Avangrid (AGR) 10-K 22 Feb 23 2022 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Feb. 21, 2023	Jun. 30, 2022
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2022
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			$ 3,262
Entity Common Stock, Shares Outstanding		386,637,276
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 2023 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	FY
Entity Central Index Key	0001634997

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2022
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Statement [Abstract]
Operating Revenues	$ 7,923	$ 6,974	$ 6,320
Operating Expenses
Purchased power, natural gas and fuel used	2,456	1,719	1,379
Operations and maintenance	2,872	2,706	2,466
Depreciation and amortization	1,085	1,014	987
Taxes other than income taxes, net	658	640	619
Total Operating Expenses