Avangrid (AGR) 10-K 23 Feb 22 2021 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Feb. 22, 2022	Jun. 30, 2021
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2021
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-37660
Entity Registrant Name	Avangrid, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	14-1798693
Entity Address, Address Line One	180 Marsh Hill Road
Entity Address, City or Town	Orange,
Entity Address, State or Province	CT
Entity Address, Postal Zip Code	06477
City Area Code	207
Local Phone Number	629-1190
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	AGR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Entity Shell Company	false
Entity Public Float			$ 3,684
Entity Common Stock, Shares Outstanding		386,577,494
Documents Incorporated by Reference	Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. Designated portions of the Proxy Statement relating to the 2022 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.
Amendment Flag	false
Document Fiscal Year Focus	2021
Document Fiscal Period Focus	FY
Entity Central Index Key	0001634997

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	New York, NY
Auditor Firm ID	185

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Operating Revenues	$ 6,974	$ 6,320	$ 6,336
Operating Expenses
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Operations and maintenance	2,706	2,466	2,305
Depreciation and amortization	1,014	987	933
Taxes other than income taxes, net	640	619	591
Total Operating Expenses	6,079	5,451	5,338
Operating Income	895	869	998
Other Income and (Expense)
Other income (expense)	60	18	121
(Losses) earnings from equity method investments	7	(3)	3
Interest expense, net of capitalization	(298)	(316)	(310)
Income Before Income Tax	664	568	812
Income tax expense	21	29	169
Net Income	643	539	643
Net loss attributable to noncontrolling interests	64	42	24
Net Income Attributable to Avangrid, Inc.	$ 707	$ 581	$ 667
Earnings Per Common Share, Basic (in dollars per share)	$ 1.97	$ 1.88	$ 2.16
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.97	$ 1.88	$ 2.16
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	358,086,621	309,494,939	309,491,082
Diluted (in shares)	358,578,608	309,559,387	309,514,910

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income	$ 643	$ 539	$ 643
Other Comprehensive Income
Gain on defined benefit plans, net of income taxes of $0, $0 and $0, respectively	2	0	1
Amortization of pension cost for nonqualified plans, net of income taxes of $(1), $3 and $(1), respectively	(8)	(13)	(1)
Unrealized loss from equity method investment, net of income taxes of $(3), $0 and $0, respectively	(9)	0	0
Unrealized loss during the year on derivatives qualifying as cash flow hedges, net of income taxes of $(44), $(7) and $(9), respectively	(159)	(22)	(22)
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $(3), $2 and $3, respectively	12	19	11
Other Comprehensive Loss	(162)	(16)	(11)
Comprehensive Income	481	523	632
Net loss attributable to noncontrolling interests	64	42	24
Comprehensive Income Attributable to Avangrid, Inc.	$ 545	$ 565	$ 656

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, net of income taxes	$ 0	$ 0	$ 0
Amortization of pension cost for nonqualified plans, taxes	1	3	1
Unrealized loss from equity method investment, taxes	(3)	0	0
Unrealized loss during the year on derivatives qualifying as cash flow hedges, taxes	(44)	(7)	(9)
Reclassification to net income of losses on cash flow hedges, taxes	$ (3)	$ 2	$ 3

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 1,474	$ 1,463
Accounts receivable and unbilled revenues, net	1,269	1,187
Accounts receivable from affiliates	11	12
Derivative assets	35	18
Fuel and gas in storage	139	93
Materials and supplies	204	169
Prepayments and other current assets	245	525
Regulatory assets	400	310
Total Current Assets	3,777	3,777
Total Property, Plant and Equipment ($1,959 and $1,637 related to VIEs, respectively)	28,866	26,751
Operating lease right-of-use assets	148	153
Equity method investments	560	668
Other investments	61	68
Regulatory assets	2,247	2,572
Other Assets
Goodwill	3,119	3,119
Intangible assets	293	305
Derivative assets	59	79
Other	374	331
Total Other Assets	3,845	3,834
Total Assets	39,504	37,823
Current Liabilities
Current portion of debt	372	313
Notes payable	159	307
Notes payable to affiliate	2	0
Interest accrued	69	70
Accounts payable and accrued liabilities	1,586	1,453
Accounts payable to affiliates	61	50
Dividends payable	170	136
Taxes accrued	43	73
Operating lease liabilities	12	8
Derivative liabilities	64	17
Other current liabilities	484	368
Regulatory liabilities	307	274
Total Current Liabilities	3,329	3,069
Regulatory liabilities	3,022	3,137
Other Non-current Liabilities
Deferred income taxes	2,016	1,919
Deferred income	1,130	1,204
Pension and other postretirement	684	1,007
Operating lease liabilities	149	154
Derivative liabilities	160	79
Asset retirement obligations	253	210
Environmental remediation costs	298	292
Other	580	448
Total Other Non-current Liabilities	5,270	5,313
Non-current debt	7,922	7,478
Non-current debt to affiliate	0	3,000
Total Non-current Liabilities	16,214	18,928
Total Liabilities	19,543	21,997
Commitments and Contingencies	0	0
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,678,630 and 309,794,917 shares issued; 386,568,104 and 309,077,300 shares outstanding, respectively	3	3
Additional paid-in capital	17,679	13,665
Treasury stock	(47)	(14)
Retained earnings	1,714	1,666
Accumulated other comprehensive loss	(273)	(111)
Total Stockholders’ Equity	19,076	15,209
Noncontrolling interests	885	617
Total Equity	19,961	15,826
Total Liabilities and Equity	$ 39,504	$ 37,823

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, plant and equipment	$ 28,866	$ 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)	386,568,104	309,077,300
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 1,959	$ 1,637

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flow from Operating Activities
Net income	$ 643	$ 539	$ 643
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	1,014	987	933
Accretion expenses	12	11	12
Regulatory assets/liabilities amortization and carrying cost	(72)	(13)	64
Pension cost	52	82	91
Earnings from equity method investments	(7)	3	(3)
Distribution of earnings from equity method investments	17	19	12
Unrealized losses (gains) on marked to market derivative contracts	86	5	(76)
Gain from divestment and disposal of property	24	(10)	(135)
Deferred taxes	11	17	164
Other non-cash items	(82)	(83)	(51)
Changes in operating assets and liabilities:
Current assets	(275)	(173)	126
Noncurrent assets	(45)	(170)	(152)
Current liabilities	286	160	(2)
Noncurrent liabilities	(103)	(86)	(38)
Net Cash Provided by Operating Activities	1,561	1,288	1,588
Cash Flow from Investing Activities
Capital expenditures	(2,976)	(2,781)	(2,735)
Contributions in aid of construction	130	48	74
Proceeds from sale of equity method and other investment	0	238	108
Proceeds from sale of property, plant and equipment	24	7	18
Payments to affiliates	5	(3)	(2)
Cash distribution from equity method investments	155	3	5
Other investments and equity method investments, net	222	(370)	(176)
Net Cash Used in Investing Activities	(2,440)	(2,858)	(2,708)
Cash Flow from Financing Activities
Non-current debt issuances	833	1,367	2,137
Non-current debt issuance with affiliate	0	3,000	0
Repayments of non-current debt	(304)	(1,011)	(346)
Repayment of non-current debt with affiliate	(3,000)	0	0
Repayments of other short-term debt, net	(306)	(253)	(28)
Repayments of financing leases	(6)	(9)	(27)
Repurchase of common stock	(33)	(2)	0
Issuance of common stock	3,998	(1)	0
Distributions to noncontrolling interests	(10)	(5)	(63)
Contributions from noncontrolling interests	330	312	133
Dividends paid	(613)	(545)	(545)
Net Cash Provided by Financing Activities	889	2,853	1,261
Net Increase in Cash, Cash Equivalents and Restricted Cash	10	1,283	141
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,467	184	43
Cash, Cash Equivalents and Restricted Cash, End of Year	1,477	1,467	184
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	279	278	270
Cash paid for income taxes	$ 2	$ 8	$ 2

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Cumulative Effect, Period of Adoption, Adjustment	Total Stockholders' Equity	Total Stockholders' EquityCumulative Effect, Period of Adoption, Adjustment	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Retained EarningsCumulative Effect, Period of Adoption, Adjustment	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss)Cumulative Effect, Period of Adoption, Adjustment	Non-controlling Interests
Balance at beginning of period (in shares) at Dec. 31, 2018	[1]					309,005,272
Balance at beginning of period at Dec. 31, 2018		$ 15,389	$ (1)	$ 15,090	$ (1)	$ 3		$ 13,657	$ (12)	$ 1,514	$ 11	$ (72)	$ (12)	$ 299
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		643		667						667				(24)
Other comprehensive income, net of tax		(11)		(11)								(11)
Comprehensive Income		632
Dividends declared		(545)		(545)						(545)
Stock-based compensation		3		3				3
Distributions to noncontrolling interests		(63)		(4)						(4)				(59)
Contributions from noncontrolling interests		124		(9)						(9)				133
Balance at end of period (in shares) at Dec. 31, 2019	[1]					309,005,272
Balance at end of period at Dec. 31, 2019		15,539	$ (1)	15,190	$ (1)	$ 3		13,660	(12)	1,634	$ (1)	(95)		349
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		539		581						581				(42)
Other comprehensive income, net of tax		(16)		(16)								(16)
Comprehensive Income		523
Dividends declared		$ (545)		(545)						(545)
Release of common stock held in trust (in shares)		72,028				72,028	[1]
Issuance of common stock (in shares)	[1]					42,777
Issuance of common stock		$ (1)		(1)				(1)
Repurchase of common stock (in shares)	[1]					(42,777)
Repurchase of common stock		(2)		(2)					(2)
Stock-based compensation		6		6				6
Distributions to noncontrolling interests		(5)												(5)
Contributions from noncontrolling interests		$ 312		(3)						(3)				315
Balance at end of period (in shares) at Dec. 31, 2020		309,077,300				309,077,300	[1]
Balance at end of period at Dec. 31, 2020		$ 15,826		15,209		$ 3		13,665	(14)	1,666		(111)		617
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		643		707						707				(64)
Other comprehensive income, net of tax		(162)		(162)								(162)
Comprehensive Income		481
Dividends declared		$ (647)		(647)						(647)
Release of common stock held in trust (in shares)		301,239				301,239	[1]
Issuance 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]					(694,148)
Repurchase of common stock		(33)		(33)					(33)
Stock-based compensation		16		16				16
Distributions to noncontrolling interests		(10)												(10)
Contributions from noncontrolling interests		$ 330		(12)						(12)				342
Balance at end of period (in shares) at Dec. 31, 2021		386,568,104				386,568,104	[1]
Balance at end of period at Dec. 31, 2021		$ 19,961		$ 19,076		$ 3		$ 17,679	$ (47)	$ 1,714		$ (273)		$ 885
[1]	Par value of share amounts is $.01

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Other comprehensive income, tax	$ (51)	$ (2)	$ (7)
Dividends declared (in dollars per share)	$ 1.76	$ 1.76	$ 1.76
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01

Background and Nature of Operat

Background and Nature of Operations	12 Months Ended
	Dec. 31, 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 81.6% 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 November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, Avangrid, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals. 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 April 20, 2023, as amended (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 of a 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 81.6% ownership interest in AVANGRID.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation in all periods presented.

Summary of Significant Accounti

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates	Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates Significant Accounting Policies We consider the following policies to be the most significant in understanding the judgments that are involved in preparing our consolidated financial statements: (a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting. (b) Revenue recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Refer to Note 4 for further details. (c) Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates. (d) Business combinations and assets acquisitions (disposals) We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred. In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed. (e) Noncontrolling interests Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement. Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets. (f) Equity method investments We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary. (g) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four (h) Property, plant and equipment We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment. We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service. We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation. We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transmission and transport facilities 41-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 7-85 Computer software 3-37 Other Buildings 30-82 Operations offices 3-75 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation were 2.8% and 2.9% of average depreciable property for 2021 and 2020, respectively. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income. (i) Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on the information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes an option to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets. (j) Impairment of long-lived assets We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset. (k) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e. (l) Equity investments with readily determinable fair values We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income. (m) Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Certain derivatives hedge specific cash flows that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. Certain interest rate derivatives hedge a liability (i.e. debt) that qualify and are designated for hedge accounting are classified as fair value hedges. Changes in the fair value of interest rate derivatives designated as a fair value hedge and the offsetting changes in the fair value of the underlying hedged exposure (i.e. debt) are recorded in Interest expense. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. (n) Cash and cash equivalents Cash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows. (o) Trade receivable and unbilled revenue, net of allowance for credit losses We record trade receivables at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain trade receivables and payables related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets. Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. Due to COVID-19, the UIL companies’ regulators require them to offer to customers, through early February 2022, a 24-month repayment plan. We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. We consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts. (p) Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors. (q) Debentures, bonds and bank borrowings We record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets. (r) Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.” (s) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses. (t ) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met. (u) Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations. (v) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis. (w) Post-employment and other employee benefits We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period. (x) Income taxes We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs.

Revenue

Revenue	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Revenue	Revenue We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 24. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. 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. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all 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. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer. Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration. Other Other, which does not represent a segment, includes miscellaneous Corporate revenues including intersegment eliminations. Contract Costs, Contract Liabilities and Practical Expedient We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2022 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2021 and 2020, and are presented in "Other non-current assets" on our consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $16 million and $9 million at December 31, 2021 and 2020, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $22 million for the year ended December 31, 2021, and $21 million for both of the years ended December 31, 2020 and 2019 as revenue related to contract liabilities. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs. Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2021, 2020 and 2019 are as follows: Year Ended December 31, 2021 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,015 $ — $ — $ 4,015 Regulated operations – natural gas 1,516 — — 1,516 Nonregulated operations – wind — 1,028 — 1028 Nonregulated operations – solar — 20 — 20 Nonregulated operations – thermal — 63 — 63 Other (a) 67 84 — 151 Revenue from contracts with customers 5,598 1,195 — 6,793 Leasing revenue 7 — — 7 Derivative revenue — 3 — 3 Alternative revenue programs 115 — — 115 Other revenue 34 22 — 56 Total operating revenues $ 5,754 $ 1,220 $ — $ 6,974 Year Ended December 31, 2020 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,642 $ — $ — $ 3,642 Regulated operations – natural gas 1,311 — — 1,311 Nonregulated operations – wind — 822 — 822 Nonregulated operations – solar — 19 — 19 Nonregulated operations – thermal — 39 — 39 Other (a) 58 101 — 159 Revenue from contracts with customers 5,011 981 — 5,992 Leasing revenue 6 — — 6 Derivative revenue — 136 — 136 Alternative revenue programs 157 — — 157 Other revenue 14 15 — 29 Total operating revenues $ 5,188 $ 1,132 $ — $ 6,320 Year Ended December 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,485 $ — $ — $ 3,485 Regulated operations – natural gas 1,479 — — 1,479 Nonregulated operations – wind — 803 — 803 Nonregulated operations – solar — 26 — 26 Nonregulated operations – thermal — 29 — 29 Other (a) 91 62 (12) 141 Revenue from contracts with customers 5,055 920 (12) 5,963 Leasing revenue 6 — — 6 Derivative revenue — 244 — 244 Alternative revenue programs 75 — — 75 Other revenue 28 20 — 48 Total operating revenues $ 5,164 $ 1,184 $ (12) $ 6,336 (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 December 31, 2021 and 2020, accounts receivable balances related to contracts with customers were approximately $1,220 million and $1,151 million, respectively, including unbilled revenues of $405 million and $341 million, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets. As of December 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 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 39 24 9 2 3 2 79 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 26 18 14 12 10 65 145 Total operating revenues $ 71 $ 43 $ 24 $ 14 $ 13 $ 67 $ 232 We do not disclose information about remaining performance obligations for contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

Industry Regulation

Industry Regulation	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Industry Regulation	Industry Regulation Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts Each of Networks’ eight regulated utility companies must comply with regulatory procedures that differ in form but in all cases conform to the basic framework outlined below. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection from, and automatic adjustments for, exceptional costs incurred and efficiency incentives. The distribution rates and allowed ROEs for Networks’ regulated utilities in New York are subject to regulation by the New York Public Service Commission (NYPSC), in Maine by the Maine Public Utilities Commission (MPUC), in Connecticut by the Connecticut Public Utilities Regulatory Authority (PURA) and in Massachusetts by the Department of Public Utilities (DPU). The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to the Networks companies are approved by the regulatory commissions of the different states and are based on the cost of providing service. The revenues of each of the Networks companies are set to be sufficient to cover its operating costs, including energy costs, finance costs and the costs of equity, the last of which reflects our capital ratio and a reasonable ROE. Energy costs that are incurred in the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York and Connecticut revenues that allow a utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting in future tariff reductions. The NYSEG and RG&E rate plans, the Maine distribution rate plan and associated proceedings, the Federal Energy Regulatory Commission (FERC) Transmission Return on Equity (ROE) case, the Connecticut rate plans, Reforming Energy Vision (REV), the storm proceedings in New York and the Tax Act are some of the most important specific regulatory processes that currently affect Networks. CMP Distribution Rate Case In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7.00%, 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 was ordered to remain in effect until CMP 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 starting from September 1, 2021. The MPUC approved CMP's request for removal of the management efficiency adjustment effective as of its February 18, 2022 order. The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. We cannot predict the outcome of this investigation. NYSEG and RG&E Rate Plans 2016 Joint Proposal On June 15, 2016, the NYPSC approved NYSEG's and RG&E's 2016 Joint Proposal for a three-year rate plan for electric and gas service which balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The 2016 Joint Proposal reflected many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows: May 1, 2018 Rate Increase Delivery Rate Increase Utility (Millions) % NYSEG Electric $ 30 4.10 % NYSEG Gas $ 15 7.30 % RG&E Electric $ 26 5.70 % RG&E Gas $ 10 5.20 % The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas was 9.00%. The equity ratio for each company was 48%; however, the equity ratio was set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increased as the ROE increased, with customers receiving 50%, 75% and 90% of earnings in rate year three (May 1, 2018 – April 30, 2019) above 9.75%, 10.25% and 10.75% ROE, respectively. The rate plans also included the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates and continuation of the existing RDM for each business. The 2016 Joint Proposal reflected the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($26 million annually for NYSEG Electric and $3 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds. The 2016 Joint Proposal maintained NYSEG’s and RG&E’s current electric reliability performance measures (and associated potential negative revenue adjustments for failing to meet established performance levels) which include the system average interruption frequency index (SAIFI) and the customer average interruption duration index (CAIDI). The 2016 Joint Proposal also modified certain gas safety performance measures at the companies, including those relating to the replacement of leak prone mains, leak backlog management, emergency response and damage prevention. The proposal established threshold performance levels for designated aspects of customer service quality and continued and expanded NYSEG’s and RG&E’s bill reduction and arrears forgiveness Low Income Programs with increased funding levels. The 2016 Joint Proposal provided for the implementation of NYSEG’s Energy Smart Community (ESC) Project in the Ithaca region which serves as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project is supported by NYSEG’s planned Distribution Automation upgrades and Advanced Metering Infrastructure (AMI) implementation for customers on circuits in the Ithaca region. The companies also are pursuing Non-Wires Alternative projects as described in the proposal. Other REV-related incremental costs and fees were included in the RAM to the extent cost recovery is not provided for elsewhere. Under the proposal, the RAM was applicable to all customers and serves to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG Electric Pole Attachment revenues. RG&E implemented a RAM in July 2018 since certain eligibility thresholds were exceeded. The 2016 Joint Proposal provided for partial or full reconciliation of certain expenses including, but not limited to: pensions and other postretirement benefits; property taxes; variable rate debt and new fixed rate debt; gas research and development; environmental remediation costs; major storms; nuclear electric insurance limited credits; economic development; and low income programs. The 2016 Joint Proposal also included a downward-only Net Plant reconciliation. In addition, the 2016 Joint Proposal included downward-only reconciliations for the costs of electric distribution and gas vegetation management, pipeline integrity and incremental maintenance. The 2016 Joint Proposal provided that NYSEG and RG&E continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis. 2020 Joint Proposal On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan (2020 Joint Proposal). On November 19, 2020, the NYPSC approved the 2020 Joint Proposal, with modifications to the rate increases at the two electric businesses. The modifications were made to limit the overall bill impacts, to a level at or below 2.00% per year, in consideration of the current impacts of COVID-19 on the economic climate. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The new rates help to facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed 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 two and three commence on May 1, 2021 and 2022, respectively. Year 1 Year 2 Year 3 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 34 4.6 % $ 46 5.9 % $ 36 4.2 % NYSEG Gas $ — — % $ 2 0.8 % $ 3 1.6 % RG&E Electric $ 17 3.8 % $ 14 3.2 % $ 16 3.3 % RG&E Gas $ — — % $ — — % $ 2 1.3 % UI, CNG, SCG and BGC Rate Plans Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills. UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2022, 60% of its standard service load for the second half of 2022. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first quarter of 2022. However, from time to time, there are no bidders in the procurement process for supplier of last resort service and UI manages the load directly. In 2016, PURA approved new distribution rate schedules for UI for three years, which became effective January 1, 2017 and, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% 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 for a three-year rate plan with annual rate increases. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and approximately 52.00% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. In December 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (CNG) effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021. On January 18, 2019, the DPU approved new distribution rates for BGC. The distribution rate increase is based on an ROE 9.70% 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. BGC expects to file an application to amend its distribution rates in the first half of 2022. We cannot predict the outcome of this proceeding. REV In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide-ranging initiative to reform New York State’s energy industry and regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources (DER), such as micro grids, on-site power supplies and storage. REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this initiative involves a collaborative process to examine the role of distribution utilities in enabling market-based deployment of DER to promote load management and greater system efficiency, including peak load reductions. NYSEG is participating in the initiative with other New York utilities. The NYPSC issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016, followed by bi-annual updates. The companies filed the initial DSIP, which also included information regarding the potential deployment of Automated Metering Infrastructure (AMI) across its entire service territory. In December 2016, the companies filed a petition to the NYPSC requesting approval for cost recovery associated with the full deployment of AMI. A collaborative associated with this petition began in the first quarter of 2017, was suspended in the second quarter of 2017, subsequently resumed in the first quarter of 2018 and then further suspended and was been included in the companies’ May 20, 2019 rate filing. The companies also filed their first bi-annual update of the DSIP on July 31, 2018 and filed their next bi-annual update on June 30, 2020. Other various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include the Clean Energy Standard, Value of DER and Net Energy Metering, Demand Response Tariffs and Community Choice Aggregation. As part of the Clean Energy Standard proceeding, all electric utilities were ordered to begin payments to New York State Energy Research and Development Authority (NYSERDA) for RECs and Zero Emissions Credits beginning in 2017. Track 2 of the REV initiative is also underway, and through a NYPSC staff whitepaper review process, is examining potential changes in current regulatory, tariff, market design and incentive structures that could better align utility interests with achieving New York state and NYPSC’s policy objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in May 2016, and includes guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs and data utilization and security. The companies, in December 2016, filed a proposal for the implementation of EAMs in the areas of System Efficiency, Energy Efficiency, Interconnections and Clean Air. A collaborative process to review the companies’ petition was suspended in 2017. The approved 2020 Joint Proposal includes EAMs. In March 2017, the NYPSC issued three separate REV-related orders. These orders created a series of filing requirements for NYSEG and RG&E beginning in March 2017 and extending through the end of 2018. The three orders involve: 1) modifications to the electric utilities’ proposed interconnection EAM framework; 2) further DSIP requirements, including filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at each company by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of the Value of DER. In September 2017, the NYPSC issued another order related to the Value of DER, requiring tariff filings, changes to Standard Interconnection Requirements and planning for the implementation of automated consolidated billing. As of the end of 2018, both NYSEG and RG&E had deployed two energy storage projects each, consistent with the March 2017 NYPSC order requirements. In December 2018, the NYPSC staff submitted whitepapers on standby and buyback service rate design, future value stack compensation and capacity value compensation. The NYPSC ruled on the proposals set forth in the whitepapers on May 16, 2019. NYSEG and RG&E filed proposed standby and buyback rates with the NYPSC in September 2019. On November 25, 2020, DPS Staff, jointly with NYSERDA, issued a whitepaper on further recommendations regarding standby and buyback rates that were based on the electric utilities’ September 23, 2019 filings. Comments on the recommendations in the whitepaper are due February 22, 2021, and reply comments are due March 8, 2021. A final Commission Order is expected in 2022. On April 18, 2019, the NYPSC issued an order on future value stack compensation and capacity value compensation. The order established a new Community Credit in place of the Market Transition Credit for certain CDG projects in NYSEG’s and RGE’s territories and expanded eligibility for Phase One Net Metering for projects that have a rated capacity of 750 kW AC or lower. The changes became effective on June 1, 2019. The NYPSC also issued an order on value stack compensation for high-capacity-factor Resources on December 12, 2019, modifying the treatment of certain high-capacity-factor DER in the Value Stack compensation framework. The modification per the December 12, 2019 Order became effective February 1, 2020. On March 19, 2020, the Commission issued an additional Order regarding Value Stack Compensation. The Order directs National Grid, NYSEG and RGE to reallocate capacity from closed tranches where available capacity remained due to projects being canceled since the issuance of the VDER Compensation Order, and to assign that capacity to a new Community Credit Tranche with compensation at 2 cents per kWh. The utilities must also continue to reallocate capacity to this new Tranche for the next six months when there are cancellations of projects that have received a Market Transition Credit (MTC) or Community Credit allocation. The new provisions per the March 19, 2020 Order became effective May 1, 2020. On May 14, 2020, the Commission issued an Order extending and expanding distributed solar incentives. In addition to authorizing the extension of and additional funding for the NY-Sun program, the Commission modified certain program rules related to the NY-Sun program and the VDER policy. As part of the ordered modifications, the Commission directed the electric utilities with VDER tariffs to add tariff language for a Remote Crediting program that will allow Value-Stack-eligible generation resources to distribute the credits they receive for generation injected into the utility system to the utility bills of multiple, separately sited, non-residential customers. The Commission ordered the utilities to submit tariff leaves that implement the modifications associated with the Remote Crediting program to become effective November 1, 2020. Given the complexity of the program changes, the utilities have petitioned the Commission for an extension. Tariffs were filed on August 16, 2021, becoming effective on September 1, 2021. On July 16, 2020, the Commission issued an Order establishing a net metering successor tariff. The Order continues Phase One NEM for all eligible mass market and commercial projects under 750 kW interconnected after January 1, 2022 and implements a modest customer benefit contribution (CBC) for onsite DERs to address cost recovery of certain public benefit programs. Customers that install DERs interconnected after January 1, 2022 shall be charged a monthly per kW fee based on the nameplate rating of the DER. Draft tariff leaves implementing the Commission’s Order and proposed CBC calculations were filed on November 1, 2020. A final Commission Order was issued on August 13, 2021, implementing the CBC effective January 1, 2022 for new mass market net metering customers. On April 24, 2018, the NYPSC instituted a proceeding to consider the role of utilities in providing infrastructure and rate design to encourage the expansion electric vehicles and electric vehicle supply equipment. The Commission issued an Order on February 2, 2019 to establish a Direct Current Fast Charger incentive program, with subsequent clarifications provided in Orders issued on July 12, 2019 and March 3, 2020. On July 16, 2020, the NYPSC issued an Order approving a $700 million statewide program (NYSEG and RG&E combined share is approximately $118 million). The make-ready program will be funded by investor-owned utilities in New York State and creates a cost-sharing program that incentivizes utilities and charging station developers to site electric vehicle charging infrastructure in places that will provide a maximal benefit to consumers. CMP Customer Billing System Investigation On March 1, 2018, the MPUC issued a Notice of Investigation initiating a summary investigation into CMP’s metering, billing and customer communications practices. Due to the highly technical nature of CMP’s customer billing system the MPUC ordered a forensic audit of CMP’s customer billing system to identify any errors that have, or continue to result in billing inaccuracies, and to review CMP’s customer communication practices. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 9, 2020, the hearing examiners issued their report whereby they recommended that the Commission find that the evidence in the record shows that there is no systemic problem within CMP’s metering and billing systems that has caused erroneous high usage on customers’ bills. Instead, the evidence-including the detailed forensic audit conducted by an independent third-party auditor-demonstrates that CMP’s metering and billing systems have been, and continue to be, recording and transmitting customer usage data accurately, and, with the exception of discrete billing calculation and presentation issues, customers’ billed amounts have been accurate. On January 30, 2020, the MPUC Commissioners deliberated and based on the verbal discussion, the Commissioners indicated that CMP’s Metering and Billing system is accurately reporting data; there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The Commissioners were critical of CMP finding that CMP failed to implement proper testing of the SmartCare system prior to go-live; CMP’s implementation of SmartCare was imprudent; CMP’s SmartCare implementation experienced an unacceptable number of billing errors, delayed or estimated bills, bill presentment issues and unreasonable time required to address these issues; and the implementation issues were compounded by inadequate staffing, resulting in the inability of customers to contact a CMP representative. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above the MPUC imposed a reduction of 100 basis points in ROE, as a management efficiency adjustment, to address concerns with CMP’s customer service performance following the implementation of its new billing system in 2017 and on February 24, 2020 issued an order in the metering and billing investigation. Each order reflected the MPUC’s conclusion that CMP’s Metering and Billing system is accurately reporting data, there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The management efficiency adjustment was ordered to remain in effect until CMP 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 starting from September 1, 2021. The MPUC approved CMP's request for removal of the management efficiency adjustment as of its February 18, 2022 order. Tax Cuts and Jobs Act On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Tax Act) was signed into law. The Tax Act significantly changed the federal taxation of business entities including, among other things, implementing a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, to review and address the implications of the Tax Act on the utilities. In New York, the NYPSC issued an order requiring sur-credits to return benefits reflecting the lower effective tax rate of 21% to customers effective October 1, 2018. For NYSEG Gas, RG&E Electric and RG&E Gas the NYPSC also required the sur-credit to include the return to customers of the January - September 2018 Tax Act savings over three years. The remaining deferred amounts associated with the recognition of the effects of the Tax Act are being used as rate moderators in the approved 2020 Joint Proposal. In Connecticut, with regard to UI, the PURA approved a multi-docket settlement proposal on June 28, 2021, which required UI to flow accumulated Tax Act savings back to customers over a 22-month period, commencing on July 1, 2021 through April 30, 2023. With regard to SCG, we expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case, unless PURA determines otherwise. CNG and BGC include Tax Act savings in their current rate plans. In Maine, CMP adjusted rates beginning July 1, 2018 to pass back to customers the Tax Act savings after offsetting for recovery of deferred 2017 storm costs. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above, the MPUC approved CMP’s distribution related accumulated deferred income tax balances associated with the Tax Act as well as the authorized amortization periods for the return of regulatory liabilities and the recovery regulatory assets. At the FERC, CMP transmission and UI transmission adjusted their tariffs in June 2018 to reflect the income statement value of Tax Act savings. On December 22, 2021, the FERC issued an order finding that the New England Transmission Owners (NETOs) Regional Network Service proposed revisions partially comply with the requirements of Order 864 and directed the NETOs to submit a further compliance filing within 60 days of the date of the order. The compliance is effective January 27, 2020, consistent with Order 864 and January 1, 2022, to reflect the fact that the NETOs existing transmission formula rates under the ISO-NE Tariff will be replaced by a settled formula rate effective January 1, 2022. Power Tax Audits Previously, CMP, NYSEG and RG&E implemented Power Tax software to track and measure their respective deferred tax amounts. In connection with this change, we identified historical updates needed with deferred taxes recognized by CMP, NYSEG and RG&E and increased our deferred tax liabilities, with a corresponding increase to regulatory assets, to reflect the updated amounts calculated by the Power Tax software. Since 2015, the NYPSC and MPUC accepted certain adjustments to deferred taxes and associated regulatory assets for this item in recent distribution rate cases, resulting in regulatory asset balances of approximately $142 million and $148 million, respectively for this item at December 31, 2021 and 2020. In 2017, audits of the power tax regulatory assets were commenced by the NYPSC and MPUC. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax accounting. The NYPSC audit report is expected to be completed during 2022. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which indicated the auditor was unable to verify the asset “acquisition value” used to calculate the Power Tax regulatory asset. The audit report requires that CMP must provide support for the beginning balance of the regulatory assets or it will be unable

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize as regulatory assets incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,136 million. The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. Regulatory assets as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Pension and other post-retirement benefits $ 545 $ 927 Pension and other post-retirement benefits cost deferrals 95 105 Storm costs 448 451 Rate adjustment mechanism 68 33 Revenue decoupling mechanism 68 58 Transmission revenue reconciliation mechanism 15 31 Contracts for differences 73 86 Hardship programs 24 20 Plant decommissioning 2 3 Deferred purchased gas 52 30 Deferred transmission expense 13 26 Environmental remediation costs 256 247 Debt premium 71 83 Unamortized losses on reacquired debt 23 26 Unfunded future income taxes 424 373 Federal tax depreciation normalization adjustment 142 148 Asset retirement obligation 20 21 Deferred meter replacement costs 46 33 COVID-19 cost recovery 21 1 Other 241 180 Total regulatory assets 2,647 2,882 Less: current portion 400 310 Total non-current regulatory assets $ 2,247 $ 2,572 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases. “Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period. "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. “Plant decommissioning” represents decommissioning and demolition expenses related to closing fossil plant facilities - Beebe & Russell. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of forty-six years and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020. “Asset retirement obligations” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by AMI meters. This amount is being amortized over the initial depreciation period of related retired meters. "COVID-19 cost recovery" represents deferred COVID-19-related costs in the state of Connecticut based on the order issued by PURA on April 29, 2020, requiring utilities to track COVID-19-related expenses and lost revenue and create a regulatory asset. “Other” includes post-term amortization deferrals and various items subject to reconciliation including hedge losses and deferred property tax. Regulatory liabilities as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Energy efficiency portfolio standard $ 45 $ 58 Gas supply charge and deferred natural gas cost 7 3 Pension and other post-retirement benefits cost deferrals 73 59 Carrying costs on deferred income tax bonus depreciation 23 34 Carrying costs on deferred income tax - Mixed Services 263(a) 7 11 2017 Tax Act 1,327 1,435 Rate change levelization 99 55 Revenue decoupling mechanism 13 9 Accrued removal obligations 1,192 1,184 Asset sale gain account 2 7 Economic development 26 28 Positive benefit adjustment 22 30 Theoretical reserve flow thru impact 6 10 Deferred property tax 22 31 Net plant reconciliation 16 20 Debt rate reconciliation 49 63 Rate refund – FERC ROE proceeding 35 33 Transmission congestion contracts 23 22 Merger-related rate credits 12 14 Accumulated deferred investment tax credits 24 25 Asset retirement obligation 18 18 Earnings sharing provisions 13 17 Middletown/Norwalk local transmission network service collections 17 18 Low income programs 25 28 Non-firm margin sharing credits 15 14 New York 2018 winter storm settlement 5 9 Hedges gains 19 — Other 194 176 Total regulatory liabilities 3,329 3,411 Less: current portion 307 274 Total non-current regulatory liabilities $ 3,022 $ 3,137 “Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. "Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/ returned to customers beginning the next calendar year. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. "Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. “2017 Tax Act” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, to review and address the implications associated with the Tax Act on the utilities providing service in such states. "Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. "Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the net gain on the sale of certain assets that will be used for the future benefit of customers. The amortization period in current rates is three years for NYSEG and two years for RG&E and began in 2020. “Economic development” represents the economic development program, which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three "Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates . A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. "Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. "Debt rate reconciliation" represents the over/under collection of costs related to debt instruments identified in the rate case. Costs would include interest, commissions and fees versus amounts included in rates. "Rate refund - FERC ROE proceeding" represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 14 for more details. "Transmission congestion contracts" represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RGE. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In both of the years ended December 31, 2021 and 2020, $2 million of rate credits were applied against customer bills. “Accumulated deferred investment tax credits” represents investment tax credits related to plant investments that are deferred when earned and amortized over the estimated lives of the related assets. “Asset retirement obligation” represents fair value of the liability for an asset retirement the company is legally committed to removing (PCB transformers, bare steel). "Earning sharing provisions" represents the annual earnings over the earning sharing threshold. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. "Middletown/Norwalk local transmission network service collections" represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project. “Low income programs” represent various hardship and payment plan programs approved for recovery. “Non-firm margin sharing credits” represents the portion of interruptible and off-system sales revenue set aside to fund gas expansion projects. "New York 2018 winter storm settlement" represents the settlement amount with the NYSPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. This balance is being amortized through current rates over an amortization period of three years, beginning in 2020. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation.

Goodwill and Intangible assets

Goodwill and Intangible assets	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible assets	Goodwill and Intangible assets Goodwill by reportable segment as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 372 Total $ 3,119 $ 3,119 During 2021, there were no changes in gross amounts and accumulated losses of goodwill for the Networks and Renewables reportable segments. Goodwill Impairment Assessment For impairment testing purposes, our reporting units are the same as operating segments, except for Networks, which contains three reporting units, Maine, New York and UIL. Goodwill for the Maine reporting unit is $325 million from the purchase of CMP by Energy East Corporation in 2000. Goodwill for the New York reporting unit is $654 million primarily from the purchase of RG&E by Energy East in 2002. Goodwill for the UIL reporting unit is $1,768 million from the 2015 acquisition of UIL. We perform our annual impairment testing in the fourth quarter, as of October 1. Our qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events and events affecting a reporting unit. Our quantitative assessment utilizes a discounted cash flow model under the income approach and includes critical assumptions, primarily the discount rate and internal estimates of forecasted cash flows. We use a discount rate that is developed using market participant assumptions, which consider the risk and nature of the respective reporting unit’s cash flows and the rates of return market participants would require in order to invest their capital in our reporting units. We test the reasonableness of the conclusions of our quantitative impairment testing using a range of discount rates and a range of assumptions for long-term cash flows. For 2021, we utilized a qualitative assessment for the Networks reporting units and a quantitative assessment for the Renewables reporting unit. For 2020, we utilized a quantitative assessment for the Networks and Renewables reporting units. We had no impairment of goodwill in 2021 and 2020 as a result of our impairment testing. Intangible assets Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2021 and 2020: As of December 31, 2021 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 592 $ (301) $ 291 Other 18 (16) 2 Total Intangible Assets $ 610 $ (317) $ 293 As of December 31, 2020 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 593 $ (290) $ 303 Other 31 (29) 2 Total Intangible Assets $ 624 $ (319) $ 305 Wind development costs, with the exception of future ‘pipeline’ development costs, are amortized on a straight-line basis in accordance with the life of the related assets once placed in service. Amortization expense was $13 million, $14 million and $15 million for the years ended December 31, 2021, 2020 and 2019, respectively. We believe our future cash flows will support the recoverability of our intangible assets. We expect amortization expense for the five years subsequent to December 31, 2021, to be as follows: Year ending December 31, Amount (Millions) 2022 $ 14 2023 $ 13 2024 $ 13 2025 $ 12 2026 $ 12

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment as of December 31, 2021, consisted of: As of December 31, 2021 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 17,392 $ 13,446 $ 30,838 Natural gas transportation, distribution and other 5,032 13 5,045 Other common operating property — 286 286 Total Property, Plant and Equipment in Service 22,424 13,745 36,169 Total accumulated depreciation (5,806) (4,783) (10,589) Total Net Property, Plant and Equipment in Service 16,618 8,962 25,580 Construction work in progress 2,064 1,222 3,286 Total Property, Plant and Equipment $ 18,682 $ 10,184 $ 28,866 Property, plant and equipment as of December 31, 2020, consisted of: As of December 31, 2020 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 16,364 $ 12,854 $ 29,218 Natural gas transportation, distribution and other 4,637 13 4,650 Other common operating property — 274 274 Total Property, Plant and Equipment in Service 21,001 13,141 34,142 Total accumulated depreciation (5,363) (4,436) (9,799) Total Net Property, Plant and Equipment in Service 15,638 8,705 24,343 Construction work in progress 1,384 1,024 2,408 Total Property, Plant and Equipment $ 17,022 $ 9,729 $ 26,751 Capitalized interest costs were $33 million, $51 million and $51 million for the years ended December 31, 2021, 2020 and 2019, respectively. Accrued liabilities for property, plant and equipment additions were $297 million, $285 million and $357 million as of December 31, 2021, 2020 and 2019, respectively. We impaired or wrote off amounts of $20 million, $7 million and $11 million for the years ended December 31, 2021, 2020 and 2019, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction. Depreciation expense for the years ended December 31, 2021, 2020 and 2019, amounted to $1,001 million, $973 million and $918 million, respectively.

Asset retirement obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2021
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligations	Asset retirement obligations AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities. The reconciliation of ARO carrying amounts for the years ended December 31, 2021 and 2020 consisted of: (Millions) As of December 31, 2019 $ 190 Liabilities settled during the year (2) Liabilities incurred during the year 9 Accretion expense 11 Revisions in estimated cash flows (a) 2 As of December 31, 2020 $ 210 Liabilities settled during the year (2) Liabilities incurred during the year 7 Accretion expense 12 Revisions in estimated cash flows (a) 26 As of December 31, 2021 $ 253 (a) Represents an increase in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities. Several of the wind generation facilities have restricted cash for purposes of settling AROs. As of both December 31, 2021 and 2020, restricted cash related to AROs was $3 million. These amounts have been included in “Other Assets” on our consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in our consolidated statements of income. We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for

Debt

Debt	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Debt	Debt Long-term debt as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2022-2051 $ 2,759 1.85%-8.00% $ 2,575 1.85%-8.00% Unsecured pollution control notes - fixed 2023-2029 478 1.40%-3.50% 478 1.40%-3.50% Other various non-current debt - fixed 2022-2050 5,110 1.95%-6.66% 4,785 1.95%-7.80% Unamortized debt issuance costs and discount (53) (47) Total Debt 8,294 7,791 Less: debt due within one year, included in current liabilities 372 313 Total Non-current Debt $ 7,922 $ 7,478 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $7,871 million. Iberdrola Loan On December 14, 2020, AVANGRID and Iberdrola entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid with the proceeds of the common share issuance described in Note 1. Other 2021 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity NYSEG 9/24/2021 Unsecured Notes $ 350 2.15 % 2031 RG&E 12/15/2021 First Mortgage Bonds $ 125 2.91 % 2051 RG&E 12/15/2021 First Mortgage Bonds $ 125 2.10 % 2031 CMP 12/15/2021 First Mortgage Bonds $ 200 2.05 % 2031 SCG 12/15/2021 First Mortgage Bonds $ 40 2.05 % 2031 Long-term debt maturities, including sinking fund obligations, due over the next five years consist of: 2022 2023 2024 2025 2026 Total (Millions) $ 372 $ 439 $ 612 $ 1,107 $ 660 $ 3,190 We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were in breach of covenants or of any obligation that could trigger the early redemption of our debt as of both December 31, 2021 and 2020 and throughout 2021 and 2020. Fair Value of Debt As of December 31, 2021 and 2020, the estimated fair value of long-term debt, including the Iberdrola Loan as of December 31, 2020, was $9,155 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 rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy. Short-term Debt AVANGRID had $159 million and $307 million of notes payable as of December 31, 2021 and 2020, respectively. AVANGRID has a commercial paper program with a limit of $2 billion which is backstopped by the AVANGRID credit facilities described below. As of December 31, 2021 and 2020, the amount of notes payable under the commercial paper program was $0 and $309 million, respectively, presented net of discounts on the balance sheet. As of December 31, 2020, the weighted-average interest rate on outstanding commercial paper was 0.32%. AVANGRID Credit Facility AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC, each of which are joint borrowers, have a revolving credit facility with a syndicate of banks, or the AVANGRID Credit Facility, that provides for maximum borrowings of up to $3,575 million in the aggregate, which was executed on November 23, 2021. The agreement contains a commitment from lenders, which will expire on April 20, 2022 if not terminated by AVANGRID at an earlier date to increase maximum borrowings to $4,000 million upon the joinder of PNM and TNMP as borrowers under the AVANGRID Credit Facility. Under the terms of the AVANGRID Credit Facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit contained in the agreement. On November 23, 2021, the executed AVANGRID Credit Facility increased AVANGRID's maximum sublimit from $1,500 million to $2,500 million. The AVANGRID Credit Facility contains pricing that is sensitive to AVANGRID’s consolidated greenhouse gas emissions intensity. The Credit Facility also contains negative covenants, including one that sets the ratio of maximum allowed consolidated debt to consolidated total capitalization at 0.65 to 1.00, for each borrower. Under the AVANGRID Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. The initial facility fees will range from 10 to 22.5 basis points. The maturity date for the AVANGRID Credit Facility is November 22, 2026. As of December 31, 2021, we had no borrowings outstanding under this credit facility. Since the AVANGRID Credit Facility is also a backstop to the AVANGRID commercial paper program, the total amount available under the facility as of December 31, 2021 was $3,575 million. 2020 Credit Facility During 2020, we entered into a revolving credit agreement with several lenders, or the 2020 Credit Facility, that provides maximum borrowings up to $500 million. We terminated this facility on April 28, 2021. Iberdrola Group Credit Facility AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both December 31, 2021 and 2020, there was no outstanding amount under this credit facility. Supplier Financing Arrangements We operate a supplier financing arrangement. 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 consolidated balance sheets. The balance relates to capital expenditures and, therefore, is treated as non-cash activity. As of December 31, 2021 and 2020, the amount of notes payable under supplier financing arrangements was $161 million and $0, respectively. As of December 31, 2021, the weighted average interest rate on the balance was 0.82%.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and non-current equity investments associated with Networks’ activities utilizing market approach valuation techniques: • Our equity and other investments consist of Rabbi Trusts for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities, fixed income and money market funds. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2. • NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1. • NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the Intercontinental Exchange (ICE). 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 12 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as New York Mercantile Exchange (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 12 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 $3 million and $4 million as of December 31, 2021 and 2020, respectively and is included in “Other Assets” on our consolidated balance sheets. The financial instruments measured at fair value as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 45 $ 15 $ — $ — $ 60 Derivative assets Derivative financial instruments - power $ 31 $ 39 $ 85 $ (78) $ 77 Derivative financial instruments - gas 4 34 9 (32) 15 Contracts for differences — — 2 — 2 Derivative financial instruments – Other — — — — — Total $ 35 $ 73 $ 96 $ (110) $ 94 Derivative liabilities Derivative financial instruments - power $ (16) $ (137) $ (90) $ 176 $ (67) Derivative financial instruments - gas (1) (22) — 18 (5) Contracts for differences — — (75) — (75) Derivative financial instruments – Other — (77) — — (77) Total $ (17) $ (236) $ (165) $ 194 $ (224) As of December 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 49 $ 14 $ — $ — $ 63 Derivative assets Derivative financial instruments - power $ 5 $ 31 $ 105 $ (54) $ 87 Derivative financial instruments - gas — 24 19 (35) 8 Contracts for differences — — 2 — 2 Total $ 5 $ 55 $ 126 $ (89) $ 97 Derivative liabilities Derivative financial instruments - power $ (23) $ (31) $ (23) $ 72 $ (5) Derivative financial instruments - gas (1) (9) (2) 9 (3) Contracts for differences — — (88) — (88) Derivative financial instruments – Other — — — — — Total $ (24) $ (40) $ (113) $ 81 $ (96) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2021, 2020 and 2019 consisted of: (Millions) 2021 2020 2019 Fair value as of January 1, $ 13 $ 25 $ (15) Gains for the year recognized in operating revenues 21 8 53 Losses for the year recognized in operating revenues (34) (2) (2) Total gains or losses for the period recognized in operating revenues (13) 6 51 Gains recognized in OCI 2 1 2 Losses recognized in OCI (52) (3) (3) Total gains or losses recognized in OCI (50) (2) (1) Net change recognized in regulatory assets and liabilities 13 6 5 Purchases (17) (2) (22) Settlements (13) (15) 4 Transfers out of Level 3 (a) (2) (5) 3 Fair value as of December 31, $ (69) $ 13 $ 25 Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ (13) $ 6 $ 51 (a) Transfers out of Level 3 were the result of increased observability of market data. Level 3 Fair Value Measurement The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2021. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 3.18 $ 6.52 $ 2.27 AECO ($/MMBtu) $ 2.41 $ 5.69 $ 1.53 Ameren ($/MWh) $ 32.23 $ 93.59 $ 18.01 COB ($/MWh) $ 46.83 $ 231.90 $ 9.15 ComEd ($/MWh) $ 29.60 $ 86.32 $ 14.98 ERCOT N hub ($/MWh) $ 35.05 $ 140.00 $ 13.66 ERCOT S hub ($/MWh) $ 34.24 $ 140.00 $ 13.88 Indiana hub ($/MWh) $ 34.20 $ 93.81 $ 20.74 Mid C ($/MWh) $ 43.53 $ 229.90 $ 5.15 Minn hub ($/MWh) $ 28.82 $ 90.99 $ 15.23 NoIL hub ($/MWh) $ 29.35 $ 84.00 $ 14.64 PJM W hub ($/MWh) $ 33.49 $ 113.93 $ 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 the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of 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 12 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input December 31, 2021 Risk of non-performance 0.39% - 0.51% Discount rate 0.97% - 1.26% Forward pricing ($ per KW-month) $2.00 - $4.80

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 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 consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities The tables below present Networks' derivative positions as of December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 29 $ 7 $ 12 $ 4 Derivative liabilities (12) (4) (27) (64) 17 3 (15) (60) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1) — — — (1) — Total derivatives before offset of cash collateral 17 3 (16) (60) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 17 $ 3 $ (16) $ (60) 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 December 31, 2021 and 2020, respectively, consisted of: As of December 31, 2021 2020 (Millions) Wholesale electricity purchase contracts (MWh) 5.7 5.6 Natural gas purchase contracts (Dth) 9.4 9.5 Fleet fuel purchase contracts (Gallons) 2.0 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 December 31, 2021 and 2020 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2021, 2020 and 2019 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2021 Electricity Natural Gas 2021 Electricity Natural Gas Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (23) $ (11) Regulatory liabilities $ (16) $ (3) December 31, 2020 2020 Regulatory assets $ 17 $ 1 Purchased power, natural gas and fuel used $ 55 $ 4 Regulatory liabilities $ — $ — 2019 Purchased power, natural gas and fuel used $ 25 $ 1 Pursuant to a PURA order, UI and Connecticut’s other electric utility, CL&P, each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of December 31, 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 $73 million, a gross derivative liability of $75 million ($72 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 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 $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 years ended December 31, 2021, 2020 and 2019, respectively, were as follows: Years Ended December 31, 2021 2020 2019 (Millions) Derivative Assets $ — $ — $ (3) Derivative Liabilities $ 13 $ 6 $ 8 Certain foreign currency exchange contracts are not designated as hedging instruments. For the years ended December 31, 2021 and 2020, we recorded a gain of $0 and $4 million, respectively, related to our foreign currency contracts not designated as hedging instruments, included in "Other income" in our consolidated statements of income. No amounts were recorded for the year ended December 31, 2019. Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 4 $ 298 Commodity contracts 2 Purchased power, natural gas and fuel used (1) 1,719 Foreign currency exchange contracts (5) — Total $ (3) $ 3 2020 Interest rate contracts $ — Interest expense $ 4 $ 316 Commodity contracts (1) Purchased power, natural gas and fuel used 1 1,379 Foreign currency exchange contracts 1 — Total $ — $ 5 2019 Interest rate contracts $ — Interest expense $ 6 $ 310 Commodity contracts — Purchased power, natural gas and fuel used 1 1,509 Foreign currency exchange contracts (1) — Total $ (1) $ 7 (a) Changes in accumulated OCI are reported on a pre-tax basis. On June 20, 2019, Networks entered into a forward contract to hedge the foreign currency exchange risk of approximately $100 million in forecasted capital expenditures through June 2023. The forward foreign currency contracts, which were designated and qualified as cash flow hedges, were settled in December 2021. The net loss of $5 million in accumulated OCI on the foreign exchange derivative will be reclassified into earnings over the useful life of the underlying capital expenditures. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $47 million and $51 million as of December 31, 2021 and 2020, respectively. We recorded $4 million, $4 million and $6 million in net derivative losses related to discontinued cash flow hedges during the years ended December 31, 2021, 2020 and 2019, respectively. We will amortize approximately $4 million of discontinued cash flow hedges in 2022. Unrealized losses of $1 million on hedge derivatives are reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2021. We expect that immaterial amounts of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months. (b) Renewables activities 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 December 31, 2021 and 2020, respectively, consisted of: As of December 31, 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 20 24 Financial power contracts 9 12 Basis swaps - purchases 30 35 Basis swaps - sales — 2 The fair values of derivative contracts associated with Renewables' activities as of December 31, 2021 and 2020, respectively, consisted of: As of December 31, 2021 2020 (Millions) Wholesale electricity purchase contracts $ 36 $ 4 Wholesale electricity sales contracts (77) 11 Natural gas and other fuel purchase contracts 6 — Financial power contracts 35 66 Basis swaps - purchases — 7 Total $ — $ 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 22, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of December 31, 2021, the fair value of the interest rate swap was a $58 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 December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 29 $ 70 $ 52 $ 9 Derivative liabilities (11) (14) (65) (11) 18 56 (13) (2) Designated as hedging instruments Derivative assets — — 5 6 Derivative liabilities — — (67) (142) — — (62) (136) Total derivatives before offset of cash collateral 18 56 (75) (138) Cash collateral payable — — 27 57 Total derivatives as presented in the balance sheet $ 18 $ 56 $ (48) $ (81) 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) receivable (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 years ended December 31, 2021, 2020 and 2019 consisted of: Year Ended December 31, 2021 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ (1) Wholesale electricity sales contracts (2) (33) Financial power contracts 4 (42) Financial and natural gas contracts (1) (25) Total loss included in operating revenues $ 2 $ (101) $ 6,974 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 32 Financial and natural gas contracts — 12 Total gain included in purchased power, natural gas and fuel used $ — $ 44 $ 1,719 Total Gain (Loss) $ 2 $ (57) Year Ended December 31, 2020 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts (1) 6 Financial power contracts 2 — Financial and natural gas contracts — (13) Total (loss) gain included in operating revenues $ — $ (7) $ 6,320 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (4) Financial and natural gas contracts — 6 Total gain included in purchased power, natural gas and fuel used $ — $ 2 $ 1,379 Total Loss $ — $ (5) Year Ended December 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts 3 40 Financial power contracts (3) 23 Financial and natural gas contracts (1) 1 Total (loss) gain included in operating revenues $ (2) $ 64 $ 6,336 Purchased power, natural gas and fuel used Financial power contracts — (1) Financial and natural gas contracts — 15 Total gain included in purchased power, natural gas and fuel used $ — $ 14 $ 1,509 Total (Loss) Gain $ (2) $ 78 During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the year ended December 31, 2019. Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ (58) Interest Expense $ — $ 298 Commodity contracts $ (142) Operating revenues $ (3) $ 6,974 Total $ (200) $ (3) 2020 Commodity contracts $ 1 Operating revenues $ 6 $ 6,320 2019 Commodity contracts $ (5) Operating revenues $ 3 $ 6,336 (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 $59 million of gain included in accumulated OCI at December 31, 2021 is expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2021, 2020 and 2019. (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. The net loss in accumulated OCI related to previously settled interest rate contracts is $48 million and $57 million as of December 31, 2021 and 2020, respectively. We amortized into income $9 million, $8 million and $2 million of the loss related to the settled interest rate contracts for the years ended December 31, 2021, 2020 and 2019, respectively. We will amortize approximately $9 million of the net loss on the interest rate contracts during 2022. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 9 $ 298 2020 Interest rate contracts $ (27) Interest expense $ 8 $ 316 2019 Interest rate contracts $ (24) Interest expense $ 2 $ 310 (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 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 consolidated financial statements as of and for the year ended December 31, 2021 are as follows: (millions) Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement As of December 31, 2021 Year Ended December 31, 2021 Current Assets $ — Interest Expense $ (3) $ 298 Non-current liabilities $ (19) Cumulative effect on hedged debt Current debt $ — Non-current debt $ 19 (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 December 31, 2021, UI would have had to post an aggregate of approximately $19 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $67 million and $18 million as of December 31, 2021 and 2020, respectively. Derivative instruments settlements and collateral payments are included throughout the "Changes in operating assets and liabilities" section of operating activities in the consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of December 31, 2021 is $0, for which we have posted collateral.

Leases

Leases	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Leases	LeasesWe have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 62 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows: For the Year Ended December 31, 2021 2020 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 8 $ 17 $ 12 Interest on lease liabilities 3 4 3 Total finance lease cost 11 21 15 Operating lease cost 14 16 18 Short-term lease cost 4 3 5 Variable lease cost 4 — 2 Sublease income — — — Total lease cost $ 33 $ 40 $ 40 Balance sheet and other information as of December 31, 2021 and 2020 was as follows: As of December 31, 2021 2020 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 148 $ 153 Operating lease liabilities, current 12 8 Operating lease liabilities, long-term 149 154 Total operating lease liabilities $ 161 $ 162 Finance Leases Other assets $ 156 $ 162 Other current liabilities 4 8 Other non-current liabilities 91 91 Total finance lease liabilities $ 95 $ 99 Weighted-average Remaining Lease Term (years) Finance leases 7.3 8.12 Operating leases 20.5 21.38 Weighted-average Discount Rate Finance leases 3.49 % 3.71 % Operating leases 3.06 % 3.21 % For the years ended December 31, 2021, 2020 and 2019 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2021 2020 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16 $ 13 $ 13 Operating cash flows from finance leases $ 3 $ 3 $ 3 Financing cash flows from finance leases $ 6 $ 9 $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — $ 46 $ 1 Operating leases $ 10 $ 94 $ 3 As of December 31, 2021, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2022 $ 5 $ 14 2023 53 14 2024 23 12 2025 2 11 2026 2 11 Thereafter 19 160 Total lease payments 104 223 Less: imputed interest (9) (62) Total $ 95 161 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $45 million and $47 million at December 31, 2021 and December 31, 2020, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.
Leases	LeasesWe have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 62 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows: For the Year Ended December 31, 2021 2020 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 8 $ 17 $ 12 Interest on lease liabilities 3 4 3 Total finance lease cost 11 21 15 Operating lease cost 14 16 18 Short-term lease cost 4 3 5 Variable lease cost 4 — 2 Sublease income — — — Total lease cost $ 33 $ 40 $ 40 Balance sheet and other information as of December 31, 2021 and 2020 was as follows: As of December 31, 2021 2020 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 148 $ 153 Operating lease liabilities, current 12 8 Operating lease liabilities, long-term 149 154 Total operating lease liabilities $ 161 $ 162 Finance Leases Other assets $ 156 $ 162 Other current liabilities 4 8 Other non-current liabilities 91 91 Total finance lease liabilities $ 95 $ 99 Weighted-average Remaining Lease Term (years) Finance leases 7.3 8.12 Operating leases 20.5 21.38 Weighted-average Discount Rate Finance leases 3.49 % 3.71 % Operating leases 3.06 % 3.21 % For the years ended December 31, 2021, 2020 and 2019 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2021 2020 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16 $ 13 $ 13 Operating cash flows from finance leases $ 3 $ 3 $ 3 Financing cash flows from finance leases $ 6 $ 9 $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — $ 46 $ 1 Operating leases $ 10 $ 94 $ 3 As of December 31, 2021, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2022 $ 5 $ 14 2023 53 14 2024 23 12 2025 2 11 2026 2 11 Thereafter 19 160 Total lease payments 104 223 Less: imputed interest (9) (62) Total $ 95 161 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $45 million and $47 million at December 31, 2021 and December 31, 2020, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is 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 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 December 31, 2021, which has not changed since December 31, 2020, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million, which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019. On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing of this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. 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 and reply comments 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 PPA entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the PPA were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014, the FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC trial staff recommended that the complaint against Renewables be dismissed. A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables PPAs unjust and unreasonable. However, the proposed ruling did conclude that the price of the PPAs imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. 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 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 filed the final compliance statement with the NYPSC on January 12, 2022. 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. On December 8, 2021, the plaintiffs filed an omnibus opposition to the motions to dismiss and the defendants' filed a reply to such motion on January 14, 2022. Oral arguments are scheduled March 17, 2022. We cannot predict the outcome of this matter. Power, Gas and Other Arrangements Power and Gas Supply Arrangements – Networks NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and the New York Power Authority, are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation. NYSEG, RG&E, SCG, CNG and BGC (collectively, the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review. The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the U.S. Gulf of Mexico region, in the Appalachia region and in Canada. The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months. Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system. Other arrangements include contractual obligations for property, plant and equipment, material and services on order but not yet delivered at December 31, 2021. Power, Gas and Other Arrangements – Renewables Gas purchase commitments consist of firm transport capacity to fuel the Klamath Cogen and Peaking gas generators. Power purchase commitments include the following: (i) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers (ii) a 95.6 MW (average) three-year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2022 and expiring in 2024) and (iii) a five-year purchase of 52 MW (average) hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2023). Power sales commitments include: (i) winter capacity sale of 150 MW through 2042, (ii) fixed price, fixed volume hydro energy sales through 2024, (iii) fixed price, fixed volume power sales off the Klamath Cogen facility, (iv) a seasonal tolling arrangement off the Klamath peaking facility with fixed capacity charges through 2024; (v) fixed price, fixed volume renewable energy credit sales off merchant wind facilities, (vi) sales of merchant wind farm capacity to various ISOs and (vii) sales of ancillary services (e.g., regulation and frequency response, generator imbalance, etc.) to third parties from Renewables’ Balancing Authority. In June 2020, Renewables entered into a Payment In Lieu of Taxes (PILOT) agreement related to two of its projects with Torrance County, New Mexico. The agreement requires PILOT payments to Torrance County through 2049. The total amount of PILOT payments related to the two projects in 2021 was $1 million. Renewables also has easement contracts which are included in the table below. Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2021 consisted of: Year Purchases Sales (Millions) 2022 $ 1,069 $ 227 2023 168 122 2024 111 75 2025 65 28 2026 49 37 Thereafter 971 72 Totals $ 2,433 $ 561 Guarantee Commitments to Third Parties As of December 31, 2021, we had approximately $483 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including approximately $21 million related to Vineyard Wind. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind as described in Note 22, which is in addition to the amounts above. 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 December 31, 2021, neither we nor our subsidiaries have any liabilities recorded for these instruments. NECEC Commitments

Environmental Liabilities

Environmental Liabilities	12 Months Ended
	Dec. 31, 2021
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-six waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-six sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; five sites are included in Maine’s Uncontrolled Sites Program; one site is included in the Brownfield Cleanup Program and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, six of the twenty-six sites are also included on the National Priorities list. Any liability may be joint and several for certain sites. We have recorded an estimated liability of $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 December 31, 2021, our estimate for costs to remediate these sites ranges from $14 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 December 31, 2021, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $162 million to $276 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 December 31, 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 December 31, 2021 and 2020, the liability associated with our MGP sites in Connecticut was $113 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 December 31, 2021 and 2020, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $303 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 2082. 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's 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 December 31, 2021 , FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $14 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 DEEP concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs have appealed the court's decision to strike and oral arguments have taken place. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. 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 December 31, 2021 and 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.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes The Taxpayer Certainty and Disaster Tax Relief Act of 2019 (Division Q of the Further Consolidated Appropriations Act of 2020) was signed into law in 2019 that extended the PTC and ITC options for wind facilities to 60% of the full credit for facilities commencing construction in 2020, leaving in place phased down credits for projects commencing in years prior to 2020. The Consolidated Appropriations Act, 2021, signed into law on December 27, 2020 provides extensions to renewable income tax incentives. Onshore and offshore wind projects may now claim a 60% PTC for projects commencing construction in 2020 and 2021. In addition, offshore wind may now elect to claim a 30% ITC for projects commencing construction through 2025. Onshore wind can claim an 18% ITC for projects commencing construction in 2020 or 2021, with no ITC thereafter. Solar projects commencing construction before 2020 may claim a 30% ITC. Solar projects that commence construction from 2020-2022 may claim a 26% ITC, projects commencing construction in 2023 may claim a 22% ITC and projects commencing thereafter may claim a 10% ITC. The ITC statutes require solar projects be completed by the end of 2025 in order to claim the applicable ITCs except for projects under the 10% credit. The Internal Revenue Service (IRS) previously provided continuity safe harbor guidance that requires renewable projects to be completed within four years of the year construction commences. Any projects that do not meet this requirement will fall outside of the safe harbor and be subject to IRS scrutiny with regard to the date construction commenced. In 2021, the IRS provided new guidance for an extension to a period of 6 years for the Continuity Safe Harbor for projects for which construction began in 2016 through 2019 and 5 years for the Continuity Safe Harbor for projects in which construction begin in 2020. Most importantly, this new guidance for the continuity requirement is satisfied if the taxpayer demonstrates satisfaction of either the Continuous Construction or the Continuous Efforts Tests, regardless of the method that the taxpayer used to begin construction. In late December 2020, the IRS issued a notice giving onshore wind projects on federal lands, with transmission permit requirements, and offshore wind projects 10 years to complete construction. Since early 2020, and in response to regulatory orders received in most but not all of our operating jurisdictions, we began returning to customers both protected and unprotected excess accumulated deferred income tax (ADIT) from the 2017 Tax Act. Such amounts are subject to the terms of those orders while meeting the requirements of normalization for both ARAM and RSG methodologies. Current and deferred taxes charged to expense for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, 2021 2020 2019 (Millions) Current Federal $ 6 $ 3 $ 11 State 4 9 (6) Current taxes charged to expense 10 12 5 Deferred Federal 49 67 164 State 72 38 58 Deferred taxes charged to expense 121 105 222 Production tax credits (109) (87) (57) Investment tax credits (1) (1) (1) Total Income Tax Expense $ 21 $ 29 $ 169 The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, 2021 2020 2019 (Millions) Tax expense at federal statutory rate $ 140 $ 119 $ 170 Depreciation and amortization not normalized (19) (13) (23) Investment tax credit amortization (1) (1) (1) Tax return related adjustments — 1 (2) Production tax credits (109) (87) (57) Tax equity financing arrangements 14 1 8 State tax expense (benefit), net of federal benefit 61 37 41 Excess ADIT amortization (65) (42) — Valuation allowance 21 12 4 Other, net (21) 2 29 Total Income Tax Expense $ 21 $ 29 $ 169 Deferred tax assets and liabilities as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,257 $ 4,147 Unfunded future income taxes 104 100 Federal and state tax credits (844) (731) Federal and state NOL’s (998) (1,047) Joint ventures/partnerships 188 167 Nontaxable grant revenue (292) (311) Pension and other post-retirement benefits 1 22 Tax Act - tax on regulatory remeasurement (352) (382) Valuation allowance 110 81 Other (158) (127) Deferred Income Tax Liabilities $ 2,016 $ 1,919 Deferred tax assets $ 2,644 $ 2,598 Deferred tax liabilities 4,660 4,517 Net Accumulated Deferred Income Tax Liabilities $ 2,016 $ 1,919 As of December 31, 2021, we had gross federal tax net operating losses of $3.6 billion, federal PTCs and ITCs, federal R&D tax credits and other federal credits of $805 million, state tax effected net operating losses of $314 million in several jurisdictions and miscellaneous state tax credits of $146 million available to carry forward and reduce future income tax liabilities. For federal purposes, we recognized a valuation allowance of $37 million, and for state purposes, we recognized a valuation allowance of $73 million. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2023. The more significant state net operating losses begin to expire in 2024. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. The valuation allowance for deferred tax assets as of December 31, 2021 and 2020 was $110 million and $81 million, respectively. Valuation allowances have been established on various federal tax credits, state net operating losses and state tax credit carryforwards. The Company has recorded a federal valuation allowance on its federal tax credit carryforwards of $37 million and has recorded a state valuation allowance on its state net operating losses and state tax credit carryforwards of $73 million. The $29 million increase in valuation allowance from 2020 to 2021 includes an increase of $21 million for additional valuation allowance on Federal tax credit carryforwards and an increase of $8 million on state net operating losses and state tax credits. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2021, 2020 and 2019 consisted of: Years ended December 31, 2021 2020 2019 (Millions) Beginning Balance $ 127 $ 148 $ 153 Increases for tax positions related to prior years 3 11 14 Increases for tax positions related to current year — — 16 Decreases for tax positions related to prior years (3) (32) (18) Reduction for tax position related to settlements with taxing authorities — — (17) Ending Balance $ 127 $ 127 $ 148 Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information. Accruals for interest and penalties on tax reserves were immaterial for the years ended December 31, 2021, 2020 and 2019. If recognized, $107 million of the total gross unrecognized tax benefits would affect the effective tax rate. As of December 31, 2021, unrecognized tax benefits are primarily attributed to state tax matters in New York, in which a decrease could occur upon settlement of an outstanding audit during 2022. AVANGRID and its subsidiaries, without ARHI, have been audited for the federal tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. Tax years 2010 and forward are open for potential federal adjustments. All New York state returns, which were filed without ARHI, are closed through 2011 and Maine state returns are closed through 2015. All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. All New York combined state returns are closed for adjustment through 2011. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period. As of December 31, 2021, UIL is subject to audit of its federal tax return for years 2014 through its short period 2015. UIL's short period ending in 2015 is open and subject to Connecticut audit.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar Obligations AVANGRID and its subsidiaries sponsor a number of retirement benefit plans. The plans include qualified defined benefit pension plans, supplemental non-qualified pension plans, defined contribution plans and other postretirement benefit plans for eligible employees and retirees. Eligibility and benefits vary depending on each plan's design. For example, certain benefits are based on years of service and final average compensation while others may use a cash balance formula that calculates benefits using a percentage of annual compensation. Qualified Retirement Benefit Plans As of December 31, 2021 and 2020, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2021 2020 2021 2020 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 3,819 $ 3,669 $ 452 $ 439 Service cost 40 47 3 3 Interest cost 87 107 10 13 Plan amendments 2 7 — — Actuarial loss (gain) (184) 236 (23) 29 Curtailments (38) (21) — — Benefits paid (239) (226) (34) (32) Benefit Obligation as of December 31, 3,487 3,819 408 452 Change in plan assets Fair Value of Plan Assets as of January 1, 3,092 2,848 167 155 Actual return on plan assets 237 388 15 26 Employer contributions 27 84 12 18 Curtailments (38) (2) — — Benefits paid (239) (226) (67) (32) Fair Value of Plan Assets as of December 31, 3,079 3,092 127 167 Funded Status as of December 31, $ (408) $ (727) $ (281) $ (285) During 2021, the pension benefit obligation had an actuarial gain of $184 million, primarily due to a $205 million gain from increases in discount rates. There were no significant gains or losses relating to the postretirement benefit obligations. During 2020, the pension benefit obligation had an actuarial loss of $236 million, primarily due to a $276 million loss from decreases in discount rates. The only significant plan change in 2020 was an agreement to freeze the UI union pension plan. There were no significant gains or losses relating to the postretirement benefit obligations. As of December 31, 2021 and 2020, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2021 2020 2021 2020 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (408) (727) (276) (280) Total $ (408) $ (727) $ (281) $ (285) We have determined that Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans. Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2021 2020 2021 2020 (Millions) Net loss (gain) $ 271 $ 610 $ (18) $ 14 Prior service cost (credit) $ 10 $ 10 $ (1) $ (8) Amounts recognized in OCI for ARHI for the years ended December 31, 2021 and 2020, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2021 2020 2021 2020 (Millions) Net loss (gain) $ 16 $ 21 $ (5) $ (7) As of December 31, 2021 and 2020, the projected benefit obligation (PBO) exceeded the fair value of pension plan assets for all qualified plans. The accumulated benefit obligation (ABO) exceeded the fair value of pension plan assets for all but one plan, as of December 31, 2021, and for all of our qualified plans, as of December 31, 2020. The aggregate PBO and ABO and the fair value of plan assets for our underfunded qualified plans consisted of: PBO in excess of plan assets As of December 31, 2021 2020 (Millions) Projected benefit obligation $ 3,487 $ 3,819 Fair value of plan assets $ 3,079 $ 3,092 ABO in excess of plan assets As of December 31, 2021 2020 (Millions) Accumulated benefit obligation $ 1,790 $ 3,629 Fair value of plan assets $ 1,536 $ 3,092 As of December 31, 2021 and 2020, the accumulated postretirement benefits obligation for all qualified plans exceeded the fair value of plan assets. Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2021, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2021 2020 2019 2021 2020 2019 (Millions) Net Periodic Benefit Cost: Service cost $ 39 $ 46 $ 41 $ 3 $ 3 $ 3 Interest cost 86 106 128 10 13 16 Expected return on plan assets (199) (198) (190) (7) (8) (7) Amortization of prior service cost (benefit) 2 1 (1) (5) (9) (10) Amortization of net loss 115 124 113 2 2 1 Settlement charge 6 — Net Periodic Benefit Cost 49 79 91 3 1 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments — (18) — — — — Settlement charge (6) — — — — — Net loss (gain) (218) 46 80 (31) 11 13 Amortization of net loss (115) (124) (113) (2) (2) (1) Current year prior service cost (credit) 2 7 (2) 1 — — Amortization of prior service (cost) benefit (2) (1) 1 5 9 10 Total Other Changes (339) (90) (34) (27) 18 22 Total Recognized $ (290) $ (11) $ 57 $ (24) $ 19 $ 25 Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2021, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2021 2020 2019 2021 2020 2019 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ 1 $ — $ — $ — Interest cost 1 1 2 — — — Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) 2 2 1 (1) (1) (1) Settlement charge 1 1 — — — — Net Periodic Benefit Cost 3 3 2 (1) (1) (1) Other Changes in plan assets and benefit obligations recognized in OCI: Settlement charge (1) — — (1) — — Net loss (gain) (3) 1 — 1 — — Amortization of net (loss) gain (2) (2) (1) 1 1 1 Amortization of prior service cost — — — — — (2) Total Other Changes (6) (1) (1) 1 1 (1) Total Recognized $ (3) $ 2 $ 1 $ — $ — $ (2) The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the service cost component in other operating expenses net of capitalized portion and include the components of net periodic benefit cost other than the service cost component in other expense. The weighted-average assumptions used to determine our benefit obligations as of December 31, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2021 2020 2021 2020 Discount rate 2.85 % 2.34 % 2.66 % 2.19 % Rate of compensation increase 3.53 % 3.52 % 3.50 % 3.50 % Interest crediting rate 2.87 % 2.87 % N/A N/A The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit obligations. The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2021, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2021 2020 2019 2021 2020 2019 Discount rate 2.34 % 3.01 % 3.98 % 2.19 % 2.99 % 3.97 % Expected long-term return on plan assets 7.30 % 7.30 % 7.30 % 4.05 % 5.09 % 5.08 % Rate of compensation increase 3.52 % 3.66 % 3.79 % 3.50 % 3.48 % 3.50 % We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 Health care cost trend rate assumed for next year 5.00%/7.00% 5.25%/7.25% Rate to which cost trend rate is assumed to decline (ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2029 / 2025 2029 / 2025 Contributions We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. We expect to contribute $22 million and $11 million, respectively, to our pension and other postretirement benefit plans during 2022. Estimated Future Benefit Payments Expected benefit payments as of December 31, 2021 consisted of: (Millions) Pension Benefits Postretirement Benefits 2022 $ 217 $ 30 2023 $ 212 $ 29 2024 $ 214 $ 29 2025 $ 213 $ 28 2026 $ 215 $ 27 2027 - 2031 $ 1,057 $ 122 Non-Qualified Retirement Benefit Plans We also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for these plans, which is included in Other current and Other non-current liabilities on our consolidated balance sheets, was $63 million and $59 million at December 31, 2021 and 2020, respectively. Plan Assets Our pension plan assets are consolidated in one master trust. A consolidated master trust provides for a uniform investment manager lineup and an efficient, cost effective means of allocating income and expenses to each plan. Our primary investment objective is to have a diversified asset allocation policy that mitigates risk and volatility while meeting or exceeding our projected expected return to ensure that current and future benefit obligations are adequately funded. Further diversification and risk mitigation is achieved within each asset class by avoiding significant concentrations in certain markets, utilizing a combination or passive and active investment managers with unique skill and expertise, a systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income and alternative investment markets. Networks and ARHI have established target asset allocation policies with allowable ranges for their pension plan assets within broad categories of asset classes made up of Return-Seeking investments and Liability-Hedging/Fixed Income investments. In 2020, a streamlined investment policy was implemented, which aligned Networks target allocations to the estimated funded status of each specific plan. Return-Seeking assets range from 25%-60% and Liability-Hedging assets range from 40%-75%. Return-Seeking assets include investments in domestic, international and emerging equity real estate, global asset allocation strategies and hedge funds. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair values of pension plan assets, by asset category, as of December 31, 2021, consisted of: As of December 31, 2021 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 69 $ 20 $ 49 $ — U.S. government securities 298 298 — — Common stocks 138 138 — — Registered investment companies 276 276 — — Corporate bonds 837 — 837 — Preferred stocks 1 1 — — Common collective trusts 862 — 862 — Other, principally annuity, fixed income 51 — 51 — $ 2,532 $ 733 $ 1,799 $ — Other investments measured at net asset value 547 Total $ 3,079 The fair values of pension plan assets, by asset category, as of December 31, 2020, consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 120 $ — $ 120 $ — U.S. government securities 177 177 — — Common stocks 107 107 — — Registered investment companies 301 301 — — Corporate bonds 710 — 710 — Preferred stocks 1 1 — — Common collective trusts 1,018 — 1,018 — Other, principally annuity, fixed income 50 6 44 — $ 2,484 $ 592 $ 1,892 $ — Other investments measured at net asset value 608 Total $ 3,092 Valuation Techniques We value our pension plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • U.S. government securities – at the closing price reported in the active market in which the security is traded. • Common stocks – at the closing price reported in the active market in which the individual investment is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Preferred stocks – at the closing price reported in the active market in which the individual investment is traded. • Common collective trusts/Registered investment companies – Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2: the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Our postretirement plan assets are consolidated with one trustee in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements. The assets are invested in various asset classes to achieve sufficient diversification and mitigate risk. This is achieved for our VEBA assets by utilizing multiple institutional mutual and money market funds, which provide exposure to different segments of the securities markets. The 401(h) assets are invested alongside the Pension assets they are tied to and share the same asset allocation policy. Approximately 54% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes. In 2020, a streamlined investment policy was implemented for Networks and ARHI that aligned target allocations. Equities range from 49%-69% and Fixed Income assets range from 31-51%. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed Income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. We primarily minimize the risk of large losses through diversification, but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews. Systematic rebalancing within target ranges increases the probability of increasing the projected expected return, while mitigating risk, should any asset categories drift outside their specified ranges. The fair values of other postretirement plan assets, by asset category, as of December 31, 2021 consisted of: As of December 31, 2021 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 5 $ — $ 5 $ — U.S. government securities 1 1 — — Common stocks 1 1 — — Registered investment companies 101 101 — — Corporate bonds 3 — 3 — Preferred stocks — — — — Common collective trusts 5 — 5 — Other, principally annuity, fixed income 9 — 9 — $ 125 $ 103 $ 22 $ — Other investments measured at net asset value 2 Total $ 127 The fair values of other postretirement plan assets, by asset category, as of December 31, 2020 consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 6 $ — $ 6 $ — U.S. government securities 1 1 — — Registered investment companies 141 141 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 9 — 9 — $ 164 $ 142 $ 22 $ — Other investments measured at net asset value 3 Total $ 167 Valuation Techniques We value our postretirement plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • U.S. government securities – at the closing price reported in the active market in which the security is traded. • Common stocks and registered investment companies – at the closing price reported in the active market in which the individual investment is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Common collective trusts – the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2021 and 2020. Defined contribution plans We also have defined contribution plans defined as 401(k)s for all eligible AVANGRID employees. There are various match formulas depending on years of service, age and pension plan closure/freeze date. For the years ended December 31, 2021, 2020 and 2019, the annual contributions we made to these plans was $58 million, $49 million and $40 million, respectively.

Equity

Equity	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Equity	Equity As of December 31, 2021 and 2020, we had 112,543 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2021 and 2020, we issued 77,883,713 and 42,777 shares of common stock, respectively, and released 301,239 and 72,028 shares of common stock held in trust, respectively, each having a par value of $0.01. 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 target relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2021, 694,148 shares were repurchased pursuant to the stock repurchase program primarily as an advanced re-purchase to hedge a portion of the anticipated payouts under AVANGRID stock based compensation plans. As of December 31, 2021, a total of 997,983 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. As of December 31, 2021, the total cost of all repurchases, including commissions, was $47 million. Accumulated OCI (Loss) Accumulated OCI (Loss) for the years ended December 31, 2021, 2020 and 2019 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2018 Adoption of new accounting standard 2019 Change As of December 31, 2019 2020 Change As of December 31, 2020 2021 Change As of December 31, 2021 (Millions) Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $0 for 2019, $0 for 2020 and $0 for 2021 $ (11) $ (2) $ 1 $ (12) $ — $ (12) $ 2 $ (10) Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $(1) for 2019, $3 for 2020 and $(1) for 2021 (6) — (1) (7) (13) (20) (8) (28) Unrealized loss from equity method investment, net of income tax benefit of $(3) for 2021 (a) $ — $ — $ — $ — $ — $ — $ (9) $ (9) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $(9) for 2019, $(7) for 2020 and $(44) for 2021 9 — (22) (13) (22) (35) (159) (194) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $3 for 2019, $2 for 2020 and $(3) for 2021 (b) (64) (10) 11 (63) 19 (44) 12 (32) Loss on derivatives qualifying as cash flow hedges (55) (10) (11) (76) (3) (79) (147) (226) Accumulated Other Comprehensive Loss $ (72) $ (12) $ (11) $ (95) $ (16) $ (111) $ (162) $ (273) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 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. The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of: Years Ended December 31, 2021 2020 2019 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 707 $ 581 $ 667 Denominator: Weighted average number of shares outstanding - basic 358,086,621 309,494,939 309,491,082 Weighted average number of shares outstanding - diluted 358,578,608 309,559,387 309,514,910 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 1.97 $ 1.88 $ 2.16 Earnings Per Common Share, Diluted $ 1.97 $ 1.88 $ 2.16

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	Variable Interest Entities We participate in certain partnership arrangements that qualify as VIEs. Consolidated VIE's consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights. The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. On 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. On November 4, 2021, we sold a TEF interest in Aeolus Wind Power VIII, LLC (Aeolus VIII) for $199 million, of which $8 million is held in escrow until certain conditions are met. As of December 31, 2021, the assets and liabilities of the VIEs totaled approximately $2,039 million and $119 million, respectively. As of December 31, 2020, the assets and liabilities of VIEs totaled approximately $1,713 million and $107 million, respectively. At both December 31, 2021 and 2020, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment. Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind farms. Under these structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments. The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met. At December 31, 2021, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus VII and Aeolus VIII are our consolidated VIEs. Our El Cabo, Patriot, Aeolus VII and Aeolus VIII interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests. See Note 22 - Equity Method Investments for information on our VIE we do not consolidate.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2021
Other Liabilities Disclosure [Abstract]
Grants, Government Incentives and Deferred Income	Grants, Government Incentives and Deferred Income The changes in deferred income as of December 31, 2021 and 2020 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2019 $ 1,258 $ 16 $ 1,274 Disposals (2) — (2) Recognized in income (66) (2) (68) As of December 31, 2020 1,190 14 1,204 Disposals — — — Recognized in income (65) (9) (74) As of December 31, 2021 $ 1,125 $ 5 $ 1,130 Within deferred income, we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States Department of Treasury (DOT) provides eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the book to tax basis differences related to the property for income tax purposes within the nontaxable grant revenue deferred income tax liabilities (see Note 16 – Income Taxes). We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grant’s terms and conditions, we are required to repay the grant funds to the DOT. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2021 and 2020.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2021
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment	Equity Method Investments On December 16, 2020, Renewables sold a 85% ownership interest in a wind farm located in South Dakota (Tatanka) to WEC Infrastructure involving total consideration of $238 million, excluding closing costs, and recognized a gain of $12 million, net of tax. The pre-tax gain of $16 million is included in "Other income (expense)" in our consolidated statements of income. Our retained investment in Tatanka of $24 million was valued based on an enterprise value of $298 million and applying an effective percentage of economic benefits retained of 7.97%, which was derived from a DCF model similar to the model used for Goodwill as described in Note 7. The net gain includes $4 million related to the remeasurement of our retained investment in Tatanka. The transaction was accounted for as a sale of assets and resulted in a loss of control. The retained 15% ownership interest is accounted for as an equity method investment. As of December 31, 2021, and 2020, the carrying value of our Tatanka investment was $23 million and $24 million, respectively. On December 13, 2019, Renewables transferred a 50% ownership interest in a wind farm and a solar project located in Arizona (Poseidon) to Axium involving total consideration of $112 million, excluding closing costs, and recognized a gain of $96 million, net of tax. The pre-tax gain of $134 million is included in "Other income (expense)" in our consolidated statements of income. The net gain includes $50 million related to the remeasurement of our retained investment in Poseidon which was valued based on the consideration received in the transaction. The transaction was accounted for as the sale of a business and resulted in a loss of control. The retained 50% ownership interest is accounted for as an equity method investment. As of December 31, 2021 and 2020, the carrying value of our Poseidon investment was $96 million and $104 million, respectively. In December 2018, Renewables sold 80% of our wholly owned subsidiary, Coyote Ridge Wind, LLC (Coyote Ridge), including substantially all of the related tax benefits, to WEC Infrastructure in exchange for $144 million of total proceeds with $84 million received in 2019 to complete the transaction. We recorded a gain of $4 million and $10 million from this transaction in “Other expense" in our consolidated statements of income for the years ended December 31, 2019 and 2018, respectively. We account for the remaining 20% membership interest under the equity method of accounting. As of December 31, 2021 and 2020, the carrying amount of our Coyote Ridge investment was $15 million and $16 million, respectively. Renewables has two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC (Flat Rock I) and the Flat Rock Wind Power II LLC (Flat Rock II) wind farms located in upstate New York. Flat Rock I has a 231 MW capacity and Flat Rock II has a 91 MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. As of December 31, 2021 and 2020, the carrying amount of Flat Rock I was $93 million and $98 million, respectively, and Flat Rock II was $44 million and $47 million, respectively. Renewables holds a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners (CIP). Vineyard Wind has acquired easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. The first easement area acquired was Lease Area 501 which contains 166,886 acres located southeast of Martha's Vineyard. Lease Area 501 was subsequently divided in 2021 creating Lease Area 534. 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. The Vineyard Wind 1 project will be located on Lease Area 501. In December 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project, which will be located on Lease area 534. In addition, in December 2021 Vineyard Wind’s Commonwealth Wind project, which will also be located on Lease Area 534 was selected as part of Massachusetts’ third offshore wind competitive procurement process. The Commonwealth Wind’s proposed 1,232 MW wind farm will deliver clean energy to the residents of Massachusetts primarily through contracts with the electric distribution companies in the state, subject to finalization of the power purchase agreements with the electric distribution companies. 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, $152 million of Renewables prior contributions to Vineyard Wind were returned. Vineyard Wind is considered a VIE because it cannot finance its activities without additional support from its owners or third-parties. Renewables is not the primary beneficiary since it does not have a controlling interest in Vineyard Wind, and therefore we do not consolidate Vineyard Wind. As of December 31, 2021 and 2020, the carrying amount of Renewables' investment in Vineyard Wind was $141 million and $245 million, respectively. On September 15, 2021, Renewables entered into an agreement with CIP to restructure Vineyard Wind, which closed on January 10, 2022. Following the restructuring agreement closing, Vineyard Wind 1 remains a 50-50 joint venture, Renewables has full ownership of the project company containing Lease Area 534, including the Park City Wind and Commonwealth Wind projects along with any remaining non-contracted area in Lease Area 534, and CIP has full ownership of the project company containing Lease Area 522. The consideration exchanged resulted in Renewables making a payment of approximately $168 million to CIP, and Renewables will recognize a gain ranging from $175 million to $200 million in 2022, driven by the increase in the market value of the leases and related development activities over its carrying value. The purchase price accounting is preliminary and subject to change. Networks is a party to a 50-50 joint venture with Clearway Energy, Inc. in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is accounted for as an equity investment. As of December 31, 2021 and 2020, the carrying value of our GenConn investment was $99 million and $104 million, respectively. Networks holds an approximate 20% ownership interest in New York TransCo. Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. On April 8, 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The selected project, New York Energy Solution (NYES), replaces nearly 80-year old transmission assets located in the upper to mid-Hudson Valley with streamlined, modernized technology, to enable surplus clean energy resources in upstate New York and help achieve the State’s energy goals. The total project cost is $600 million plus interconnection costs. New York Transco is subject to regulatory approval of its rates, terms and conditions with the FERC. As of both December 31, 2021 and 2020, the amount receivable from New York TransCo was $0. The investment in New York TransCo is accounted for as an equity investment. As of December 31, 2021 and 2020, the carrying value of our New York TransCo investment was $49 million and $30 million, respectively. None of our joint ventures have any contingent liabilities or capital commitments, except for those disclosed above. Distributions received from equity method investments, excluding the return of capital as part of the Vineyard Wind 1 financial close disclosed above, amounted to $21 million, $22 million and $17 million for the years ended December 31, 2021, 2020 and 2019 respectively, which are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively. In addition, during the years ended December 31, 2021, 2020 and 2019, we received $11 million, $14 million and $9 million of distributions in RECs from our equity method investments. As of December 31, 2021, there was $10 million of undistributed earnings from our equity method investments. Capitalized interest costs related to equity method investments were $6 million, $8 million and $7 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Other Financial Statements Items	Other Financial Statements Items Other income (expense) Other income (expense) for the years ended December 31, 2021, 2020 and 2019 consisted of: Years ended December 31, 2021 2020 2019 (Millions) Gain on sale of assets (a) $ — $ 20 $ 148 Allowance for funds used during construction 88 56 46 Carrying costs on regulatory assets 17 28 21 Non-service component of net periodic benefit cost (37) (62) (79) Other (8) (24) (15) Total Other Income (Expense) $ 60 $ 18 $ 121 (a) 2020 includes a $16 million gain from the Tatanka sale and 2019 includes a $134 million gain from the Poseidon sale (see Note 22). Accounts receivable and unbilled revenues, net Accounts receivable and unbilled revenues, net as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Trade receivables and unbilled revenues $ 1,420 $ 1,295 Allowance for credit losses (151) (108) Total Accounts receivable and unbilled revenues, net $ 1,269 $ 1,187 The change in the allowance for credit losses as of December 31, 2021 and 2020 consisted of: (Millions) As of December 31, 2018 $ 62 Current period provision 92 Write-off as uncollectible (85) As of December 31, 2019 $ 69 Current period provision 83 Write-off as uncollectible (44) As of December 31, 2020 $ 108 Current period provision 110 Write-off as uncollectible (67) As of December 31, 2021 $ 151 DPA receivable balances were $108 million and $78 million as of December 31, 2021 and 2020, respectively. As of December 31, 2021 and 2020, our allowance for credit losses for DPAs was $68 million and $48 million, respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Prepaid other taxes $ 95 $ 135 Short-term investment (a) — 300 Broker margin and collateral accounts 87 30 Other pledged deposits 4 2 Prepaid expenses 58 41 Other 1 17 Total $ 245 $ 525 (a) Short-term investment from proceeds of the Iberdrola Loan. Other current liabilities Other current liabilities as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Advances received $ 204 $ 141 Accrued salaries 127 109 Short-term environmental provisions 52 49 Collateral deposits received 58 42 Pension and other postretirement 5 5 Finance leases 4 8 Other 34 14 Total $ 484 $ 368 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 $11 million, net of tax. The pre-tax gain of $15 million is recorded in "Operating revenues" in our 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.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Segment Information	Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes 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, a legal settlement, 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 consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. Segment information as of and for the year ended December 31, 2021 consisted of: For the year ended December 31, 2021 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,753 $ 1,220 $ 1 $ 6,974 Revenue - intersegment 1 — (1) — Depreciation and amortization 616 397 1 1,014 Operating income 876 26 (7) 895 Earnings (losses) from equity method investments 12 (5) — 7 Interest expense, net of capitalization 217 1 80 298 Income tax expense (benefit) 98 (48) (29) 21 Capital expenditures 2,294 680 2 2,976 Adjusted net income 661 170 (51) 780 As of December 31, 2021 Property, plant and equipment 18,737 10,118 11 28,866 Equity method investments 148 412 — 560 Total assets $ 26,126 $ 12,578 $ 800 $ 39,504 (a) Includes Corporate and intersegment eliminations. Segment information as of and for the year ended December 31, 2020 consisted of: For the year ended December 31, 2020 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,187 $ 1,132 $ 1 $ 6,320 Revenue - intersegment 1 — (1) — Depreciation and amortization 592 394 1 987 Operating income 877 (16) 8 869 Earnings (losses) from equity method investments 10 (13) — (3) Interest expense, net of capitalization 234 7 75 316 Income tax expense (benefit) 120 (80) (11) 29 Capital expenditures 1,838 943 — 2,781 Adjusted net income 568 115 (58) 625 As of December 31, 2020 Property, plant and equipment 17,079 9,662 10 26,751 Equity method investments 134 534 — 668 Total assets $ 24,592 $ 12,867 $ 364 $ 37,823 (a) Includes Corporate and intersegment eliminations. Segment information for the year ended December 31, 2019 consisted of: For the year ended December 31, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 5,150 $ 1,184 $ 2 $ 6,336 Revenue - intersegment 14 — (14) — Depreciation and amortization 549 383 1 933 Operating income 890 93 15 998 Earnings (losses) from equity method investments 11 (8) — 3 Interest expense, net of capitalization 269 14 27 310 Income tax expense (benefit) 152 28 (11) 169 Capital expenditures 1,610 1,122 3 2,735 Adjusted net income $ 465 $ 193 $ (17) $ 640 (a) Includes Corporate and intersegment eliminations. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019 is as follows: Years Ended December 31, 2021 2020 2019 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 780 $ 625 $ 640 Adjustments: Mark-to-market adjustments - Renewables (1) (53) (5) 76 Restructuring charges (2) — (6) (6) Accelerated depreciation from repowering (3) — (9) (33) Impact of COVID-19 (4) (34) (29) — Merger costs (5) (12) (6) — Legal settlement - Gas storage (6) — (5) — Income tax impact of adjustments 26 16 (10) Net Income Attributable to Avangrid, Inc. $ 707 $ 581 $ 667 (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 wind farms in Renewables. (4) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (5) Pre-merger costs incurred. (6) Removal of the impact from Gas activity in the reconciliation to AVANGRID Net Income.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 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 years ended December 31, 2021, 2020 and 2019, respectively, consisted of: Years Ended December 31, 2021 2020 2019 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (52) $ 1 $ (43) $ 1 $ (42) Iberdrola Renovables Energia, S.L. $ — $ (10) $ — $ (9) $ — $ (9) Iberdrola Financiación, S.A. $ — $ (9) $ — $ (7) $ — $ (3) Vineyard Wind $ 14 $ — $ 9 $ — $ 13 $ — Iberdrola Solutions $ 7 $ (39) $ 2 $ — $ 1 $ — Other $ 2 $ (3) $ — $ — $ 1 $ (3) In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola had an 8.1% ownership interest until Iberdrola sold its interest in February 2020. After the sale, the turbine purchases are no longer considered related party transactions. The amounts capitalized for transactions while Siemens-Gamesa was considered a related party was $11 million for the year ended December 31, 2020. Related party balances as of December 31, 2021 and 2020, respectively, consisted of: As of December 31, 2021 2020 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 3 $ (43) $ 2 $ (43) Iberdrola Financiacion $ — $ (9) $ — $ (6) Vineyard Wind $ 8 $ (8) $ 4 $ — Iberdrola Solutions $ — $ (2) $ 5 $ — Other $ — $ (1) $ 1 $ (1) Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 10 for a discussion of the Iberdrola Loan. AVANGRID optimizes its 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 December 31, 2021 and 2020 was $0. AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both December 31, 2021 and 2020, there was no outstanding amount under this credit facility. 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 for the years ended December 31, 2021 and 2020, respectively. Renewables also had financial forward power contracts with Iberdrola Solutions to hedge Renewables' uncontracted wind exposure in Texas. See Note 22 - Equity Method Investments for more information on transactions with our equity method investees. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation	Stock-Based CompensationThe Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares). As of December 31, 2021, the total number of shares authorized for stock-based compensation plans was 2,500,000. Performance Stock Units During 2016, 1,298,683 performance stock units (PSUs) were granted to certain officers and employees of AVANGRID. In 2017, 2018 and 2019, an additional 85,759, 75,350 and 3,881 PSUs, respectively, were granted to officers and employees of AVANGRID under the Plan with achievement measured based on certain performance and market-based metrics for the 2016 to 2019 time period. The fair value of the PSUs on the grant date was $31.80 per share, which is expensed on a straight-line basis over the requisite service period of approximately seven years based on expected achievement. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recent quarterly dividend payment and the stock price as of the grant date. In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved as earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes. The remaining unvested PSUs were forfeited. In May 2020, 42,777 shares of common stock were issued to settle the first installment payment and 2,605 PSUs were forfeited from the originally approved total number of PSUs. In March 2021, 45,661 shares of common stock were issued to settle the second installment payment. The final payment will occur in 2022. During 2021, 1,336,787 PSUs, 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 June and October 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan two restricted stock units (RSUs) awards of 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vested in full in one installment in June and December 2020, respectively for each award. The fair value on the grant date was determined based on a price of $50.40 per share for the June 2018 awards and $47.59 per share for the October 2018 awards. In June 2020, 60,000 RSUs, plus dividend equivalents accrued through the vesting period, were settled for $3 million in cash. In March 2021, the October 2018 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 October 2021, this RSU grant was cancelled and the remaining unvested RSUs were forfeited. In March 2021, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in full in one installment in March 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting date. The fair value on the grant date was determined based on a price of $48.83 per share. 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. In January 2022, 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 48.16 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 will vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of AVANGRID’s common stock at each reporting date until the date of settlement. In both June 2020 and March 2021, $2 million was paid to settle, respectively, the first and the second installments under this plan. As of both December 31, 2021 and 2020, the total liability was $2 million, which is included in other current and non-current liabilities. The total stock-based compensation expense, which is included in "Operations and maintenance" of our consolidated statements of income for the years ended December 31, 2021, 2020 and 2019 was $18 million, $14 million and $3 million, respectively. The total income tax benefits recognized for stock-based compensation arrangements for each of the years ended December 31, 2021, 2020 and 2019, were $5 million, $4 million and $1 million, respectively. A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2021, and changes during the fiscal year ended December 31, 2021, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2020 142,167 $ 32.42 Granted 1,359,516 $ 36.49 Forfeited (90,603) $ 36.63 Vested (87,751) $ 47.70 Nonvested Balance – December 31, 2021 1,323,328 $ 36.05 As of December 31, 2021, total unrecognized costs for non-vested PSUs, RSUs and Phantom Shares was $25 million. The weighted-average period over which the PSU, RSU and Phantom Shares costs will be recognized is approximately 3 years. The weighted-average grant date fair value of PSUs and RSUs granted during the year was $36.49 per share for the year ended December 31, 2021.

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2021
Subsequent Events [Abstract]
Subsequent events	Subsequent eventsOn February 16, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2022 to shareholders of record at the close of business on March 1, 2022.On January 10, 2022 Renewables closed an agreement with CIP to restructure Vineyard Wind. See Note 22 - Equity Method Investments for more information on this transaction.

CONDENSED FINANCIAL INFORMATION

CONDENSED FINANCIAL INFORMATION OF PARENT	12 Months Ended
	Dec. 31, 2021
Condensed Financial Information Disclosure [Abstract]
CONDENSED FINANCIAL INFORMATION OF PARENT	Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF INCOME FOR THE YEARS ENDED December 31, 2021, 2020 AND 2019 Years Ended December 31, 2021 2020 2019 (Millions) Operating Revenues $ — $ — $ — Operating Expenses Operating expense 19 10 3 Taxes other than income taxes (11) (11) (12) Total Operating Expenses 8 (1) (9) Operating (Loss) Income (8) 1 9 Other Income Other income 22 35 59 Equity earnings of subsidiaries 756 641 678 Interest expense (93) (109) (93) Income Before Income Tax 677 568 653 Income tax benefit (30) (13) (14) Net Income $ 707 $ 581 $ 667 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED December 31, 2021, 2020, AND 2019 Years Ended December 31, 2021 2020 2019 (Millions) Net Income $ 707 $ 581 $ 667 Other comprehensive loss of subsidiaries (162) (16) (11) Comprehensive Income $ 545 $ 565 $ 656 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT BALANCE SHEETS AS OF December 31, 2021 AND 2020 As of December 31, 2021 2020 (Millions) Assets Current Assets Cash and cash equivalents $ 1,424 $ 1,438 Accounts receivable from subsidiaries 128 124 Notes receivable from subsidiaries 1,475 1,489 Prepayments and other current assets 52 357 Total current assets 3,079 3,408 Investments in subsidiaries 18,500 18,356 Other assets Deferred income taxes 413 388 Other 3 3 Total other assets 416 391 Total Assets $ 21,995 $ 22,155 Liabilities Current Liabilities Notes payable — 308 Notes payable to subsidiaries 643 1,375 Accounts payable and accrued liabilities 3 12 Accounts payable to subsidiaries 9 9 Interest accrued 9 9 Interest accrued subsidiaries 1 10 Dividends payable 170 136 Total current liabilities 835 1,859 Derivative liabilities 19 — Non-current debt 2,065 2,087 Non-current debt with affiliate — 3,000 Total non-current liabilities 2,084 5,087 Total Liabilities 2,919 6,946 Equity Stockholders' Equity: Common stock 3 3 Additional paid-in capital 17,679 13,665 Treasury stock (47) (14) Retained earnings 1,714 1,666 Accumulated other comprehensive loss (273) (111) Total Equity 19,076 15,209 Total Liabilities and Equity $ 21,995 $ 22,155 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED December 31, 2021, 2020, AND 2019 Years Ended December 31, 2021 2020 2019 (Millions) Net Cash used in Operating Activities $ (397) $ (142) $ (1,299) Cash Flow from Investing Activities Notes receivable from subsidiaries 130 (73) 633 Investments in subsidiaries (1,026) (591) (399) Return of capital from investments in subsidiaries 1,122 419 433 Other investments 300 (300) — Net Cash provided by (used in) Investing Activities 526 (545) 667 Cash Flow from Financing Activities (Repayments) receipts of short-term notes payable from subsidiaries, net (186) (14) 107 Repayments of short-term notes payable (309) (253) (27) Proceeds from non-current debt — 744 1,243 (Repayments) proceeds from non-current debt with affiliate (3,000) 3,000 — Repayments of non-current debt — (950) — Repurchase of common stock (33) (2) — Issuance of common stock 3,998 (1) — Dividends paid (613) (545) (545) Net Cash (used in) provided by Financing Activities (143) 1,979 778 Net (Decrease) Increase in Cash and Cash Equivalents (14) 1,292 146 Cash and Cash Equivalents, Beginning of Year 1,438 146 — Cash and Cash Equivalents, End of Year $ 1,424 $ 1,438 $ 146 Supplemental Cash Flow Information Cash paid for interest $ 74 $ 111 $ 85 Cash paid (refunded) payment for income taxes $ (15) $ 65 $ 43 See accompanying notes to Schedule I. Avangrid, Inc. (AVANGRID) is a holding company and we conduct substantially all of our business through our subsidiaries. Substantially all of our consolidated assets are held by our subsidiaries. Accordingly, our cash flow and ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the distribution or other payment of their earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. Our condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. Our condensed financial statements should be read in conjunction with the consolidated financial statements and notes thereto of AVANGRID and subsidiaries (AVANGRID Group). AVANGRID indirectly or directly owns all of the ownership interests of our significant subsidiaries. AVANGRID relies on dividends or loans from our subsidiaries to fund dividends to our primary shareholder. AVANGRID’s significant accounting policies are consistent with those of the AVANGRID Group. For the purposes of these condensed financial statements, AVANGRID’s wholly owned and majority owned subsidiaries are recorded based upon our proportionate share of the subsidiaries net assets. AVANGRID files a consolidated federal income tax return that includes the taxable income or loss of all our subsidiaries. Each subsidiary company is treated as a member of the consolidated group and determines its current and deferred taxes separately and settles its current tax liability or benefit each year directly with AVANGRID pursuant to a tax sharing agreement between AVANGRID and our members. 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 November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, Avangrid, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals. 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 April 20, 2023, as amended (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 of a 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. As of December 31, 2021, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 387,678,630 shares issued and 386,568,104 shares outstanding, 81.6% of which are owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $3 million and additional paid in capital of $17,679 million. As of December 31, 2020, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 309,794,917 shares issued and 309,077,300 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $ $0.01, for a total value of common stock capital of $3 million and additional paid in of $13,665 million. As of December 31, 2021 and 2020, we had 112,543 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2021 and 2020, we issued 77,883,713 and 42,777 shares of common stock, respectively, and released 301,239 and 72,028 shares of common stock held in trust, respectively, each having a par value of $0.01. 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 target relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2021, 694,148 shares were repurchased pursuant to the stock repurchase program. As of December 31, 2021, a total of 997,983 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. As of December 31, 2021, the total cost of all repurchases, including commissions, was $47 million. On February 16, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2022 to shareholders of record at the close of business on March 1, 2022. In 2017, AVANGRID issued $600 million aggregate principal amount of its 3.15% notes maturing in 2024. On May 16, 2019, AVANGRID issued $750 million aggregate principal amount of its 3.80% notes maturing in 2029. Proceeds of the offering were used to finance and/or refinance, in whole or in part, one or more eligible renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $743 million. On April 9, 2020, AVANGRID issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%. Net proceeds of the offering after the price discount and issuance-related expenses were $744 million. Cash dividends paid by subsidiary are as follows: Years ended December 31, 2021 2020 2019 (millions) AVANGRID Networks $ 970 $ 419 $ 433 AVANGRID Renewables $ 152 $ — $ — For the years ended December 31, 2021, 2020 and 2019, AVANGRID made capital contributions to Networks of $1,011 million, $590 million and $158 million, respectively. During 2021 and 2020, AVANGRID recorded a net non-cash contribution and dividend of $674 million and $423 million, respectively, to and from its subsidiaries to zero out their account balances of notes receivable and payable.

Summary of Significant Accoun_2

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Policies)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidationWe consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting.
Revenue recognition	Revenue recognitionWe recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 24. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. 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. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all 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. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer. Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration. Other Other, which does not represent a segment, includes miscellaneous Corporate revenues including intersegment eliminations. Contract Costs, Contract Liabilities and Practical Expedient We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2022 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2021 and 2020, and are presented in "Other non-current assets" on our consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $16 million and $9 million at December 31, 2021 and 2020, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $22 million for the year ended December 31, 2021, and $21 million for both of the years ended December 31, 2020 and 2019 as revenue related to contract liabilities. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.
Regulatory accounting	Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
Business combinations and assets acquisitions (disposals)	Business combinations and assets acquisitions (disposals) We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred. In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed.
Noncontrolling interests	Noncontrolling interestsNoncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement.Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets.
Equity method investments	Equity method investmentsWe account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary.
Goodwill and other intangible assets	Goodwill and other intangible assetsGoodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four
Property, plant and equipment	Property, plant and equipment We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment. We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service. We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation. We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transmission and transport facilities 41-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 7-85 Computer software 3-37 Other Buildings 30-82 Operations offices 3-75 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation were 2.8% and 2.9% of average depreciable property for 2021 and 2020, respectively. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income.
Leases	Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on the information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes an option to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets.
Impairment of long-lived assets	Impairment of long-lived assets We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset.
Fair value measurement	Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e.
Equity investments with readily determinable fair values	Equity investments with readily determinable fair valuesWe measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.
Derivatives and hedge accounting	Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Certain derivatives hedge specific cash flows that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. Certain interest rate derivatives hedge a liability (i.e. debt) that qualify and are designated for hedge accounting are classified as fair value hedges. Changes in the fair value of interest rate derivatives designated as a fair value hedge and the offsetting changes in the fair value of the underlying hedged exposure (i.e. debt) are recorded in Interest expense. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.
Cash and cash equivalents	Cash and cash equivalentsCash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows.
Trade receivable and unbilled revenue, net of allowance for credit losses	Trade receivable and unbilled revenue, net of allowance for credit losses We record trade receivables at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain trade receivables and payables related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets. Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. Due to COVID-19, the UIL companies’ regulators require them to offer to customers, through early February 2022, a 24-month repayment plan. We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. We consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts.
Variable interest entities	Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors.
Debentures, bonds and bank borrowings	Debentures, bonds and bank borrowingsWe record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets.
Inventory	InventoryInventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.”
Government grants and Deferred income	Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses. (t ) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.
Asset retirement obligations	Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations.
Environmental remediation liability	Environmental remediation liabilityIn recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis.
Post-employment and other employee benefits	Post-employment and other employee benefits We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period.
Income taxes	Income taxes We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets. We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” in our consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income. Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.
Stock-based compensation	Stock-based compensationStock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier.
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued But Not Yet Adopted	Adoption of New Accounting Pronouncements (a) 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 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. (c) 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 liabilities from revenue contracts in a business combination. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively to business combinations occurring on or after the effective date of the amendments. Early adoption is permitted. We have elected to early apply the amendments effective October 1, 2021. Our adoption did 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 that we have evaluated or are evaluating to determine their effect on our 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 were 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. Our prospective adoption of ASC 848 on January 1, 2022 will not materially affect our consolidated results of operations, financial position and cash flows. (b) Disclosures by business entities about government assistance In November 2021, the FASB issued amendments that apply to business entities (all entities except specified not-for-profit entities and employee benefit plans) that account for a transaction with a government by applying a grant or contribution accounting model by analogy to other accounting guidance (such as a grant model within International Accounting Standards 20 Accounting for Government Grants and Disclosure of Government Assistance, or ASC Subtopic 958-605, Not-For-Profit Entities—Revenue Recognition). Government assistance can include tax credits (excluding transactions within the scope of Topic 740, Income Taxes), cash grants, grants of other assets, and project grants. Often, government assistance is provided to an entity for a particular purpose, and the entity promises to take specific actions. Transactions with a government, as used in ASC 832, Government Assistance, include assistance administered by domestic, foreign, local (city, town, county, municipal), regional (state, provincial, territorial), and national (federal) governments and entities related to those governments. The amendments require annual disclosures in notes to financial statements about transactions with a government as follows: (1) information about the nature of the transactions and the related accounting policy used to account for the transactions, (2) the line items on the balance sheet and income statement affected by the transactions, and the amounts applicable to each financial statement line item, and (3) significant terms and conditions of the transactions, including commitments and contingencies. For entities within scope the amendments are effective for annual periods beginning after December 15, 2021, with early application permitted. The amendments are to be applied either (1) prospectively to transactions within the scope of the amendments that are reflected in financial statements at the date of initial application and new transactions that are entered into after the date of initial application or (2) retrospectively to those transactions. Our adoption of the amendments on January 1, 2022 will not materially affect our disclosures.
Use of Estimates and Assumptions	Use of Estimates and Assumptions The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for credit losses and unbilled revenues; (2) asset impairments, including goodwill; (3) investments in equity instruments; (4) depreciable lives of assets; (5) income tax valuation allowances; (6) uncertain tax positions; (7) reserves for professional, workers’ compensation and comprehensive general insurance liability risks; (8) contingency and litigation reserves; (9) fair value measurements; (10) earnings sharing mechanisms; (11) environmental remediation liabilities; (12) AROs; (13) pension and other postretirement employee benefits and (14) noncontrolling interest balances. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates we use in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates. We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from COVID-19 has made such estimates and assumptions more difficult to assess and calculate. Affected estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While we have not yet had material effects of COVID-19 on our financial results, actual results could differ from those estimates, which could result in material effects to our consolidated financial statements in future reporting periods.
Union collective bargaining agreements	Union collective bargaining agreements We have approximately 47.7% of our employees covered by a collective bargaining agreement. Agreements expiring in the coming year apply to approximately 18.8% of our employees.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2021
Accounting Policies [Abstract]
Schedule of Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transmission and transport facilities 41-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 7-85 Computer software 3-37 Other Buildings 30-82 Operations offices 3-75 Property, plant and equipment as of December 31, 2021, consisted of: As of December 31, 2021 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 17,392 $ 13,446 $ 30,838 Natural gas transportation, distribution and other 5,032 13 5,045 Other common operating property — 286 286 Total Property, Plant and Equipment in Service 22,424 13,745 36,169 Total accumulated depreciation (5,806) (4,783) (10,589) Total Net Property, Plant and Equipment in Service 16,618 8,962 25,580 Construction work in progress 2,064 1,222 3,286 Total Property, Plant and Equipment $ 18,682 $ 10,184 $ 28,866 Property, plant and equipment as of December 31, 2020, consisted of: As of December 31, 2020 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 16,364 $ 12,854 $ 29,218 Natural gas transportation, distribution and other 4,637 13 4,650 Other common operating property — 274 274 Total Property, Plant and Equipment in Service 21,001 13,141 34,142 Total accumulated depreciation (5,363) (4,436) (9,799) Total Net Property, Plant and Equipment in Service 15,638 8,705 24,343 Construction work in progress 1,384 1,024 2,408 Total Property, Plant and Equipment $ 17,022 $ 9,729 $ 26,751

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2021
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2021, 2020 and 2019 are as follows: Year Ended December 31, 2021 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,015 $ — $ — $ 4,015 Regulated operations – natural gas 1,516 — — 1,516 Nonregulated operations – wind — 1,028 — 1028 Nonregulated operations – solar — 20 — 20 Nonregulated operations – thermal — 63 — 63 Other (a) 67 84 — 151 Revenue from contracts with customers 5,598 1,195 — 6,793 Leasing revenue 7 — — 7 Derivative revenue — 3 — 3 Alternative revenue programs 115 — — 115 Other revenue 34 22 — 56 Total operating revenues $ 5,754 $ 1,220 $ — $ 6,974 Year Ended December 31, 2020 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,642 $ — $ — $ 3,642 Regulated operations – natural gas 1,311 — — 1,311 Nonregulated operations – wind — 822 — 822 Nonregulated operations – solar — 19 — 19 Nonregulated operations – thermal — 39 — 39 Other (a) 58 101 — 159 Revenue from contracts with customers 5,011 981 — 5,992 Leasing revenue 6 — — 6 Derivative revenue — 136 — 136 Alternative revenue programs 157 — — 157 Other revenue 14 15 — 29 Total operating revenues $ 5,188 $ 1,132 $ — $ 6,320 Year Ended December 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 3,485 $ — $ — $ 3,485 Regulated operations – natural gas 1,479 — — 1,479 Nonregulated operations – wind — 803 — 803 Nonregulated operations – solar — 26 — 26 Nonregulated operations – thermal — 29 — 29 Other (a) 91 62 (12) 141 Revenue from contracts with customers 5,055 920 (12) 5,963 Leasing revenue 6 — — 6 Derivative revenue — 244 — 244 Alternative revenue programs 75 — — 75 Other revenue 28 20 — 48 Total operating revenues $ 5,164 $ 1,184 $ (12) $ 6,336 (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 December 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 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 39 24 9 2 3 2 79 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 26 18 14 12 10 65 145 Total operating revenues $ 71 $ 43 $ 24 $ 14 $ 13 $ 67 $ 232

Industry Regulation (Tables)

Industry Regulation (Tables)	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Schedule of Delivery Rate Increases	The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows: May 1, 2018 Rate Increase Delivery Rate Increase Utility (Millions) % NYSEG Electric $ 30 4.10 % NYSEG Gas $ 15 7.30 % RG&E Electric $ 26 5.70 % RG&E Gas $ 10 5.20 % Year 1 Year 2 Year 3 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 34 4.6 % $ 46 5.9 % $ 36 4.2 % NYSEG Gas $ — — % $ 2 0.8 % $ 3 1.6 % RG&E Electric $ 17 3.8 % $ 14 3.2 % $ 16 3.3 % RG&E Gas $ — — % $ — — % $ 2 1.3 %

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Pension and other post-retirement benefits $ 545 $ 927 Pension and other post-retirement benefits cost deferrals 95 105 Storm costs 448 451 Rate adjustment mechanism 68 33 Revenue decoupling mechanism 68 58 Transmission revenue reconciliation mechanism 15 31 Contracts for differences 73 86 Hardship programs 24 20 Plant decommissioning 2 3 Deferred purchased gas 52 30 Deferred transmission expense 13 26 Environmental remediation costs 256 247 Debt premium 71 83 Unamortized losses on reacquired debt 23 26 Unfunded future income taxes 424 373 Federal tax depreciation normalization adjustment 142 148 Asset retirement obligation 20 21 Deferred meter replacement costs 46 33 COVID-19 cost recovery 21 1 Other 241 180 Total regulatory assets 2,647 2,882 Less: current portion 400 310 Total non-current regulatory assets $ 2,247 $ 2,572
Schedule of Regulatory Liabilities	Regulatory liabilities as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Energy efficiency portfolio standard $ 45 $ 58 Gas supply charge and deferred natural gas cost 7 3 Pension and other post-retirement benefits cost deferrals 73 59 Carrying costs on deferred income tax bonus depreciation 23 34 Carrying costs on deferred income tax - Mixed Services 263(a) 7 11 2017 Tax Act 1,327 1,435 Rate change levelization 99 55 Revenue decoupling mechanism 13 9 Accrued removal obligations 1,192 1,184 Asset sale gain account 2 7 Economic development 26 28 Positive benefit adjustment 22 30 Theoretical reserve flow thru impact 6 10 Deferred property tax 22 31 Net plant reconciliation 16 20 Debt rate reconciliation 49 63 Rate refund – FERC ROE proceeding 35 33 Transmission congestion contracts 23 22 Merger-related rate credits 12 14 Accumulated deferred investment tax credits 24 25 Asset retirement obligation 18 18 Earnings sharing provisions 13 17 Middletown/Norwalk local transmission network service collections 17 18 Low income programs 25 28 Non-firm margin sharing credits 15 14 New York 2018 winter storm settlement 5 9 Hedges gains 19 — Other 194 176 Total regulatory liabilities 3,329 3,411 Less: current portion 307 274 Total non-current regulatory liabilities $ 3,022 $ 3,137

Goodwill and Intangible assets

Goodwill and Intangible assets (Tables)	12 Months Ended
	Dec. 31, 2021
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 372 Total $ 3,119 $ 3,119
Schedule of Intangible Assets Acquired and Developed	Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2021 and 2020: As of December 31, 2021 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 592 $ (301) $ 291 Other 18 (16) 2 Total Intangible Assets $ 610 $ (317) $ 293 As of December 31, 2020 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 593 $ (290) $ 303 Other 31 (29) 2 Total Intangible Assets $ 624 $ (319) $ 305
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2021, to be as follows: Year ending December 31, Amount (Millions) 2022 $ 14 2023 $ 13 2024 $ 13 2025 $ 12 2026 $ 12

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 25 Transmission and transport facilities 41-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 7-85 Computer software 3-37 Other Buildings 30-82 Operations offices 3-75 Property, plant and equipment as of December 31, 2021, consisted of: As of December 31, 2021 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 17,392 $ 13,446 $ 30,838 Natural gas transportation, distribution and other 5,032 13 5,045 Other common operating property — 286 286 Total Property, Plant and Equipment in Service 22,424 13,745 36,169 Total accumulated depreciation (5,806) (4,783) (10,589) Total Net Property, Plant and Equipment in Service 16,618 8,962 25,580 Construction work in progress 2,064 1,222 3,286 Total Property, Plant and Equipment $ 18,682 $ 10,184 $ 28,866 Property, plant and equipment as of December 31, 2020, consisted of: As of December 31, 2020 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 16,364 $ 12,854 $ 29,218 Natural gas transportation, distribution and other 4,637 13 4,650 Other common operating property — 274 274 Total Property, Plant and Equipment in Service 21,001 13,141 34,142 Total accumulated depreciation (5,363) (4,436) (9,799) Total Net Property, Plant and Equipment in Service 15,638 8,705 24,343 Construction work in progress 1,384 1,024 2,408 Total Property, Plant and Equipment $ 17,022 $ 9,729 $ 26,751

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2021
Table Text Block Supplement [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2021 and 2020 consisted of: (Millions) As of December 31, 2019 $ 190 Liabilities settled during the year (2) Liabilities incurred during the year 9 Accretion expense 11 Revisions in estimated cash flows (a) 2 As of December 31, 2020 $ 210 Liabilities settled during the year (2) Liabilities incurred during the year 7 Accretion expense 12 Revisions in estimated cash flows (a) 26 As of December 31, 2021 $ 253 (a) Represents an increase in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2021
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2022-2051 $ 2,759 1.85%-8.00% $ 2,575 1.85%-8.00% Unsecured pollution control notes - fixed 2023-2029 478 1.40%-3.50% 478 1.40%-3.50% Other various non-current debt - fixed 2022-2050 5,110 1.95%-6.66% 4,785 1.95%-7.80% Unamortized debt issuance costs and discount (53) (47) Total Debt 8,294 7,791 Less: debt due within one year, included in current liabilities 372 313 Total Non-current Debt $ 7,922 $ 7,478 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $7,871 million. Other 2021 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity NYSEG 9/24/2021 Unsecured Notes $ 350 2.15 % 2031 RG&E 12/15/2021 First Mortgage Bonds $ 125 2.91 % 2051 RG&E 12/15/2021 First Mortgage Bonds $ 125 2.10 % 2031 CMP 12/15/2021 First Mortgage Bonds $ 200 2.05 % 2031 SCG 12/15/2021 First Mortgage Bonds $ 40 2.05 % 2031
Schedule of Maturities and Repayments of Long-term Debt	Long-term debt maturities, including sinking fund obligations, due over the next five years consist of: 2022 2023 2024 2025 2026 Total (Millions) $ 372 $ 439 $ 612 $ 1,107 $ 660 $ 3,190

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2021
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 45 $ 15 $ — $ — $ 60 Derivative assets Derivative financial instruments - power $ 31 $ 39 $ 85 $ (78) $ 77 Derivative financial instruments - gas 4 34 9 (32) 15 Contracts for differences — — 2 — 2 Derivative financial instruments – Other — — — — — Total $ 35 $ 73 $ 96 $ (110) $ 94 Derivative liabilities Derivative financial instruments - power $ (16) $ (137) $ (90) $ 176 $ (67) Derivative financial instruments - gas (1) (22) — 18 (5) Contracts for differences — — (75) — (75) Derivative financial instruments – Other — (77) — — (77) Total $ (17) $ (236) $ (165) $ 194 $ (224) As of December 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 49 $ 14 $ — $ — $ 63 Derivative assets Derivative financial instruments - power $ 5 $ 31 $ 105 $ (54) $ 87 Derivative financial instruments - gas — 24 19 (35) 8 Contracts for differences — — 2 — 2 Total $ 5 $ 55 $ 126 $ (89) $ 97 Derivative liabilities Derivative financial instruments - power $ (23) $ (31) $ (23) $ 72 $ (5) Derivative financial instruments - gas (1) (9) (2) 9 (3) Contracts for differences — — (88) — (88) Derivative financial instruments – Other — — — — — Total $ (24) $ (40) $ (113) $ 81 $ (96)
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2021, 2020 and 2019 consisted of: (Millions) 2021 2020 2019 Fair value as of January 1, $ 13 $ 25 $ (15) Gains for the year recognized in operating revenues 21 8 53 Losses for the year recognized in operating revenues (34) (2) (2) Total gains or losses for the period recognized in operating revenues (13) 6 51 Gains recognized in OCI 2 1 2 Losses recognized in OCI (52) (3) (3) Total gains or losses recognized in OCI (50) (2) (1) Net change recognized in regulatory assets and liabilities 13 6 5 Purchases (17) (2) (22) Settlements (13) (15) 4 Transfers out of Level 3 (a) (2) (5) 3 Fair value as of December 31, $ (69) $ 13 $ 25 Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ (13) $ 6 $ 51 (a) Transfers out of Level 3 were the result of increased observability of market data. Range at Unobservable Input December 31, 2021 Risk of non-performance 0.39% - 0.51% Discount rate 0.97% - 1.26% Forward pricing ($ per KW-month) $2.00 - $4.80
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2021. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 3.18 $ 6.52 $ 2.27 AECO ($/MMBtu) $ 2.41 $ 5.69 $ 1.53 Ameren ($/MWh) $ 32.23 $ 93.59 $ 18.01 COB ($/MWh) $ 46.83 $ 231.90 $ 9.15 ComEd ($/MWh) $ 29.60 $ 86.32 $ 14.98 ERCOT N hub ($/MWh) $ 35.05 $ 140.00 $ 13.66 ERCOT S hub ($/MWh) $ 34.24 $ 140.00 $ 13.88 Indiana hub ($/MWh) $ 34.20 $ 93.81 $ 20.74 Mid C ($/MWh) $ 43.53 $ 229.90 $ 5.15 Minn hub ($/MWh) $ 28.82 $ 90.99 $ 15.23 NoIL hub ($/MWh) $ 29.35 $ 84.00 $ 14.64 PJM W hub ($/MWh) $ 33.49 $ 113.93 $ 17.78

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Consolidated Balance Sheet and Amounts	The tables below present Networks' derivative positions as of December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 29 $ 7 $ 12 $ 4 Derivative liabilities (12) (4) (27) (64) 17 3 (15) (60) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1) — — — (1) — Total derivatives before offset of cash collateral 17 3 (16) (60) Cash collateral receivable — — — — Total derivatives as presented in the balance sheet $ 17 $ 3 $ (16) $ (60) 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 December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 2021 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 29 $ 70 $ 52 $ 9 Derivative liabilities (11) (14) (65) (11) 18 56 (13) (2) Designated as hedging instruments Derivative assets — — 5 6 Derivative liabilities — — (67) (142) — — (62) (136) Total derivatives before offset of cash collateral 18 56 (75) (138) Cash collateral payable — — 27 57 Total derivatives as presented in the balance sheet $ 18 $ 56 $ (48) $ (81) 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) receivable (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 December 31, 2021 and 2020, respectively, consisted of: As of December 31, 2021 2020 (Millions) Wholesale electricity purchase contracts (MWh) 5.7 5.6 Natural gas purchase contracts (Dth) 9.4 9.5 Fleet fuel purchase contracts (Gallons) 2.0 2.5 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2021 and 2020, respectively, consisted of: As of December 31, 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 20 24 Financial power contracts 9 12 Basis swaps - purchases 30 35 Basis swaps - sales — 2
Summary of Unrealized Gains and Losses from Fair Value Adjustments	The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of December 31, 2021 and 2020 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2021, 2020 and 2019 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2021 Electricity Natural Gas 2021 Electricity Natural Gas Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (23) $ (11) Regulatory liabilities $ (16) $ (3) December 31, 2020 2020 Regulatory assets $ 17 $ 1 Purchased power, natural gas and fuel used $ 55 $ 4 Regulatory liabilities $ — $ — 2019 Purchased power, natural gas and fuel used $ 25 $ 1 The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2021, 2020 and 2019, respectively, were as follows: Years Ended December 31, 2021 2020 2019 (Millions) Derivative Assets $ — $ — $ (3) Derivative Liabilities $ 13 $ 6 $ 8
Derivative Instruments, Gain (Loss)	The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 4 $ 298 Commodity contracts 2 Purchased power, natural gas and fuel used (1) 1,719 Foreign currency exchange contracts (5) — Total $ (3) $ 3 2020 Interest rate contracts $ — Interest expense $ 4 $ 316 Commodity contracts (1) Purchased power, natural gas and fuel used 1 1,379 Foreign currency exchange contracts 1 — Total $ — $ 5 2019 Interest rate contracts $ — Interest expense $ 6 $ 310 Commodity contracts — Purchased power, natural gas and fuel used 1 1,509 Foreign currency exchange contracts (1) — Total $ (1) $ 7 (a) Changes in accumulated OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ (58) Interest Expense $ — $ 298 Commodity contracts $ (142) Operating revenues $ (3) $ 6,974 Total $ (200) $ (3) 2020 Commodity contracts $ 1 Operating revenues $ 6 $ 6,320 2019 Commodity contracts $ (5) Operating revenues $ 3 $ 6,336 (a) Changes in OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2021 Interest rate contracts $ — Interest expense $ 9 $ 298 2020 Interest rate contracts $ (27) Interest expense $ 8 $ 316 2019 Interest rate contracts $ (24) Interest expense $ 2 $ 310 (a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029.
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables' activities as of December 31, 2021 and 2020, respectively, consisted of: As of December 31, 2021 2020 (Millions) Wholesale electricity purchase contracts $ 36 $ 4 Wholesale electricity sales contracts (77) 11 Natural gas and other fuel purchase contracts 6 — Financial power contracts 35 66 Basis swaps - purchases — 7 Total $ — $ 88
Schedule of Effects of Trading and Non-Trading Derivatives	The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2021, 2020 and 2019 consisted of: Year Ended December 31, 2021 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ (1) Wholesale electricity sales contracts (2) (33) Financial power contracts 4 (42) Financial and natural gas contracts (1) (25) Total loss included in operating revenues $ 2 $ (101) $ 6,974 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 32 Financial and natural gas contracts — 12 Total gain included in purchased power, natural gas and fuel used $ — $ 44 $ 1,719 Total Gain (Loss) $ 2 $ (57) Year Ended December 31, 2020 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts (1) 6 Financial power contracts 2 — Financial and natural gas contracts — (13) Total (loss) gain included in operating revenues $ — $ (7) $ 6,320 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (4) Financial and natural gas contracts — 6 Total gain included in purchased power, natural gas and fuel used $ — $ 2 $ 1,379 Total Loss $ — $ (5) Year Ended December 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ — Wholesale electricity sales contracts 3 40 Financial power contracts (3) 23 Financial and natural gas contracts (1) 1 Total (loss) gain included in operating revenues $ (2) $ 64 $ 6,336 Purchased power, natural gas and fuel used Financial power contracts — (1) Financial and natural gas contracts — 15 Total gain included in purchased power, natural gas and fuel used $ — $ 14 $ 1,509 Total (Loss) Gain $ (2) $ 78
Schedule of Fair Value Hedging Instruments	The effects on our consolidated financial statements as of and for the year ended December 31, 2021 are as follows: (millions) Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement As of December 31, 2021 Year Ended December 31, 2021 Current Assets $ — Interest Expense $ (3) $ 298 Non-current liabilities $ (19) Cumulative effect on hedged debt Current debt $ — Non-current debt $ 19

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2021
Leases [Abstract]
Lease, Cost	The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows: For the Year Ended December 31, 2021 2020 2019 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 8 $ 17 $ 12 Interest on lease liabilities 3 4 3 Total finance lease cost 11 21 15 Operating lease cost 14 16 18 Short-term lease cost 4 3 5 Variable lease cost 4 — 2 Sublease income — — — Total lease cost $ 33 $ 40 $ 40 For the years ended December 31, 2021, 2020 and 2019 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2021 2020 2019 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16 $ 13 $ 13 Operating cash flows from finance leases $ 3 $ 3 $ 3 Financing cash flows from finance leases $ 6 $ 9 $ 27 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — $ 46 $ 1 Operating leases $ 10 $ 94 $ 3
Assets And Liabilities, Lessee	Balance sheet and other information as of December 31, 2021 and 2020 was as follows: As of December 31, 2021 2020 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 148 $ 153 Operating lease liabilities, current 12 8 Operating lease liabilities, long-term 149 154 Total operating lease liabilities $ 161 $ 162 Finance Leases Other assets $ 156 $ 162 Other current liabilities 4 8 Other non-current liabilities 91 91 Total finance lease liabilities $ 95 $ 99 Weighted-average Remaining Lease Term (years) Finance leases 7.3 8.12 Operating leases 20.5 21.38 Weighted-average Discount Rate Finance leases 3.49 % 3.71 % Operating leases 3.06 % 3.21 %
Finance Lease Maturity	As of December 31, 2021, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2022 $ 5 $ 14 2023 53 14 2024 23 12 2025 2 11 2026 2 11 Thereafter 19 160 Total lease payments 104 223 Less: imputed interest (9) (62) Total $ 95 161
Operating Lease Maturity	As of December 31, 2021, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2022 $ 5 $ 14 2023 53 14 2024 23 12 2025 2 11 2026 2 11 Thereafter 19 160 Total lease payments 104 223 Less: imputed interest (9) (62) Total $ 95 161

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2021
Commitments and Contingencies Disclosure [Abstract]
Forward Purchase and Sales Commitment Arrangement	Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2021 consisted of: Year Purchases Sales (Millions) 2022 $ 1,069 $ 227 2023 168 122 2024 111 75 2025 65 28 2026 49 37 Thereafter 971 72 Totals $ 2,433 $ 561

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Schedule of Current and Deferred Taxes Charged to (Benefit) Expense	Current and deferred taxes charged to expense for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, 2021 2020 2019 (Millions) Current Federal $ 6 $ 3 $ 11 State 4 9 (6) Current taxes charged to expense 10 12 5 Deferred Federal 49 67 164 State 72 38 58 Deferred taxes charged to expense 121 105 222 Production tax credits (109) (87) (57) Investment tax credits (1) (1) (1) Total Income Tax Expense $ 21 $ 29 $ 169
Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate	The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2021, 2020 and 2019 consisted of: Years Ended December 31, 2021 2020 2019 (Millions) Tax expense at federal statutory rate $ 140 $ 119 $ 170 Depreciation and amortization not normalized (19) (13) (23) Investment tax credit amortization (1) (1) (1) Tax return related adjustments — 1 (2) Production tax credits (109) (87) (57) Tax equity financing arrangements 14 1 8 State tax expense (benefit), net of federal benefit 61 37 41 Excess ADIT amortization (65) (42) — Valuation allowance 21 12 4 Other, net (21) 2 29 Total Income Tax Expense $ 21 $ 29 $ 169
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,257 $ 4,147 Unfunded future income taxes 104 100 Federal and state tax credits (844) (731) Federal and state NOL’s (998) (1,047) Joint ventures/partnerships 188 167 Nontaxable grant revenue (292) (311) Pension and other post-retirement benefits 1 22 Tax Act - tax on regulatory remeasurement (352) (382) Valuation allowance 110 81 Other (158) (127) Deferred Income Tax Liabilities $ 2,016 $ 1,919 Deferred tax assets $ 2,644 $ 2,598 Deferred tax liabilities 4,660 4,517 Net Accumulated Deferred Income Tax Liabilities $ 2,016 $ 1,919
Schedule of Reconciliation of Unrecognized Income Tax Benefits	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2021, 2020 and 2019 consisted of: Years ended December 31, 2021 2020 2019 (Millions) Beginning Balance $ 127 $ 148 $ 153 Increases for tax positions related to prior years 3 11 14 Increases for tax positions related to current year — — 16 Decreases for tax positions related to prior years (3) (32) (18) Reduction for tax position related to settlements with taxing authorities — — (17) Ending Balance $ 127 $ 127 $ 148

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2021
Retirement Benefits [Abstract]
Obligations and Funded Status	As of December 31, 2021 and 2020, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2021 2020 2021 2020 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 3,819 $ 3,669 $ 452 $ 439 Service cost 40 47 3 3 Interest cost 87 107 10 13 Plan amendments 2 7 — — Actuarial loss (gain) (184) 236 (23) 29 Curtailments (38) (21) — — Benefits paid (239) (226) (34) (32) Benefit Obligation as of December 31, 3,487 3,819 408 452 Change in plan assets Fair Value of Plan Assets as of January 1, 3,092 2,848 167 155 Actual return on plan assets 237 388 15 26 Employer contributions 27 84 12 18 Curtailments (38) (2) — — Benefits paid (239) (226) (67) (32) Fair Value of Plan Assets as of December 31, 3,079 3,092 127 167 Funded Status as of December 31, $ (408) $ (727) $ (281) $ (285)
Schedule of Amounts Recognized in Balance Sheet	As of December 31, 2021 and 2020, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2021 2020 2021 2020 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (408) (727) (276) (280) Total $ (408) $ (727) $ (281) $ (285)
Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations	Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2021 2020 2021 2020 (Millions) Net loss (gain) $ 271 $ 610 $ (18) $ 14 Prior service cost (credit) $ 10 $ 10 $ (1) $ (8) Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2021, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2021 2020 2019 2021 2020 2019 (Millions) Net Periodic Benefit Cost: Service cost $ 39 $ 46 $ 41 $ 3 $ 3 $ 3 Interest cost 86 106 128 10 13 16 Expected return on plan assets (199) (198) (190) (7) (8) (7) Amortization of prior service cost (benefit) 2 1 (1) (5) (9) (10) Amortization of net loss 115 124 113 2 2 1 Settlement charge 6 — Net Periodic Benefit Cost 49 79 91 3 1 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments — (18) — — — — Settlement charge (6) — — — — — Net loss (gain) (218) 46 80 (31) 11 13 Amortization of net loss (115) (124) (113) (2) (2) (1) Current year prior service cost (credit) 2 7 (2) 1 — — Amortization of prior service (cost) benefit (2) (1) 1 5 9 10 Total Other Changes (339) (90) (34) (27) 18 22 Total Recognized $ (290) $ (11) $ 57 $ (24) $ 19 $ 25 Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2021, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2021 2020 2019 2021 2020 2019 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ 1 $ — $ — $ — Interest cost 1 1 2 — — — Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) 2 2 1 (1) (1) (1) Settlement charge 1 1 — — — — Net Periodic Benefit Cost 3 3 2 (1) (1) (1) Other Changes in plan assets and benefit obligations recognized in OCI: Settlement charge (1) — — (1) — — Net loss (gain) (3) 1 — 1 — — Amortization of net (loss) gain (2) (2) (1) 1 1 1 Amortization of prior service cost — — — — — (2) Total Other Changes (6) (1) (1) 1 1 (1) Total Recognized $ (3) $ 2 $ 1 $ — $ — $ (2)
Summary of Amounts Recognized in OCI	Amounts recognized in OCI for ARHI for the years ended December 31, 2021 and 2020, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2021 2020 2021 2020 (Millions) Net loss (gain) $ 16 $ 21 $ (5) $ (7)
Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans	PBO in excess of plan assets As of December 31, 2021 2020 (Millions) Projected benefit obligation $ 3,487 $ 3,819 Fair value of plan assets $ 3,079 $ 3,092 ABO in excess of plan assets As of December 31, 2021 2020 (Millions) Accumulated benefit obligation $ 1,790 $ 3,629 Fair value of plan assets $ 1,536 $ 3,092
Weighted Average Assumptions Used to Determine Benefit Obligations and Net periodic Benefit Cost	The weighted-average assumptions used to determine our benefit obligations as of December 31, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2021 2020 2021 2020 Discount rate 2.85 % 2.34 % 2.66 % 2.19 % Rate of compensation increase 3.53 % 3.52 % 3.50 % 3.50 % Interest crediting rate 2.87 % 2.87 % N/A N/A The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2021, 2020 and 2019 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2021 2020 2019 2021 2020 2019 Discount rate 2.34 % 3.01 % 3.98 % 2.19 % 2.99 % 3.97 % Expected long-term return on plan assets 7.30 % 7.30 % 7.30 % 4.05 % 5.09 % 5.08 % Rate of compensation increase 3.52 % 3.66 % 3.79 % 3.50 % 3.48 % 3.50 %
Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations	Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 Health care cost trend rate assumed for next year 5.00%/7.00% 5.25%/7.25% Rate to which cost trend rate is assumed to decline (ultimate trend rate) 4.50 % 4.50 % Year that the rate reaches the ultimate trend rate 2029 / 2025 2029 / 2025
Expected Future Benefits Payments	Expected benefit payments as of December 31, 2021 consisted of: (Millions) Pension Benefits Postretirement Benefits 2022 $ 217 $ 30 2023 $ 212 $ 29 2024 $ 214 $ 29 2025 $ 213 $ 28 2026 $ 215 $ 27 2027 - 2031 $ 1,057 $ 122
Fair Values of Pension Plan Assets, by Asset Category	The fair values of pension plan assets, by asset category, as of December 31, 2021, consisted of: As of December 31, 2021 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 69 $ 20 $ 49 $ — U.S. government securities 298 298 — — Common stocks 138 138 — — Registered investment companies 276 276 — — Corporate bonds 837 — 837 — Preferred stocks 1 1 — — Common collective trusts 862 — 862 — Other, principally annuity, fixed income 51 — 51 — $ 2,532 $ 733 $ 1,799 $ — Other investments measured at net asset value 547 Total $ 3,079 The fair values of pension plan assets, by asset category, as of December 31, 2020, consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 120 $ — $ 120 $ — U.S. government securities 177 177 — — Common stocks 107 107 — — Registered investment companies 301 301 — — Corporate bonds 710 — 710 — Preferred stocks 1 1 — — Common collective trusts 1,018 — 1,018 — Other, principally annuity, fixed income 50 6 44 — $ 2,484 $ 592 $ 1,892 $ — Other investments measured at net asset value 608 Total $ 3,092
Fair Value of Other Postretirement Plan Assets, by Asset Category	The fair values of other postretirement plan assets, by asset category, as of December 31, 2021 consisted of: As of December 31, 2021 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 5 $ — $ 5 $ — U.S. government securities 1 1 — — Common stocks 1 1 — — Registered investment companies 101 101 — — Corporate bonds 3 — 3 — Preferred stocks — — — — Common collective trusts 5 — 5 — Other, principally annuity, fixed income 9 — 9 — $ 125 $ 103 $ 22 $ — Other investments measured at net asset value 2 Total $ 127 The fair values of other postretirement plan assets, by asset category, as of December 31, 2020 consisted of: As of December 31, 2020 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 6 $ — $ 6 $ — U.S. government securities 1 1 — — Registered investment companies 141 141 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 9 — 9 — $ 164 $ 142 $ 22 $ — Other investments measured at net asset value 3 Total $ 167

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2021
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) for the years ended December 31, 2021, 2020 and 2019 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2018 Adoption of new accounting standard 2019 Change As of December 31, 2019 2020 Change As of December 31, 2020 2021 Change As of December 31, 2021 (Millions) Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $0 for 2019, $0 for 2020 and $0 for 2021 $ (11) $ (2) $ 1 $ (12) $ — $ (12) $ 2 $ (10) Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $(1) for 2019, $3 for 2020 and $(1) for 2021 (6) — (1) (7) (13) (20) (8) (28) Unrealized loss from equity method investment, net of income tax benefit of $(3) for 2021 (a) $ — $ — $ — $ — $ — $ — $ (9) $ (9) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $(9) for 2019, $(7) for 2020 and $(44) for 2021 9 — (22) (13) (22) (35) (159) (194) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $3 for 2019, $2 for 2020 and $(3) for 2021 (b) (64) (10) 11 (63) 19 (44) 12 (32) Loss on derivatives qualifying as cash flow hedges (55) (10) (11) (76) (3) (79) (147) (226) Accumulated Other Comprehensive Loss $ (72) $ (12) $ (11) $ (95) $ (16) $ (111) $ (162) $ (273) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 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 years ended December 31, 2021, 2020 and 2019, respectively, consisted of: Years Ended December 31, 2021 2020 2019 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 707 $ 581 $ 667 Denominator: Weighted average number of shares outstanding - basic 358,086,621 309,494,939 309,491,082 Weighted average number of shares outstanding - diluted 358,578,608 309,559,387 309,514,910 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 1.97 $ 1.88 $ 2.16 Earnings Per Common Share, Diluted $ 1.97 $ 1.88 $ 2.16

Grants, Government Incentives_2

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2021
Other Liabilities Disclosure [Abstract]
Schedule of Changes in Deferred Income	The changes in deferred income as of December 31, 2021 and 2020 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2019 $ 1,258 $ 16 $ 1,274 Disposals (2) — (2) Recognized in income (66) (2) (68) As of December 31, 2020 1,190 14 1,204 Disposals — — — Recognized in income (65) (9) (74) As of December 31, 2021 $ 1,125 $ 5 $ 1,130

Other Financial Statements It_2

Other Financial Statements Items (Tables)	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Other Income and (Expense)	Other income (expense) for the years ended December 31, 2021, 2020 and 2019 consisted of: Years ended December 31, 2021 2020 2019 (Millions) Gain on sale of assets (a) $ — $ 20 $ 148 Allowance for funds used during construction 88 56 46 Carrying costs on regulatory assets 17 28 21 Non-service component of net periodic benefit cost (37) (62) (79) Other (8) (24) (15) Total Other Income (Expense) $ 60 $ 18 $ 121 (a) 2020 includes a $16 million gain from the Tatanka sale and 2019 includes a $134 million gain from the Poseidon sale (see Note 22).
Schedule of Accounts Receivable and Change in Allowance For Bad Debts	Accounts receivable and unbilled revenues, net as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Trade receivables and unbilled revenues $ 1,420 $ 1,295 Allowance for credit losses (151) (108) Total Accounts receivable and unbilled revenues, net $ 1,269 $ 1,187 The change in the allowance for credit losses as of December 31, 2021 and 2020 consisted of: (Millions) As of December 31, 2018 $ 62 Current period provision 92 Write-off as uncollectible (85) As of December 31, 2019 $ 69 Current period provision 83 Write-off as uncollectible (44) As of December 31, 2020 $ 108 Current period provision 110 Write-off as uncollectible (67) As of December 31, 2021 $ 151
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Prepaid other taxes $ 95 $ 135 Short-term investment (a) — 300 Broker margin and collateral accounts 87 30 Other pledged deposits 4 2 Prepaid expenses 58 41 Other 1 17 Total $ 245 $ 525
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2021 and 2020 consisted of: As of December 31, 2021 2020 (Millions) Advances received $ 204 $ 141 Accrued salaries 127 109 Short-term environmental provisions 52 49 Collateral deposits received 58 42 Pension and other postretirement 5 5 Finance leases 4 8 Other 34 14 Total $ 484 $ 368

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2021
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the year ended December 31, 2021 consisted of: For the year ended December 31, 2021 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,753 $ 1,220 $ 1 $ 6,974 Revenue - intersegment 1 — (1) — Depreciation and amortization 616 397 1 1,014 Operating income 876 26 (7) 895 Earnings (losses) from equity method investments 12 (5) — 7 Interest expense, net of capitalization 217 1 80 298 Income tax expense (benefit) 98 (48) (29) 21 Capital expenditures 2,294 680 2 2,976 Adjusted net income 661 170 (51) 780 As of December 31, 2021 Property, plant and equipment 18,737 10,118 11 28,866 Equity method investments 148 412 — 560 Total assets $ 26,126 $ 12,578 $ 800 $ 39,504 (a) Includes Corporate and intersegment eliminations. Segment information as of and for the year ended December 31, 2020 consisted of: For the year ended December 31, 2020 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 5,187 $ 1,132 $ 1 $ 6,320 Revenue - intersegment 1 — (1) — Depreciation and amortization 592 394 1 987 Operating income 877 (16) 8 869 Earnings (losses) from equity method investments 10 (13) — (3) Interest expense, net of capitalization 234 7 75 316 Income tax expense (benefit) 120 (80) (11) 29 Capital expenditures 1,838 943 — 2,781 Adjusted net income 568 115 (58) 625 As of December 31, 2020 Property, plant and equipment 17,079 9,662 10 26,751 Equity method investments 134 534 — 668 Total assets $ 24,592 $ 12,867 $ 364 $ 37,823 (a) Includes Corporate and intersegment eliminations. Segment information for the year ended December 31, 2019 consisted of: For the year ended December 31, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 5,150 $ 1,184 $ 2 $ 6,336 Revenue - intersegment 14 — (14) — Depreciation and amortization 549 383 1 933 Operating income 890 93 15 998 Earnings (losses) from equity method investments 11 (8) — 3 Interest expense, net of capitalization 269 14 27 310 Income tax expense (benefit) 152 28 (11) 169 Capital expenditures 1,610 1,122 3 2,735 Adjusted net income $ 465 $ 193 $ (17) $ 640 (a) Includes Corporate and intersegment eliminations.
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019 is as follows: Years Ended December 31, 2021 2020 2019 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 780 $ 625 $ 640 Adjustments: Mark-to-market adjustments - Renewables (1) (53) (5) 76 Restructuring charges (2) — (6) (6) Accelerated depreciation from repowering (3) — (9) (33) Impact of COVID-19 (4) (34) (29) — Merger costs (5) (12) (6) — Legal settlement - Gas storage (6) — (5) — Income tax impact of adjustments 26 16 (10) Net Income Attributable to Avangrid, Inc. $ 707 $ 581 $ 667 (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 wind farms in Renewables. (4) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (5) Pre-merger costs incurred. (6) Removal of the impact from Gas activity in the reconciliation to AVANGRID Net Income.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2021
Related Party Transactions [Abstract]
Schedule of Related Party Transactions and Balances	Related party transactions for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of: Years Ended December 31, 2021 2020 2019 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (52) $ 1 $ (43) $ 1 $ (42) Iberdrola Renovables Energia, S.L. $ — $ (10) $ — $ (9) $ — $ (9) Iberdrola Financiación, S.A. $ — $ (9) $ — $ (7) $ — $ (3) Vineyard Wind $ 14 $ — $ 9 $ — $ 13 $ — Iberdrola Solutions $ 7 $ (39) $ 2 $ — $ 1 $ — Other $ 2 $ (3) $ — $ — $ 1 $ (3) Related party balances as of December 31, 2021 and 2020, respectively, consisted of: As of December 31, 2021 2020 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 3 $ (43) $ 2 $ (43) Iberdrola Financiacion $ — $ (9) $ — $ (6) Vineyard Wind $ 8 $ (8) $ 4 $ — Iberdrola Solutions $ — $ (2) $ 5 $ — Other $ — $ (1) $ 1 $ (1)

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2021
Share-based Payment Arrangement [Abstract]
Schedule of Nonvested PSUs	A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2021, and changes during the fiscal year ended December 31, 2021, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2020 142,167 $ 32.42 Granted 1,359,516 $ 36.49 Forfeited (90,603) $ 36.63 Vested (87,751) $ 47.70 Nonvested Balance – December 31, 2021 1,323,328 $ 36.05

Background and Nature of Oper_2

Background and Nature of Operations (Details) $ / shares in Units, $ in Millions	May 18, 2021USD ($)placement$ / sharesshares	Apr. 15, 2021	Oct. 20, 2020USD ($)$ / shares	Dec. 31, 2021$ / shares	Dec. 31, 2020$ / shares	Dec. 31, 2019$ / shares
Noncontrolling Interest [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
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	$ 3,000
NM Green Holdings, Inc.
Noncontrolling Interest [Line Items]
Merger agreement, share price (in dollars per share) | $ / shares			$ 50.30
Merger agreement term, ownership percentage benchmark			15.00%
Merger agreement, termination rights term, extension period			3 months
Merger agreement, termination rights term, termination fees			$ 130
Merger agreement, termination rights term, termination fees as remedy			184
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			$ 10
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger
Noncontrolling Interest [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%
Hyde Member LLC and Subsidiary of Qatar Investment Authority
Noncontrolling Interest [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
Iberdrola S.A.
Noncontrolling Interest [Line Items]
Sale of stock, number of shares issued (in shares) | shares	63,424,125
Avangrid | Iberdrola S.A.
Noncontrolling Interest [Line Items]
Parent company, ownership percentage				81.60%
Avangrid | Various Shareholders
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners				14.80%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Composite rate	2.80%	2.90%
Average remaining service period	10 years
Expected return on plan assets, period	5 years
Unionized Employees Concentration Risk | Employees covered by a collective bargaining agreement
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	47.70%
Unionized Employees Concentration Risk | Agreements which will expire within the coming year
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	18.80%
Min.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	4 years
Max.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	40 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2021
Plant | Solar power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	35 years
Min. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	45 years
Min. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Plant | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	41 years
Min. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	4 years
Min. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	7 years
Min. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	3 years
Min. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years
Min. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	3 years
Max. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	90 years
Max. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Max. | Plant | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	85 years
Max. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	37 years
Max. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	82 years
Max. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years

Revenue - Additional Informatio

Revenue - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Contract assets	$ 9	$ 9
Contract liabilities	16	9
Contract liabilities, revenue recognized	22	21	$ 21
Accounts receivable related to contracts with customers	1,220	1,151
Unbilled contracts receivable	$ 405	$ 341
Min. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	6 months
Max. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	2 years
Networks
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	1 year
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term	15 years

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 6,793	$ 5,992	$ 5,963
Leasing revenue	7	6	6
Derivative revenue	3	136	244
Alternative revenue programs	115	157	75
Other revenue	56	29	48
Total operating revenues	6,974	6,320	6,336
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	(12)
Leasing revenue	0	0	0
Derivative revenue	0	0	0
Alternative revenue programs	0	0	0
Other revenue	0	0	0
Total operating revenues	0	0	(12)
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,015	3,642	3,485
Regulated operations – electricity | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,516	1,311	1,479
Regulated operations – natural gas | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,028	822	803
Nonregulated operations – wind | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	20	19	26
Nonregulated operations – solar | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	63	39	29
Nonregulated operations – thermal | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	151	159	141
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	(12)
Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers	5,598	5,011	5,055
Leasing revenue	7	6	6
Derivative revenue	0	0	0
Alternative revenue programs	115	157	75
Other revenue	34	14	28
Total operating revenues	5,754	5,188	5,164
Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,015	3,642	3,485
Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,516	1,311	1,479
Networks | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	67	58	91
Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,195	981	920
Leasing revenue	0	0	0
Derivative revenue	3	136	244
Alternative revenue programs	0	0	0
Other revenue	22	15	20
Total operating revenues	1,220	1,132	1,184
Renewables | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,028	822	803
Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	20	19	26
Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	63	39	29
Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 84	$ 101	$ 62

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Dec. 31, 2021USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 232
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	79
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	145
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	$ 39
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	$ 26
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	$ 43
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	$ 24
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 18
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 24
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	$ 9
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
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	$ 2
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 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	$ 3
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	$ 10
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	$ 2
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	$ 65
Remaining performance obligation, period

Industry Regulation - Additiona

Industry Regulation - Additional Information (Details) MWh in Millions

Jul. 14, 2021USD ($)

Jun. 23, 2021USD ($)

May 06, 2021USD ($)

Apr. 15, 2021

Dec. 31, 2020USD ($)MW

Nov. 19, 2020

May 21, 2020

Feb. 19, 2020USD ($)

Jan. 21, 2020

Dec. 09, 2019USD ($)

Nov. 21, 2019

Jan. 18, 2019

Sep. 10, 2018USD ($)

Jan. 01, 2017

Mar. 31, 2010USD ($)MW

Dec. 31, 2019MWhproject

Oct. 31, 2018agreementMW

Dec. 31, 2017

Mar. 31, 2017projectorder

Dec. 31, 2016

Dec. 31, 2021USD ($)company

Apr. 30, 2019

Jun. 30, 2021USD ($)hour

Jul. 16, 2020USD ($)

Jan. 31, 2018USD ($)

Public Utilities, General Disclosures [Line Items]

Number of networks supply companies | company

8

Direct Current Fast Charger incentive program, approved amount

$ 700,000,000

Approved return on equity

10.02%

9.88%

Equity ratio

50.00%

54.00%

3.00%

Rate plan modification, overall bill impact limit, percent

2.00%

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

60.00%

Public utilities regulatory authority distribution rate

9.70%

Number of REV related orders issued | order

3

Number of energy storage projects | project

2

Regulatory assets

$ 2,882,000,000

$ 2,647,000,000

$ 11,000,000

Number of average months used to set rate

13 months

Restricted net assets

$ 5,808,000,000

Purchase obligation per year

$ 2,433,000,000

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

DEEP

Public Utilities, General Disclosures [Line Items]

PPA capacity (in MWH) | MWh

12

PURA

Public Utilities, General Disclosures [Line Items]

Equity ratio

50.00%

Percentage of return on equity (ROE)

9.10%

9.30%

New distribution rate schedule, period

3 years

Public utilities regulatory authority distribution rate

50.00%

Equity ratio, year one

54.00%

Equity ratio, year two

54.50%

Equity ratio, year three

55.00%

Power Tax

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

32 years 6 months

Depreciation amortization period

32 years 6 months

Storm costs

Public Utilities, General Disclosures [Line Items]

Regulatory assets

451,000,000

$ 448,000,000

Federal tax depreciation normalization adjustment

Public Utilities, General Disclosures [Line Items]

Regulatory assets

$ 148,000,000

142,000,000

Central Maine Power

Public Utilities, General Disclosures [Line Items]

Distribution revenue requirement

$ 17,000,000

Annual distribution tariff increase percentage

7.00%

Distribution tariff rate increased based on ROE

9.25%

Distribution tariff rate increased based on equity capital

50.00%

ROE reduction

1.00%

Proposed distribution tariff rate decrease based on return on equity

8.25%

Customer service performance period

18 months

SCG

Public Utilities, General Disclosures [Line Items]

Equity ratio

52.00%

Percentage of return on equity (ROE)

9.25%

NYDPS

Public Utilities, General Disclosures [Line Items]

Equity ratio for earnings sharing

48.00%

Percentage of return on equity (ROE)

8.80%

United Illuminating Company (UI)

Public Utilities, General Disclosures [Line Items]

ROE reduction

0.15%

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

$ 200,000,000

Period of purchase commitment

21 years

Solicitation period

6 years

Maximum annual commitment level obligation after year six

$ 14,000,000

Additional maximum annual commitment

$ 64,000,000

Number of power purchase agreements | agreement

5

Proposed off shore wind capacity (in MW) | MW

50

Number of projects | project

11

Vineyard Wind

Public Utilities, General Disclosures [Line Items]

Proposed off shore wind capacity (in MW) | MW

804

CMP

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

20 years

Wind farm capacity (in MW) | MW

60

Purchase obligation per year

$ 7,000,000

CMP | Dirigo Solar, LLC

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase obligation per year

$ 4,000,000

CMP | Maine Aqua Ventus I GP LLC

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase obligation per year

$ 12,000,000

NYSEG Electric

Public Utilities, General Disclosures [Line Items]

Approved return on equity

9.00%

Equity ratio

48.00%

Equity ratio for earnings sharing

50.00%

Recovery of deferred storm costs

$ 262,000,000

NYSEG Electric | Storm costs, ten year recovery

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

123,000,000

NYSEG Electric | Storm costs, five year recovery

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

139,000,000

NYSEG Electric | Deferred Storm Cost Amortization 1 Year

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

$ 26,000,000

NYSEG Electric | Storm costs

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

10 years

Depreciation amortization period

10 years

NYSEG Electric | Regulatory Items Other Than Storm Costs

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

5 years

Depreciation amortization period

5 years

NYSEG Gas

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

50.00%

Percentage of return on equity (ROE)

9.75%

RG&E Electric

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

75.00%

Percentage of return on equity (ROE)

10.25%

RG&E Electric | Deferred Storm Cost Amortization 1 Year

Public Utilities, General Disclosures [Line Items]

Amortization of deferred storm cost

$ 3,000,000

RG&E Gas

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

90.00%

Percentage of return on equity (ROE)

10.75%

NYSEG and RG&E

Public Utilities, General Disclosures [Line Items]

Direct Current Fast Charger incentive program, approved amount

$ 118,000,000

Industry Regulation - Rate Incr

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

Industry Regulation - Rate In_2

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

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Regulatory Assets Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Regulated Operations [Abstract]
Unrecorded regulatory assets	$ 1,136
Regulatory Assets [Line Items]
Unfunded future income tax expense collection period	46 years
Central Maine Power
Regulatory Assets [Line Items]
Deferred income tax recovery period	32 years 6 months

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Schedule of Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Jan. 31, 2018
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,647	$ 2,882	$ 11
Less: current portion	400	310
Total non-current regulatory assets	2,247	2,572
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	545	927
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	95	105
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	448	451
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	68	33
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	68	58
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	15	31
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	73	86
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	24	20
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	2	3
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	52	30
Deferred transmission expense
Regulatory Assets [Line Items]
Total regulatory assets	13	26
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	256	247
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	71	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	424	373
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	142	148
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	21
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	46	33
COVID-19 cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	21	1
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 241	$ 180

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,329	$ 3,411
Less: current portion	307	274
Regulatory liabilities	3,022	3,137
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	45	58
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	3
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	73	59
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	34
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	11
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,327	1,435
Rate change levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	99	55
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	9
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,192	1,184
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	7
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	26	28
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	30
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	6	10
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	31
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	20
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	49	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	23	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
Earnings sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	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	25	28
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	14
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	5	9
Hedges gains
Regulatory Liabilities [Line Items]
Total regulatory liabilities	19	0
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 194	$ 176

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Regulatory Liabilities Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
UIL Holdings
Regulatory Liabilities [Line Items]
Business combination merger related rate credits	$ 2	$ 2
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Rate change levelization
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Positive benefit adjustment | Min.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Positive benefit adjustment | Max.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Theoretical reserve flow thru impact | Min.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Theoretical reserve flow thru impact | Max.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Deferred property tax
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Net plant reconciliation
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
NYSEG and RG&E | Economic development
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
NYSEG | Asset sale gain account
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
RG&E | Asset sale gain account
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	2 years

Goodwill and Intangible asset_2

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Goodwill [Line Items]
Goodwill	$ 3,119	$ 3,119
Networks
Goodwill [Line Items]
Goodwill	2,747	2,747
Renewables
Goodwill [Line Items]
Goodwill	$ 372	$ 372

Goodwill and Intangible asset_3

Goodwill and Intangible assets - Additional Information (Details)	Dec. 16, 2015USD ($)	Dec. 31, 2021USD ($)reportingUnit	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2002USD ($)	Dec. 31, 2000USD ($)
Goodwill [Line Items]
Impairment of goodwill		$ 0	$ 0
Amortization expense		$ 13,000,000	$ 14,000,000	$ 15,000,000
Maine Reporting Unit
Goodwill [Line Items]
Goodwill						$ 325,000,000
New York Reporting Unit
Goodwill [Line Items]
Goodwill					$ 654,000,000
UIL Reporting Unit
Goodwill [Line Items]
Goodwill	$ 1,768,000,000
Networks
Goodwill [Line Items]
Number of reporting units | reportingUnit		3

Goodwill and Intangible asset_4

Goodwill and Intangible assets - Summary of Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 610	$ 624
Accumulated Amortization	(317)	(319)
Net Carrying Amount	293	305
Wind development
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	592	593
Accumulated Amortization	(301)	(290)
Net Carrying Amount	291	303
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	18	31
Accumulated Amortization	(16)	(29)
Net Carrying Amount	$ 2	$ 2

Goodwill and Intangible asset_5

Goodwill and Intangible assets - Schedule of Amortization Expense (Details) $ in Millions	Dec. 31, 2021USD ($)
Year ending December 31,
2022	$ 14
2023	13
2024	13
2025	12
2026	$ 12

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 36,169	$ 34,142
Total accumulated depreciation	(10,589)	(9,799)
Total Net Property, Plant and Equipment in Service	25,580	24,343
Construction work in progress	3,286	2,408
Total Property, Plant and Equipment	28,866	26,751
Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	30,838	29,218
Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,045	4,650
Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	286	274
Regulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	22,424	21,001
Total accumulated depreciation	(5,806)	(5,363)
Total Net Property, Plant and Equipment in Service	16,618	15,638
Construction work in progress	2,064	1,384
Total Property, Plant and Equipment	18,682	17,022
Regulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	17,392	16,364
Regulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,032	4,637
Regulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	0	0
Nonregulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13,745	13,141
Total accumulated depreciation	(4,783)	(4,436)
Total Net Property, Plant and Equipment in Service	8,962	8,705
Construction work in progress	1,222	1,024
Total Property, Plant and Equipment	10,184	9,729
Nonregulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13,446	12,854
Nonregulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13	13
Nonregulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 286	$ 274

Property, Plant and Equipment_2

Property, Plant and Equipment - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Interest costs capitalized	$ 33,000,000	$ 51,000,000	$ 51,000,000
Accrued liabilities for property, plant and equipment additions	297,000,000	285,000,000	357,000,000
Tangible asset impairment charges	20,000,000	7,000,000	11,000,000
Depreciation	1,001,000,000	973,000,000	$ 918,000,000
New England Clean Energy Connect (NECEC) project, impairment	0
New England Clean Energy Connect (NECEC) project, capitalized amount	$ 546,000,000	$ 180,000,000

Asset retirement obligations -

Asset retirement obligations - Reconciliation of ARO (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 210	$ 190
Liabilities settled during the year	(2)	(2)
Liabilities incurred during the year	7	9
Accretion expense	12	11
Revisions in estimated cash flows	26	2
Ending Balance	$ 253	$ 210

Asset retirement obligations _2

Asset retirement obligations - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted cash	$ 3	$ 3

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Unamortized debt issuance costs and discount	$ (53)	$ (47)
Total Debt	8,294	7,791
Less: debt due within one year, included in current liabilities	372	313
Total Non-current Debt	7,922	7,478
First mortgage bonds - fixed
Debt Instrument [Line Items]
Long-term debt	2,759	$ 2,575
Bond pledged as collateral	$ 7,871
First mortgage bonds - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.85%	1.85%
First mortgage bonds - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	8.00%	8.00%
Unsecured pollution control notes - fixed
Debt Instrument [Line Items]
Long-term debt	$ 478	$ 478
Unsecured pollution control notes - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.40%	1.40%
Unsecured pollution control notes - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	3.50%	3.50%
Other various non-current debt - fixed
Debt Instrument [Line Items]
Long-term debt	$ 5,110	$ 4,785
Other various non-current debt - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.95%	1.95%
Other various non-current debt - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	6.66%	7.80%

Debt - Additional Information (

Debt - Additional Information (Details)	Nov. 23, 2021USD ($)	Dec. 31, 2021USD ($)	Nov. 22, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 14, 2020USD ($)
Debt Instrument [Line Items]
Estimated fair value of debt		$ 9,155,000,000		$ 12,166,000,000
Commercial paper		0		309,000,000
Notes payable		159,000,000		307,000,000
Supplier Financing Arrangements
Debt Instrument [Line Items]
Notes payable		$ 161,000,000		$ 0
Weighted-average interest rate		0.82%
Commercial Paper
Debt Instrument [Line Items]
Weighted-average interest rate				0.32%
Subordinated Debt | Iberdrola Loan
Debt Instrument [Line Items]
Debt instrument principal amount					$ 3,000,000,000
AVANGRID Credit Facility
Debt Instrument [Line Items]
Credit facility remaining borrowing capacity		$ 3,575,000,000
Line of credit facility, maximum borrowing capacity	$ 4,000,000,000
Debt covenant, ratio of consolidated debt to consolidated total capitalization	0.65
Line of credit borrowing outstanding		0
AVANGRID Credit Facility | Min.
Debt Instrument [Line Items]
Credit facility fees percentage	0.10%
AVANGRID Credit Facility | Max.
Debt Instrument [Line Items]
Credit facility fees percentage	0.225%
AVANGRID Credit Facility | Commercial Paper
Debt Instrument [Line Items]
Commercial paper		2,000,000,000
AVANGRID Credit Facility Sublimit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 2,500,000,000		$ 1,500,000,000
2020 Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 500,000,000
Iberdrola Group Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 500,000,000
Credit facility fees percentage		0.105%
Credit facility amount drawn		$ 0		$ 0

Debt - Other 2021 Long-Term Deb

Debt - Other 2021 Long-Term Debt Issuances (Details) - USD ($) $ in Millions	Dec. 15, 2021	Sep. 24, 2021
Unsecured Notes | NYSEG | 2.15% Unsecured Notes Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount		$ 350
Debt instrument, interest rate		2.15%
First Mortgage Bonds | RG&E | 2.91% First Mortgage Bonds Due 2051
Debt Instrument [Line Items]
Debt instrument principal amount	$ 125
Debt instrument, interest rate	2.91%
First Mortgage Bonds | RG&E | 2.10% First Mortgage Bonds Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount	$ 125
Debt instrument, interest rate	2.10%
First Mortgage Bonds | CMP | 2.05% First Mortgage Bonds Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount	$ 200
Debt instrument, interest rate	2.05%
First Mortgage Bonds | SCG | 2.05% First Mortgage Bonds Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount	$ 40
Debt instrument, interest rate	2.05%

Debt - Schedule of Long-term _2

Debt - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2021USD ($)
Debt Disclosure [Abstract]
2022	$ 372
2023	439
2024	612
2025	1,107
2026	660
Total	$ 3,190

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 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	$ 3	$ 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	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	$ 60	$ 63
Netting adjustment	(110)	(89)
Derivative assets	94	97
Netting adjustment	194	81
Derivative liabilities	(224)	(96)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(78)	(54)
Derivative assets	77	87
Netting adjustment	176	72
Derivative liabilities	(67)	(5)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(32)	(35)
Derivative assets	15	8
Netting adjustment	18	9
Derivative liabilities	(5)	(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	(75)	(88)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0
Derivative assets	0
Netting adjustment	0	0
Derivative liabilities	(77)	0
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	45	49
Derivative assets, before netting	35	5
Derivative liabilities, before netting	(17)	(24)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	31	5
Derivative liabilities, before netting	(16)	(23)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	4	0
Derivative liabilities, before netting	(1)	(1)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 1 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0
Derivative liabilities, before netting	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	15	14
Derivative assets, before netting	73	55
Derivative liabilities, before netting	(236)	(40)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	39	31
Derivative liabilities, before netting	(137)	(31)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	34	24
Derivative liabilities, before netting	(22)	(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	0
Derivative liabilities, before netting	(77)	0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	0	0
Derivative assets, before netting	96	126
Derivative liabilities, before netting	(165)	(113)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	85	105
Derivative liabilities, before netting	(90)	(23)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	9	19
Derivative liabilities, before netting	0	(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	(75)	(88)
Level 3 | 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	$ 0

Fair Value of Financial Instr_5

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value as of January 1,	$ 13	$ 25	$ (15)
Gains for the year recognized in operating revenues	21	8	53
Losses for the year recognized in operating revenues	(34)	(2)	(2)
Total gains or losses for the period recognized in operating revenues	(13)	6	51
Gains recognized in OCI	2	1	2
Losses recognized in OCI	(52)	(3)	(3)
Total gains or losses recognized in OCI	(50)	(2)	(1)
Net change recognized in regulatory assets and liabilities	13	6	5
Purchases	(17)	(2)	(22)
Settlements	(13)	(15)	4
Transfers out of Level 3 (a)	(2)	(5)	3
Fair value as of December 31,	(69)	13	25
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$ (13)	$ 6	$ 51

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price	Dec. 31, 2021$ / MWh$ / kilowatt-MonthOfEnergy
Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate | $ / kilowatt-MonthOfEnergy	4.80
Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate | $ / kilowatt-MonthOfEnergy	2
NYMEX | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	3.18
NYMEX | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	6.52
NYMEX | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.27
AECO | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.41
AECO | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	5.69
AECO | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	1.53
Ameren | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	32.23
Ameren | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	93.59
Ameren | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	18.01
COB | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	46.83
COB | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	231.90
COB | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	9.15
ComEd | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	29.60
ComEd | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	86.32
ComEd | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	14.98
ERCOT N hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	35.05
ERCOT N hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	140
ERCOT N hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	13.66
ERCOT S hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	34.24
ERCOT S hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	140
ERCOT S hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	13.88
Indiana hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	34.20
Indiana hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	93.81
Indiana hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	20.74
Mid C | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	43.53
Mid C | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	229.90
Mid C | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	5.15
Minn hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	28.82
Minn hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	90.99
Minn hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	15.23
Noil hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	29.35
Noil hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	84
Noil hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	14.64
PJM W hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	33.49
PJM W hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	113.93
PJM W hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	17.78

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details)	Dec. 31, 2021$ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0039
Min. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0097
Min. | Measurement Input, Commodity Forward Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2
Max. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0051
Max. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0126
Max. | Measurement Input, Commodity Forward Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	4.80

Derivative Instruments and He_3

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 94	$ 97
Derivative Liability	(224)	(96)
Cash collateral (payable) receivable, asset	(67)	(18)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	17	0
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	17	0
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	29	3
Derivative liabilities	(12)	(3)
Derivative Asset	17	0
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	3	1
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	3	1
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	7	5
Derivative liabilities	(4)	(4)
Derivative Asset	3	1
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(16)	(32)
Cash collateral (payable) receivable, liability	0	18
Total derivatives as presented in the balance sheet	(16)	(14)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	12	3
Derivative liabilities	(27)	(34)
Derivative Liability	(15)	(31)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	(1)	(1)
Derivative Liability	(1)	(1)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(60)	(75)
Cash collateral (payable) receivable, liability	0	1
Total derivatives as presented in the balance sheet	(60)	(74)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	3
Derivative liabilities	(64)	(78)
Derivative Liability	(60)	(75)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Liability	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	18	27
Cash collateral (payable) receivable, asset	0	(9)
Total derivatives as presented in the balance sheet	18	18
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	29	47
Derivative liabilities	(11)	(23)
Derivative Asset	18	24
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	8
Derivative liabilities	0	(5)
Derivative Asset	0	3
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	56	96
Cash collateral (payable) receivable, asset	0	(18)
Total derivatives as presented in the balance sheet	56	78
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	70	89
Derivative liabilities	(14)	(2)
Derivative Asset	56	87
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	15
Derivative liabilities	0	(6)
Derivative Asset	0	9
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(75)	(3)
Cash collateral (payable) receivable, liability	27	0
Total derivatives as presented in the balance sheet	(48)	(3)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	52	2
Derivative liabilities	(65)	(4)
Derivative Liability	(13)	(2)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	2
Derivative liabilities	(67)	(3)
Derivative Liability	(62)	(1)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(138)	(5)
Cash collateral (payable) receivable, liability	57	0
Total derivatives as presented in the balance sheet	(81)	(5)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	9	9
Derivative liabilities	(11)	(11)
Derivative Liability	(2)	(2)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	6	7
Derivative liabilities	(142)	(10)
Derivative Liability	$ (136)	$ (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	12 Months Ended
	Dec. 31, 2021USD ($)MWhMMBTUgal	Dec. 31, 2020USD ($)MMBTUMWhgal
Networks | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	5.7	5.6
Networks | Natural gas purchase contracts (Dth) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	9.4	9.5
Networks | Fleet fuel purchase contracts (Gallons) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount | gal	2	2.5
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 0	$ 88
Renewables | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	4	3
Derivative assets (liabilities), fair value	$ 36	$ 4
Renewables | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	10	7
Derivative assets (liabilities), fair value	$ (77)	$ 11
Renewables | Natural gas and other fuel purchase contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	20	24
Derivative assets (liabilities), fair value	$ 6	$ 0
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	9	12
Derivative assets (liabilities), fair value	$ 35	$ 66
Renewables | Basis Swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	30	35
Derivative assets (liabilities), fair value	$ 0	$ 7
Renewables | Basis Swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	0	2

Derivative Instruments and He_5

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 0	$ 0	$ (3)
Derivative Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	13	6	8
Electricity
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			25
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	17
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(23)	55
Electricity | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	(16)	0
Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			$ 1
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	1
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(11)	4
Natural Gas | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ (3)	$ 0

Derivative Instruments and He_6

Derivative Instruments and Hedging - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021USD ($)instrument	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Sep. 15, 2021USD ($)	Jul. 15, 2021USD ($)	May 27, 2021USD ($)	Jun. 20, 2019USD ($)	Jan. 31, 2018USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 2,647,000,000	$ 2,882,000,000						$ 11,000,000
Regulatory liabilities	3,329,000,000	3,411,000,000
Gain (loss) recognized in OCI on derivatives	(200,000,000)
Derivative liabilities	160,000,000	79,000,000
Gain on derivative			$ 43,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months	(9,000,000)
Loss (Gain) Reclassified from Accumulated OCI into Income	(3,000,000)
Derivative liability	224,000,000	96,000,000
Derivative collateral obligation to be paid in decrease in credit rating below investment grade	19,000,000
Cash collateral pledged	67,000,000	18,000,000
Derivative with credit risk contingent features, liability, fair value	0
Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain on foreign currency contracts not designated as hedging instruments	$ 0	4,000,000
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of instruments held | instrument	2
Derivative liability	$ 75,000,000	88,000,000
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(9,000,000)	(8,000,000)	(2,000,000)
Cash Flow Hedging | Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	48,000,000	57,000,000
Fair Value Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability					$ 750,000,000
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(3,000,000)	0	(1,000,000)
Loss (Gain) Reclassified from Accumulated OCI into Income	3,000,000	5,000,000	7,000,000
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Forward contract to hedge foreign currency exchange risk							$ 100,000,000
Gain (loss) recognized in OCI on derivatives	(4,000,000)	(4,000,000)	$ (6,000,000)
Expected amortization of discontinued cash flow hedges, next fiscal year	(4,000,000)
Unrealized loss	1,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months	(5,000,000)
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	$ 47,000,000	51,000,000
Networks | Cash Flow Hedging | Fuel Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum length of time hedged in cash flow hedge	12 months
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 59,000,000
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount				$ 956,000,000		$ 935,000,000
Derivative liabilities	$ 58,000,000
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	20.00%
Derivative assets	$ 2,000,000	2,000,000
Regulatory assets	73,000,000	86,000,000
Derivative liabilities	75,000,000	88,000,000
Regulatory liabilities	$ 0	0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	80.00%
Derivative assets	$ 0	0
Derivative liabilities	$ 72,000,000	$ 85,000,000

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	$ (200)
Loss (Gain) Reclassified from Accumulated OCI into Income	(3)
Interest expense	298	$ 316	$ 310
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Operating revenues	6,974	6,320	6,336
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(3)	0	(1)
Loss (Gain) Reclassified from Accumulated OCI into Income	3	5	7
Operating revenues	5,754	5,188	5,164
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,220	1,132	1,184
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	(27)	(24)
Interest rate contracts | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	9	8	2
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	4	4	6
Interest rate contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(58)
Operating revenues	298
Interest rate contracts | Renewables | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	0
Commodity contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	2	(1)	0
Loss (Gain) Reclassified from Accumulated OCI into Income	(1)	1	1
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(142)	1	(5)
Commodity contracts | Renewables | Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	(3)	6	3
Operating revenues	6,974	6,320	6,336
Foreign currency exchange contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(5)	1	(1)
Loss (Gain) Reclassified from Accumulated OCI into Income	$ 0	$ 0	$ 0

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 0	$ 88
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	35	66
Long | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	36	4
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	6	0
Long | Basis Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	0	7
Short | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (77)	$ 11

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non Trading Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			$ 43
Operating revenues	$ 6,974	$ 6,320	6,336
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,220	1,132	1,184
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	2	0	(2)
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(57)	(5)	78
Renewables | Operating Revenues | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	2	0	(2)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	1	(1)	(1)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(2)	(1)	3
Renewables | Operating Revenues | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	4	2	(3)
Renewables | Operating Revenues | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(1)	0	(1)
Renewables | Operating Revenues | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(101)	(7)	64
Operating revenues	6,974	6,320	6,336
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(1)	0	0
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(33)	6	40
Renewables | Operating Revenues | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(42)	0	23
Renewables | Operating Revenues | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(25)	(13)	1
Renewables | Purchased power, natural gas and fuel used | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Purchased power, natural gas and fuel used | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	44	2	14
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Renewables | Purchased power, natural gas and fuel used | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	32	(4)	(1)
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 12	$ 6	$ 15

Derivative Instruments and H_10

Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged asset, fair value hedge	$ 0
Hedged liability, fair value hedge	(19)
(Gain) Recognized in Income Statement	(3)
Fair Value Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Year to date total per Income Statement	298
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	0
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	$ 19

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Renewal term	40 years
Finance lease liabilities	$ 95	$ 99
Renewables
Lessee, Lease, Description [Line Items]
Finance lease liabilities	$ 45	$ 47
Finance lease term	15 years
Early buyout option term	10 years
Renewables | Generation Facility
Lessee, Lease, Description [Line Items]
Useful life of facility	25 years
Min.
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Max.
Lessee, Lease, Description [Line Items]
Remaining lease term	62 years

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Finance lease cost
Amortization of right-of-use assets	$ 8	$ 17	$ 12
Interest on lease liabilities	3	4	3
Total finance lease cost	11	21	15
Operating lease cost	14	16	18
Short-term lease cost	4	3	5
Variable lease cost	4	0	2
Sublease income	0	0	0
Total lease cost	$ 33	$ 40	$ 40

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
Operating lease right-of-use assets	$ 148	$ 153
Operating lease liabilities, current	12	8
Operating lease liabilities, long-term	149	154
Total operating lease liabilities	161	162
Finance Leases
Other assets	$ 156	$ 162
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Other current liabilities	$ 4	$ 8
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Other non-current liabilities	$ 91	$ 91
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Total finance lease liabilities	$ 95	$ 99
Weighted-average Remaining Lease Term (years)
Finance leases	7 years 3 months 18 days	8 years 1 month 13 days
Operating leases	20 years 6 months	21 years 4 months 17 days
Weighted-average Discount Rate
Finance leases	3.49%	3.71%
Operating leases	3.06%	3.21%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 16	$ 13	$ 13
Operating cash flows from finance leases	3	3	3
Repayments of financing leases	6	9	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	0	46	1
Operating leases	$ 10	$ 94	$ 3

Leases - Lease Maturities (Deta

Leases - Lease Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Finance Leases
2022	$ 5
2023	53
2024	23
2025	2
2026	2
Thereafter	19
Total lease payments	104
Less: imputed interest	(9)
Total	95	$ 99
Operating Leases
2022	14
2023	14
2024	12
2025	11
2026	11
Thereafter	160
Total lease payments	223
Less: imputed interest	(62)
Total	$ 161	$ 162

Commitments and Contingent Li_3

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

Nov. 20, 2020violation

May 21, 2020

Nov. 21, 2019complaint

Jan. 11, 2019complaint

Mar. 22, 2016

Mar. 03, 2015

Oct. 16, 2014

Sep. 30, 2011

Apr. 30, 2018

Dec. 31, 2021USD ($)projectMW

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

10.02%

9.88%

Regulatory liabilities

$ 3,022

$ 3,137

Number of complaints | complaint

2

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

$ 483

Payment in lieu of taxes (pilot) agreement, number of projects | project

2

Payment In Lieu of Taxes (PILOT) agreement, payment amount

$ 1

NECEC commitment, amount

$ 90

NECEC commitment, payment during period

9

Max.

Loss Contingencies [Line Items]

Show cause order settlement payment

$ 5

Complaint III

Loss Contingencies [Line Items]

Regulatory liabilities

8

Complaint II

Loss Contingencies [Line Items]

Regulatory liabilities

27

Complaint II and III

Loss Contingencies [Line Items]

Reasonably possible loss, in additional reserve, pre tax

$ 17

California Energy Crisis Litigation

Loss Contingencies [Line Items]

Price of the PPAs

$ 259

Requested renewables delay from preliminary proposed ruling period

2 years

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Approved return on equity

10.57%

Number of complaints | complaint

4

Unfavorable Regulatory Action | Complaint I | Max.

Loss Contingencies [Line Items]

Approved return on equity

10.42%

11.74%

11.74%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Unfavorable Regulatory Action | Complaint III | Max.

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Unfavorable Regulatory Action | Complaint II

Loss Contingencies [Line Items]

Approved return on equity

9.59%

Refund period

15 months

Before Amendment

Loss Contingencies [Line Items]

Requested return on equity base percentage

11.14%

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

Loss Contingencies [Line Items]

Power purchase commitment | MW

95.6

Period of purchase commitment

3 years

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

Loss Contingencies [Line Items]

Power purchase commitment | MW

52

Period of purchase commitment

5 years

2042 | Power purchase commitments | Hydro Capacity And Energy

Loss Contingencies [Line Items]

Power purchase commitment | MW

150

Vineyard Wind

Loss Contingencies [Line Items]

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

$ 21

Commitments and Contingent Li_4

Commitments and Contingent Liabilities - Schedule of Forward Purchases and Sales Commitments Under Power, Gas, and Other Arrangements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)
Purchases
2022	$ 1,069
2023	168
2024	111
2025	65
2026	49
Thereafter	971
Totals	2,433
Sales
2022	227
2023	122
2024	75
2025	28
2026	37
Thereafter	72
Totals	$ 561

Environmental Liabilities (Deta

Environmental Liabilities (Details)	12 Months Ended			65 Months Ended
	Dec. 31, 2021USD ($)site	Dec. 31, 2011site	Dec. 31, 2008site	Dec. 31, 2021USD ($)	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 | $	$ 303,000,000			$ 303,000,000	$ 300,000,000
Accrual related to investigation and remediation, amount recorded to date | $				35,000,000
First Energy
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
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
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 | $	$ 113,000,000			113,000,000	$ 96,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	162,000,000			162,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	276,000,000			276,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 0			0
MGP Sites | First Energy
Environmental Exit Cost [Line Items]
Number of sites in dispute			2
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
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 | $	14,000,000			14,000,000
Another Ten Sites | Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	22,000,000			22,000,000
NYSEG | First Energy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	14,000,000			14,000,000
RG&E | First Energy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 7,000,000			$ 7,000,000

Income Taxes - Schedule of Curr

Income Taxes - Schedule of Current and Deferred Taxes Charged to (Benefit) Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current
Federal	$ 6	$ 3	$ 11
State	4	9	(6)
Current taxes charged to expense	10	12	5
Deferred
Federal	49	67	164
State	72	38	58
Deferred taxes charged to expense	121	105	222
Production tax credits	(109)	(87)	(57)
Investment tax credits	(1)	(1)	(1)
Total Income Tax Expense	$ 21	$ 29	$ 169

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 140	$ 119	$ 170
Depreciation and amortization not normalized	(19)	(13)	(23)
Investment tax credit amortization	(1)	(1)	(1)
Tax return related adjustments	0	1	(2)
Production tax credits	(109)	(87)	(57)
Tax equity financing arrangements	14	1	8
State tax expense (benefit), net of federal benefit	61	37	41
Excess ADIT amortization	(65)	(42)	0
Valuation allowance	21	12	4
Other, net	(21)	2	29
Total Income Tax Expense	$ 21	$ 29	$ 169

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Income Tax Liabilities (Assets)
Property related	$ 4,257	$ 4,147
Unfunded future income taxes	104	100
Federal and state tax credits	(844)	(731)
Federal and state NOL’s	(998)	(1,047)
Joint ventures/partnerships	188	167
Nontaxable grant revenue	(292)	(311)
Pension and other post-retirement benefits	1	22
Tax Act - tax on regulatory remeasurement	(352)	(382)
Valuation allowance	110	81
Other	(158)	(127)
Deferred Income Tax Liabilities	2,016	1,919
Deferred tax assets	2,644	2,598
Deferred tax liabilities	4,660	4,517
Net Accumulated Deferred Income Tax Liabilities	$ 2,016	$ 1,919

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Line Items]
Operating loss carryforwards, valuation allowance	$ 73
Deferred tax assets, valuation allowance	110	$ 81
Increase in valuation allowance, deferred tax asset	29
Unrecognized tax benefits that would impact effective tax rate	107
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	3,600
Increase in valuation allowance, deferred tax asset	21
Federal | Renewable Energy and Investment
Income Taxes [Line Items]
Tax credit carry forward	805
State
Income Taxes [Line Items]
Net operating loss carry forwards	314
Tax credit carry forward	146
Operating loss carryforwards, valuation allowance	37
Increase in valuation allowance, deferred tax asset	$ 8

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning Balance	$ 127	$ 148	$ 153
Increases for tax positions related to prior years	3	11	14
Increases for tax positions related to current year	0	0	16
Decreases for tax positions related to prior years	(3)	(32)	(18)
Reduction for tax position related to settlements with taxing authorities	0	0	(17)
Ending Balance	$ 127	$ 127	$ 148

Post-retirement and Similar O_3

Post-retirement and Similar Obligations - Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	$ 3,819	$ 3,669
Service cost	40	47
Interest cost	87	107
Plan amendments	2	7
Actuarial loss (gain)	(184)	236
Curtailments	(38)	(21)
Benefits paid	(239)	(226)
Benefit Obligation as of December 31,	3,487	3,819
Change in plan assets
Fair Value of Plan Assets as of January 1,	3,092	2,848
Actual return on plan assets	237	388
Employer contributions	27	84
Curtailments	(38)	(2)
Benefits paid	(239)	(226)
Fair Value of Plan Assets as of December 31,	3,079	3,092
Funded Status as of December 31,	(408)	(727)
Postretirement Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	452	439
Service cost	3	3
Interest cost	10	13
Plan amendments	0	0
Actuarial loss (gain)	(23)	29
Curtailments	0	0
Benefits paid	(34)	(32)
Benefit Obligation as of December 31,	408	452
Change in plan assets
Fair Value of Plan Assets as of January 1,	167	155
Actual return on plan assets	15	26
Employer contributions	12	18
Curtailments	0	0
Benefits paid	(67)	(32)
Fair Value of Plan Assets as of December 31,	127	167
Funded Status as of December 31,	$ (281)	$ (285)

Post-retirement and Similar O_4

Post-retirement and Similar Obligations - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021USD ($)trust	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Defined Benefit Plan Disclosure [Line Items]
Actuarial gain(loss) due to change in discount rates	$ 205	$ 276
Accumulated benefit obligation	$ 1,790	3,629
Amortization period	10 years
Annual contributions made	$ 58	49	$ 40
Non-Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Other current and other non-current liabilities	63	59
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	(184)	236
Expected contribution for pension benefit plans during 2021	22
Other current and other non-current liabilities	$ 408	$ 727
Plan assets, number of trust | trust	1
Pension Benefits | Return-Seeking assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	25.00%
Pension Benefits | Return-Seeking assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	60.00%
Pension Benefits | Liability-Hedging assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	40.00%
Pension Benefits | Liability-Hedging assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	75.00%
Pension Benefits | Equity Securities | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		49.00%
Pension Benefits | Equity Securities | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		69.00%
Pension Benefits | Fixed Income Investments | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		31.00%
Pension Benefits | Fixed Income Investments | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		51.00%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	$ (23)	$ 29
Expected contribution for pension benefit plans during 2021	11
Other current and other non-current liabilities	$ 281	$ 285
Plan assets, number of trust | trust	1
Postretirement Benefits | VEBA and 401(h) arrangements
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	54.00%

Post-retirement and Similar O_5

Post-retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	$ 0	$ 0
Non-current liabilities	(408)	(727)
Total	(408)	(727)
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(276)	(280)
Total	$ (281)	$ (285)

Post-retirement and Similar O_6

Post-retirement and Similar Obligations - Summary of Recognized as Regulatory Assets or Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 271	$ 610
Prior service cost (credit)	10	10
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	(18)	14
Prior service cost (credit)	$ (1)	$ (8)

Post-retirement and Similar O_7

Post-retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 16	$ 21
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ (5)	$ (7)

Post-retirement and Similar O_8

Post-retirement and Similar Obligations - Schedule of Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Retirement Benefits [Abstract]
Projected benefit obligation	$ 3,487	$ 3,819
Fair value of plan assets	3,079	3,092
Accumulated benefit obligation	1,790	3,629
Fair value of plan assets	$ 1,536	$ 3,092

Post-retirement and Similar O_9

Post-retirement and Similar Obligations - Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations Recognized (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Net Periodic Benefit Cost:
Service cost	$ 40	$ 47
Interest cost	87	107
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	16	21
Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	3
Interest cost	10	13
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	(5)	(7)
Networks | Pension Benefits
Net Periodic Benefit Cost:
Service cost	39	46	$ 41
Interest cost	86	106	128
Expected return on plan assets	(199)	(198)	(190)
Amortization of prior service cost (benefit)	2	1	(1)
Amortization of net loss	115	124	113
Settlement charge	6
Net Periodic Benefit Cost	49	79	91
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	0	(18)	0
Settlement charge	6	0	0
Net loss (gain)	(218)	46	80
Amortization of net loss	(115)	(124)	(113)
Current year prior service cost (credit)	2	7	(2)
Amortization of prior service (cost) benefit	(2)	(1)	1
Net loss (gain)	(339)	(90)	(34)
Total Recognized	(290)	(11)	57
Networks | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	3	3
Interest cost	10	13	16
Expected return on plan assets	(7)	(8)	(7)
Amortization of prior service cost (benefit)	(5)	(9)	(10)
Amortization of net loss	2	2	1
Settlement charge	0
Net Periodic Benefit Cost	3	1	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	0	0	0
Settlement charge	0	0	0
Net loss (gain)	(31)	11	13
Amortization of net loss	(2)	(2)	(1)
Current year prior service cost (credit)	1	0	0
Amortization of prior service (cost) benefit	5	9	10
Net loss (gain)	(27)	18	22
Total Recognized	(24)	19	25
ARHI | Pension Benefits
Net Periodic Benefit Cost:
Service cost	1	1	1
Interest cost	1	1	2
Expected return on plan assets	(2)	(2)	(2)
Amortization of net loss	2	2	1
Settlement charge	1	1	0
Net Periodic Benefit Cost	3	3	2
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlement charge	1	0	0
Net loss (gain)	(3)	1	0
Amortization of net loss	(2)	(2)	(1)
Amortization of prior service (cost) benefit	0	0	0
Net loss (gain)	(6)	(1)	(1)
Total Recognized	(3)	2	1
ARHI | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	0	0	0
Interest cost	0	0	0
Expected return on plan assets	0	0	0
Amortization of net loss	(1)	(1)	(1)
Settlement charge	0	0	0
Net Periodic Benefit Cost	(1)	(1)	(1)
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlement charge	1	0	0
Net loss (gain)	1	0	0
Amortization of net loss	1	1	1
Amortization of prior service (cost) benefit	0	0	(2)
Net loss (gain)	1	1	(1)
Total Recognized	$ 0	$ 0	$ (2)

Post-retirement and Similar _10

Post-retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.85%	2.34%
Rate of compensation increase - benefit obligations	3.53%	3.52%
Interest crediting rate	2.87%	2.87%
Discount rate - net periodic benefit	2.34%	3.01%	3.98%
Expected long-term return on plan assets	7.30%	7.30%	7.30%
Rate of compensation increase - net periodic benefit	3.52%	3.66%	3.79%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.66%	2.19%
Rate of compensation increase - benefit obligations	3.50%	3.50%
Discount rate - net periodic benefit	2.19%	2.99%	3.97%
Expected long-term return on plan assets	4.05%	5.09%	5.08%
Rate of compensation increase - net periodic benefit	3.50%	3.48%	3.50%

Post-retirement and Similar _11

Post-retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Details)	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
Min.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	5.00%	5.25%
Max.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.00%	7.25%

Post-retirement and Similar _12

Post-retirement and Similar Obligations - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2021USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	$ 217
2023	212
2024	214
2025	213
2026	215
2027 - 2031	1,057
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	30
2023	29
2024	29
2025	28
2026	27
2027 - 2031	$ 122

Post-retirement and Similar _13

Post-retirement and Similar Obligations - Fair Values of Pension Plan Assets by Asset Category (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 3,079	$ 3,092	$ 2,848
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	2,532	2,484
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	69	120
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	298	177
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	138	107
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	276	301
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	837	710
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	862	1,018
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	51	50
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	733	592
Pension Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	20	0
Pension Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	298	177
Pension Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	138	107
Pension Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	276	301
Pension Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Pension Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	6
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,799	1,892
Pension Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	49	120
Pension Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	837	710
Pension Benefits | Level 2 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	862	1,018
Pension Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	51	44
Pension Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	547	608
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	127	167	$ 155
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	125	164
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	6
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	101	141
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	3
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	4
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	9	9
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	103	142
Postretirement Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Postretirement Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	101	141
Postretirement Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	22	22
Postretirement Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	6
Postretirement Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	3
Postretirement Benefits | Level 2 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	4
Postretirement Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	9	9
Postretirement Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 2	$ 3

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	May 18, 2021	Dec. 31, 2019
Class of Stock [Line Items]
Treasury stock, shares (in shares)	112,543	413,782
Release of common stock held in trust (in shares)	301,239	72,028
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Number of shares repurchased during period (in shares)	694,148
Treasury shares (in shares)	997,983
Repurchases of common stock	$ 47	$ 14
Convertible Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares outstanding (in shares)	0	0
Common Stock
Class of Stock [Line Items]
Issuance of common stock (in shares)	77,883,713	42,777
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent	81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	$ 15,826	$ 15,539	$ 15,389
Change	(162)	(16)	(11)
Balance at end of period	19,961	15,826	15,539
Change in revaluation of defined benefit plans, net of income tax expense (benefit)	0	0	0
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit)	1	3	1
Unrealized loss from equity method investment, net of income tax benefit	(3)	0	0
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)	(44)	(7)	(9)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)	(3)	2	3
Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(1)	(1)
Balance at end of period			(1)
Change in revaluation of defined benefit plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(12)	(12)	(11)
Change	2	0	1
Balance at end of period	(10)	(12)	(12)
Change in revaluation of defined benefit plans, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			(2)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(20)	(7)	(6)
Change	(8)	(13)	(1)
Balance at end of period	(28)	(20)	(7)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			0
Unrealized loss from equity method investment, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	0	0	0
Change	(9)	0	0
Balance at end of period	(9)	0	0
Unrealized loss from equity method investment, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			0
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(35)	(13)	9
Change	(159)	(22)	(22)
Balance at end of period	(194)	(35)	(13)
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			0
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(44)	(63)	(64)
Change	12	19	11
Balance at end of period	(32)	(44)	(63)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			(10)
Loss on derivatives qualifying as cash flow hedges
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(79)	(76)	(55)
Change	(147)	(3)	(11)
Balance at end of period	(226)	(79)	(76)
Loss on derivatives qualifying as cash flow hedges | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			(10)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(111)	(95)	(72)
Change	(162)	(16)	(11)
Balance at end of period	$ (273)	$ (111)	(95)
Accumulated Other Comprehensive Loss | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			$ (12)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Numerator:
Net income attributable to AVANGRID, basic	$ 707	$ 581	$ 667
Net income attributable to AVANGRID, diluted	$ 707	$ 581	$ 667
Denominator:
Weighted average number of shares outstanding - basic (in shares)	358,086,621	309,494,939	309,491,082
Weighted average number of shares outstanding - diluted (in shares)	358,578,608	309,559,387	309,514,910
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)	$ 1.97	$ 1.88	$ 2.16
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.97	$ 1.88	$ 2.16

Variable Interest Entities (Det

Variable Interest Entities (Details) $ in Millions	Nov. 04, 2021USD ($)	Sep. 09, 2021USD ($)	Feb. 05, 2021agreementMW	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)				$ 39,504	$ 37,823
Liabilities of variable interest entities (VIEs)				19,543	21,997
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Proceeds from Sale of Interest in Partnership Unit	$ 199	$ 131
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		8
Noncontrolling interest in variable interest entity		$ 139
Proceeds from sale of interest in partnership unit, amount held in escrow	$ 8
Assets of variable interest entities (VIEs)				2,039	1,713
Liabilities of variable interest entities (VIEs)				$ 119	$ 107
Patriot Wind Farm LLC
Variable Interest Entity [Line Items]
Number of TEF agreements | agreement			4
Proposed wind farm and electricity transmission project capacity (in MW) | MW			688

Grants, Government Incentives_3

Grants, Government Incentives and Deferred Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	$ 1,204	$ 1,274
Disposals	0	(2)
Recognized in income	(74)	(68)
Balance at end of period	1,130	1,204
Government grants
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	1,190	1,258
Disposals	0	(2)
Recognized in income	(65)	(66)
Balance at end of period	1,125	1,190
Other deferred income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	14	16
Disposals	0	0
Recognized in income	(9)	(2)
Balance at end of period	$ 5	$ 14

Equity Method Investments (Deta

Equity Method Investments (Details)	Dec. 16, 2020USD ($)	Dec. 13, 2019USD ($)	Dec. 31, 2021USD ($)aplantjointVentureMW	Dec. 31, 2020USD ($)	Dec. 31, 2019MW	Dec. 31, 2018USD ($)	Dec. 31, 2021USD ($)aplantjointVentureMW	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)MW	Sep. 15, 2021USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 560,000,000	$ 668,000,000			$ 560,000,000	$ 668,000,000
Distribution of earnings from equity method investments							21,000,000	22,000,000	$ 17,000,000
Equity method investment, distributions received in RECs							11,000,000	14,000,000	9,000,000
Undistributed earnings from equity method investees			10,000,000				10,000,000
Capitalized interest costs							6,000,000	8,000,000	7,000,000
South Dokata Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 24,000,000		$ 23,000,000	24,000,000			23,000,000	24,000,000
Enterprise value	$ 298,000,000
Gain related to remeasurement of retained investment							$ 4,000,000
Equity method investment, ownership percentage			15.00%				15.00%
South Dokata Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold	85.00%
Consideration from disposition	$ 238,000,000
Gain on sale of business, net of tax	12,000,000
Gain on sale of business, pre-tax	$ 16,000,000
Effective percentage of economic benefits retained	7.97%
Arizona Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 96,000,000	104,000,000			$ 96,000,000	104,000,000
Equity method investment, ownership percentage			50.00%				50.00%
Arizona Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold		50.00%
Consideration from disposition		$ 112,000,000
Gain on sale of business, net of tax		96,000,000
Gain on sale of business, pre-tax		134,000,000
Net gain related to remeasurement of retained investment		$ 50,000,000
Coyote Ridge Wind LLC
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold						80.00%				80.00%
Equity method investments			$ 15,000,000	16,000,000			$ 15,000,000	16,000,000
Equity method investment, ownership percentage			20.00%				20.00%
Proceeds from sale of portion of subsidiary						$ 144,000,000			84,000,000
Gain (loss) on sale of equity method investee									$ 4,000,000	$ 10,000,000
Horizon Wind Energy LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%				50.00%
Number of joint ventures | jointVenture			2				2
Flat Rock Wind Power LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 93,000,000	98,000,000			$ 93,000,000	98,000,000
Leased are transmission capacity (in MW) | MW							231
Flat Rock Wind Power II LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments			44,000,000	47,000,000			$ 44,000,000	47,000,000
Leased are transmission capacity (in MW) | MW							91
Vineyard Wind
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 141,000,000	$ 245,000,000			$ 141,000,000	$ 245,000,000
Equity method investment, ownership percentage			50.00%				50.00%
Area of land | a			166,886				166,886
Proposed wind farm and electricity transmission project capacity (in MW) | MW			1,232		804					800
Vineyard Wind | AVANGRID Renewables
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage				50.00%				50.00%
Amount funded to date				$ 33,000,000				$ 100,000,000
Joint Venture With CIP
Schedule of Equity Method Investments [Line Items]
Amount of guaranty issued											$ 827,000,000
Amount contributed to acquire easement contract, returned											152,000,000
Joint Venture With CIP | Letter of Credit
Schedule of Equity Method Investments [Line Items]
Credit facility maximum borrowing capacity											1,200,000,000
Joint Venture With CIP | Renewables
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%				50.00%
Joint venture restructuring agreement, payment amount											$ 168,000,000
Joint Venture With CIP | Renewables | Min.
Schedule of Equity Method Investments [Line Items]
Joint venture restructuring agreement, gain expected to recognize			$ 175,000,000				$ 175,000,000
Joint Venture With CIP | Renewables | Max.
Schedule of Equity Method Investments [Line Items]
Joint venture restructuring agreement, gain expected to recognize			200,000,000				200,000,000
Clearway Energy, Inc
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 99,000,000	104,000,000			$ 99,000,000	104,000,000
Equity method investment, ownership percentage			50.00%				50.00%
Number of peaking generation plants | plant			2				2
New York TransCo.
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 49,000,000	30,000,000			$ 49,000,000	30,000,000
Equity method investment, ownership percentage			20.00%				20.00%
Leased are transmission capacity (in MW) | MW							3,200
Amount funded to date							$ 600,000,000	600,000,000
Portion of amount receivable from related parties			$ 0	$ 0			$ 0	$ 0

Other Financial Statements It_3

Other Financial Statements Items - Schedule of Other Income and (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gain on sale of assets	$ 0	$ 20	$ 148
Allowance for funds used during construction	88	56	46
Carrying costs on regulatory assets	17	28	21
Non-service component of net periodic benefit cost	(37)	(62)	(79)
Other	(8)	(24)	(15)
Total Other Income (Expense)	$ 60	18	121
Tatanka Project
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee		$ 16
Poseidon Project
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee			$ 134

Other Financial Statements It_4

Other Financial Statements Items - Schedule of Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Trade receivables and unbilled revenues	$ 1,420	$ 1,295
Allowance for credit losses	(151)	(108)	$ (69)	$ (62)
Total Accounts receivable and unbilled revenues, net	$ 1,269	$ 1,187

Other Financial Statements It_5

Other Financial Statements Items - Schedule of Change in Allowance For Bad Debts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 108	$ 69	$ 62
Current period provision	110	83	92
Write-off as uncollectible	(67)	(44)	(85)
Ending balance	$ 151	$ 108	$ 69

Other Financial Statements It_6

Other Financial Statements Items - Additional Information (Details) $ in Millions	May 13, 2021USD ($)project	Dec. 31, 2021USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)	Dec. 31, 2018USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for credit losses		$ 151	$ 108	$ 69	$ 62
Sale of Business | Solar Projects In Nevada
Accounts, Notes, Loans and Financing Receivable [Line Items]
Percentage disposed	100.00%
Number of projects disposed | project	2
Consideration from disposition	$ 35
Gain on disposal, net of tax	11
Pre-tax gain on disposal	$ 15
Deferred Payment Arrangements
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable		108	78
Allowance for credit losses		$ 68	$ 48

Other Financial Statements It_7

Other Financial Statements Items - Schedule of Prepayments and Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid other taxes	$ 95	$ 135
Short-term investment	0	300
Broker margin and collateral accounts	87	30
Other pledged deposits	4	2
Prepaid expenses	58	41
Other	1	17
Total	$ 245	$ 525

Other Financial Statements It_8

Other Financial Statements Items - Schedule of Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Advances received	$ 204	$ 141
Accrued salaries	127	109
Short-term environmental provisions	52	49
Collateral deposits received	58	42
Pension and other postretirement	5	5
Finance leases	4	8
Other	34	14
Total	$ 484	$ 368

Segment Information - Additiona

Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 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	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Operating Revenues	$ 6,974	$ 6,320	$ 6,336
Depreciation and amortization	1,014	987	933
Operating income	895	869	998
(Losses) earnings from equity method investments	7	(3)	3
Interest expense, net of capitalization	298	316	310
Income tax expense (benefit)	21	29	169
Capital expenditures	2,976	2,781	2,735
Adjusted net income	780	625	640
Property, plant and equipment	28,866	26,751
Equity method investments	560	668
Total assets	39,504	37,823
Other
Segment Reporting Information [Line Items]
Operating Revenues	1	1	2
Depreciation and amortization	1	1	1
Operating income	(7)	8	15
(Losses) earnings from equity method investments	0	0	0
Interest expense, net of capitalization	80	75	27
Income tax expense (benefit)	(29)	(11)	(11)
Capital expenditures	2	0	3
Adjusted net income	(51)	(58)	(17)
Property, plant and equipment	11	10
Equity method investments	0	0
Total assets	800	364
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	(1)	(1)	(14)
Networks
Segment Reporting Information [Line Items]
Operating Revenues	5,754	5,188	5,164
Networks | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	1	1	14
Networks | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	5,753	5,187	5,150
Depreciation and amortization	616	592	549
Operating income	876	877	890
(Losses) earnings from equity method investments	12	10	11
Interest expense, net of capitalization	217	234	269
Income tax expense (benefit)	98	120	152
Capital expenditures	2,294	1,838	1,610
Adjusted net income	661	568	465
Property, plant and equipment	18,737	17,079
Equity method investments	148	134
Total assets	26,126	24,592
Renewables
Segment Reporting Information [Line Items]
Operating Revenues	1,220	1,132	1,184
Renewables | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	0	0	0
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	1,220	1,132	1,184
Depreciation and amortization	397	394	383
Operating income	26	(16)	93
(Losses) earnings from equity method investments	(5)	(13)	(8)
Interest expense, net of capitalization	1	7	14
Income tax expense (benefit)	(48)	(80)	28
Capital expenditures	680	943	1,122
Adjusted net income	170	115	$ 193
Property, plant and equipment	10,118	9,662
Equity method investments	412	534
Total assets	$ 12,578	$ 12,867

Segment Information - Reconcili

Segment Information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 780	$ 625	$ 640
Adjustments:
Mark-to-market adjustments - Renewables	(53)	(5)	76
Restructuring charges	0	(6)	(6)
Accelerated depreciation from repowering	0	(9)	(33)
Impact of COVID-19	(34)	(29)	0
Merger costs	(12)	(6)	0
Proceeds from Legal Settlements	0	(5)	0
Income tax impact of adjustments	26	16	(10)
Net Income Attributable to Avangrid, Inc.	$ 707	$ 581	$ 667

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To	$ 0	$ 1	$ 1
Purchases From	(52)	(43)	(42)
Iberdrola Renovables Energia, S.L.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(10)	(9)	(9)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(9)	(7)	(3)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	14	9	13
Purchases From	0	0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Sales To	7	2	1
Purchases From	(39)	0	0
Other
Related Party Transaction [Line Items]
Sales To	2	0	1
Purchases From	$ (3)	$ 0	$ (3)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Jan. 31, 2020
Iberdrola
Related Party Transaction [Line Items]
Deposit balance	$ 0	$ 0
Iberdrola | Siemens Gamesa
Related Party Transaction [Line Items]
Ownership percentage by noncontrolling owners			8.10%
Iberdrola Financiacion S A U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Credit facility fees percentage	0.105%
Credit facility, amount outstanding	$ 0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Notes payable, related parties	2,000,000	5,000,000
Affiliated Entity
Related Party Transaction [Line Items]
Asset impairment charges	$ 0
Siemens Gamesa | Iberdrola
Related Party Transaction [Line Items]
Related party transaction, amount		$ 11,000,000

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	$ 3	$ 2
Owed To	(43)	(43)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(9)	(6)
Siemens Gamesa
Related Party Transaction [Line Items]
Owed By	8	4
Owed To	(8)	0
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	0	5
Owed To	(2)	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	1
Owed To	$ (1)	$ (1)

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Details) $ / shares in Units, $ in Millions	1 Months Ended												12 Months Ended
	Jan. 31, 2022$ / sharesshares	Jun. 30, 2021$ / sharesshares	Mar. 31, 2021USD ($)installment$ / sharesshares	Feb. 28, 2021shares	Dec. 31, 2020USD ($)installment$ / shares	Aug. 31, 2020installment$ / sharesshares	Jun. 30, 2020USD ($)installmentshares	May 31, 2020shares	Mar. 31, 2020installmentshares	Feb. 29, 2020installmentshares	Oct. 31, 2018set$ / sharesshares	Jun. 30, 2018set$ / sharesshares	Dec. 31, 2021USD ($)installment$ / sharesshares	Dec. 31, 2020USD ($)$ / shares	Dec. 31, 2019USD ($)shares	Dec. 31, 2018shares	Dec. 31, 2017shares	Dec. 31, 2016$ / sharesshares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for stock-based compensation plans (in shares)													2,500,000
Number of shares granted (in shares)													1,359,516
Share-based payment award grant date fair value (in dollars per share) | $ / shares													$ 36.49
Number of shares forfeited (in shares)								2,605					90,603
Number of vesting installments | installment													3
Grant date fair value (in dollars per share) | $ / shares					$ 32.42								$ 36.05	$ 32.42
Number of awards set granted | set											2	2
Stock-based compensation expense | $													$ 18	$ 14	$ 3
Income tax benefit recognized for stock-based compensation arrangements | $													5	4	$ 1
Unrecognized cost for non-vested PSUs | $													$ 25
Recognition of PSU costs, weighted-average period													3 years
Performance Shares Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)										208,268			1,336,787
Share-based payment award options requisite service period													4 years
Number of shares issued (in shares)			45,661					42,777
Grant date fair value (in dollars per share) | $ / shares													$ 36.22
Performance Shares Units | Officers and Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)															3,881	75,350	85,759	1,298,683
Share-based payment award grant date fair value (in dollars per share) | $ / shares																		$ 31.80
Share-based payment award options requisite service period																		7 years
Number of vesting installments | installment										3
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued (in shares)			5,953				60,000
Cash used to settle award | $							$ 3
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			5,000					8,000	60,000
Share-based payment award grant date fair value (in dollars per share) | $ / shares											$ 47.59	$ 50.40
Number of vesting installments | installment			1		1	3	1
Number of shares issued (in shares)		9,390		1,697
Grant date fair value (in dollars per share) | $ / shares		$ 53.59	$ 48.83			$ 48.99
Restricted Stock Units (RSUs) | Executive Officer | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	17,500
Number of shares issued (in shares)	9,390
Grant date fair value (in dollars per share) | $ / shares	$ 48.16
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				$ 2
Share based compensation liability | $					$ 2								$ 2	$ 2

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Nonvested PSUs and RSUs (Details) - $ / shares	1 Months Ended	12 Months Ended
	May 31, 2020	Dec. 31, 2021
Number of PSUs and RSUs
Nonvested Balance – beginning of year (in shares)		142,167
Granted (in shares)		1,359,516
Forfeited (in shares)	(2,605)	(90,603)
Vested (in shares)		(87,751)
Nonvested Balance – end of year (in shares)		1,323,328
Weighted Average Grant Date Fair Value
Nonvested Balance – beginning of year (in dollars per share)		$ 32.42
Granted (in dollars per share)		36.49
Forfeited (in dollars per share)		36.63
Vested (in dollars per share)		47.70
Nonvested Balance – end of year (in dollars per share)		$ 36.05

Subsequent events (Details)

Subsequent events (Details) - $ / shares	Feb. 16, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Subsequent Event [Line Items]
Dividends declared (in dollars per share)		$ 1.76	$ 1.76	$ 1.76
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share)	$ 0.44

CONDENSED FINANCIAL INFORMATI_2

CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Income Statements, Captions [Line Items]
Operating Revenues	$ 6,974	$ 6,320	$ 6,336
Operating Expenses
Taxes other than income taxes	640	619	591
Total Operating Expenses	6,079	5,451	5,338
Operating Income	895	869	998
Other Income
Other income	60	18	121
Interest expense	(298)	(316)	(310)
Income Before Income Tax	664	568	812
Income tax expense (benefit)	21	29	169
Net Income Attributable to Avangrid, Inc.	707	581	667
AVANGRID
Condensed Income Statements, Captions [Line Items]
Operating Revenues	0	0	0
Operating Expenses
Operating expense	19	10	3
Taxes other than income taxes	(11)	(11)	(12)
Total Operating Expenses	8	(1)	(9)
Operating Income	(8)	1	9
Other Income
Other income	22	35	59
Equity earnings of subsidiaries	756	641	678
Interest expense	(93)	(109)	(93)
Income Before Income Tax	677	568	653
Income tax expense (benefit)	(30)	(13)	(14)
Net Income Attributable to Avangrid, Inc.	$ 707	$ 581	$ 667

CONDENSED FINANCIAL INFORMATI_3

CONDENSED FINANCIAL INFORMATION OF PARENT - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Statement of Income Captions [Line Items]
Net Income	$ 707	$ 581	$ 667
Comprehensive Income Attributable to Avangrid, Inc.	545	565	656
AVANGRID
Condensed Statement of Income Captions [Line Items]
Net Income	707	581	667
Other comprehensive loss of subsidiaries	(162)	(16)	(11)
Comprehensive Income Attributable to Avangrid, Inc.	$ 545	$ 565	$ 656

CONDENSED FINANCIAL INFORMATI_4

CONDENSED FINANCIAL INFORMATION OF PARENT - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 1,474	$ 1,463
Accounts receivable from subsidiaries	11	12
Prepayments and other current assets	245	525
Total Current Assets	3,777	3,777
Other assets
Other	374	331
Total Other Assets	3,845	3,834
Total Assets	39,504	37,823
Current Liabilities
Accounts payable and accrued liabilities	1,586	1,453
Accounts payable to subsidiaries	61	50
Interest accrued	69	70
Dividends payable	170	136
Total Current Liabilities	3,329	3,069
Derivative liabilities	160	79
Non-current debt	7,922	7,478
Non-current debt to affiliate	0	3,000
Total non-current liabilities	16,214	18,928
Total Liabilities	19,543	21,997
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	17,679	13,665
Treasury stock	(47)	(14)
Retained earnings	1,714	1,666
Accumulated other comprehensive loss	(273)	(111)
Total Equity	19,961	15,826	$ 15,539	$ 15,389
Total Liabilities and Equity	39,504	37,823
AVANGRID
Current Assets
Cash and cash equivalents	1,424	1,438
Accounts receivable from subsidiaries	128	124
Notes receivable from subsidiaries	1,475	1,489
Prepayments and other current assets	52	357
Total Current Assets	3,079	3,408
Investments in subsidiaries	18,500	18,356
Other assets
Deferred income taxes	413	388
Other	3	3
Total Other Assets	416	391
Total Assets	21,995	22,155
Current Liabilities
Notes payable	0	308
Notes payable to subsidiaries	643	1,375
Accounts payable and accrued liabilities	3	12
Accounts payable to subsidiaries	9	9
Interest accrued	9	9
Interest accrued subsidiaries	1	10
Dividends payable	170	136
Total Current Liabilities	835	1,859
Derivative liabilities	19	0
Non-current debt	2,065	2,087
Non-current debt to affiliate	0	3,000
Total non-current liabilities	2,084	5,087
Total Liabilities	2,919	6,946
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	17,679	13,665
Treasury stock	(47)	(14)
Retained earnings	1,714	1,666
Accumulated other comprehensive loss	(273)	(111)
Total Equity	19,076	15,209
Total Liabilities and Equity	$ 21,995	$ 22,155

CONDENSED FINANCIAL INFORMATI_5

CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	$ 1,561	$ 1,288	$ 1,588
Cash Flow from Investing Activities
Net Cash Used in Investing Activities	(2,440)	(2,858)	(2,708)
Cash Flow from Financing Activities
Proceeds from non-current debt	833	1,367	2,137
(Repayments) proceeds from non-current debt with affiliate	0	3,000	0
Repurchase of common stock	(33)	(2)	0
Dividends paid	(613)	(545)	(545)
Net Cash Provided by Financing Activities	889	2,853	1,261
Net Increase in Cash, Cash Equivalents and Restricted Cash	10	1,283	141
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,467	184	43
Cash, Cash Equivalents and Restricted Cash, End of Year	1,477	1,467	184
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	279	278	270
Cash paid for income taxes	2	8	2
AVANGRID
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	(397)	(142)	(1,299)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	130	(73)	633
Investments in subsidiaries	(1,026)	(591)	(399)
Return of capital from investments in subsidiaries	1,122	419	433
Other investments	300	(300)	0
Net Cash Used in Investing Activities	526	(545)	667
Cash Flow from Financing Activities
(Repayments) receipts of short-term notes payable from subsidiaries, net	(186)	(14)	107
Repayments of short-term notes payable	(309)	(253)	(27)
Proceeds from non-current debt	0	744	1,243
(Repayments) proceeds from non-current debt with affiliate	(3,000)	3,000	0
Repayments of non-current debt	0	(950)	0
Repurchase of common stock	(33)	(2)	0
Issuance of common stock	3,998	(1)	0
Dividends paid	(613)	(545)	(545)
Net Cash Provided by Financing Activities	(143)	1,979	778
Net Increase in Cash, Cash Equivalents and Restricted Cash	(14)	1,292	146
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,438	146	0
Cash, Cash Equivalents and Restricted Cash, End of Year	1,424	1,438	146
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	74	111	85
Cash paid for income taxes	$ (15)	$ 65	$ 43

CONDENSED FINANCIAL INFORMATI_6

CONDENSED FINANCIAL INFORMATION OF PARENT - Basis Of Presentation (Details) $ / shares in Units, $ in Millions	May 18, 2021USD ($)placement$ / sharesshares	Apr. 15, 2021	Oct. 20, 2020USD ($)$ / shares	Dec. 31, 2021$ / shares	Dec. 31, 2020$ / shares	Dec. 31, 2019$ / shares
Collaborative Arrangement and Arrangement Other than Collaborative [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
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	$ 3,000
AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [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
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	$ 3,000
Iberdrola S.A. | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	63,424,125
Avangrid | Iberdrola S.A.
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Percentage of equity owned by parent				81.60%
Avangrid | Iberdrola S.A. | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Percentage of equity owned by parent				81.50%
Hyde Member LLC and Subsidiary of Qatar Investment Authority
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
Hyde Member LLC and Subsidiary of Qatar Investment Authority | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
NM Green Holdings, Inc.
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Merger agreement, share price (in dollars per share) | $ / shares			$ 50.30
Merger agreement term, ownership percentage benchmark			15.00%
Merger agreement, termination rights term, extension period			3 months
Merger agreement, termination rights term, termination fees			$ 130
Merger agreement, termination rights term, termination fees as remedy			184
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			10
NM Green Holdings, Inc. | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Merger agreement, termination rights term, termination fees as remedy			184
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			$ 10
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%

CONDENSED FINANCIAL INFORMATI_7

CONDENSED FINANCIAL INFORMATION OF PARENT - Common Stock (Details) - USD ($) $ / shares in Units, $ in Millions	Feb. 16, 2022	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 18, 2021
Business Acquisition [Line Items]
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)			386,568,104	309,077,300
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 17,679	$ 13,665
Release of common stock held in trust (in shares)			301,239	72,028
Number of shares repurchased during period (in shares)			694,148
Treasury shares (in shares)			997,983
Treasury stock			$ 47	$ 14
Dividends declared (in dollars per share)			$ 1.76	$ 1.76	$ 1.76
Subsequent Event
Business Acquisition [Line Items]
Dividends declared (in dollars per share)	$ 0.44
Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)			0	0
Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)			77,883,713	42,777
AVANGRID
Business Acquisition [Line Items]
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)			386,568,104	309,077,300
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01		$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 17,679	$ 13,665
Common stock held in trust (in shares)			112,543	413,782
Release of common stock held in trust (in shares)			301,239	72,028
Number of shares repurchased during period (in shares)		694,148
Treasury shares (in shares)			997,983
Treasury stock			$ 47	$ 14
AVANGRID | Subsequent Event
Business Acquisition [Line Items]
Dividends declared (in dollars per share)	$ 0.44
AVANGRID | Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)			0	0
AVANGRID | Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)			77,883,713	42,777
Iberdrola Renewables Holding, Inc
Business Acquisition [Line Items]
Percentage of equity owned by parent			81.50%
Iberdrola Renewables Holding, Inc | AVANGRID
Business Acquisition [Line Items]
Percentage of equity owned by parent			81.60%	81.50%
Target ownership percentage by Parent			81.50%

CONDENSED FINANCIAL INFORMATI_8

CONDENSED FINANCIAL INFORMATION OF PARENT - Long-Term Debt (Details) - USD ($)	Apr. 09, 2020	May 16, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 14, 2020	Nov. 21, 2017
Debt Instrument [Line Items]
Proceeds from non-current debt			$ 833,000,000	$ 1,367,000,000	$ 2,137,000,000
Iberdrola Loan | Subordinated Debt
Debt Instrument [Line Items]
Debt instrument principal amount						$ 3,000,000,000
AVANGRID
Debt Instrument [Line Items]
Proceeds from non-current debt			$ 0	$ 744,000,000	$ 1,243,000,000
AVANGRID | 3.150% Notes due 2024
Debt Instrument [Line Items]
Debt instrument principal amount							$ 600,000,000
Debt instrument, interest rate							3.15%
AVANGRID | 3.800% Notes due 2029
Debt Instrument [Line Items]
Debt instrument principal amount		$ 750,000,000
Debt instrument, interest rate		3.80%
Proceeds from non-current debt		$ 743,000,000
AVANGRID | Unsecured Notes Maturing in 2025
Debt Instrument [Line Items]
Debt instrument principal amount	$ 750,000,000
Debt instrument, interest rate	3.20%
Proceeds from non-current debt	$ 744,000,000
AVANGRID | Iberdrola Loan | Subordinated Debt
Debt Instrument [Line Items]
Debt instrument principal amount						$ 3,000,000,000

CONDENSED FINANCIAL INFORMATI_9

CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Summary (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
AVANGRID Networks
Cash Dividend [Line Items]
Cash dividends paid	$ 970	$ 419	$ 433
AVANGRID Renewables
Cash Dividend [Line Items]
Cash dividends paid	$ 152	$ 0	$ 0

CONDENSED FINANCIAL INFORMAT_10

CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Additional Information (Details) - AVANGRID - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 1,026	$ 591	$ 399
Non cash contribution/dividend recorded by parent company	674	423
United Illuminating Company (UI)
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 1,011	$ 590	$ 158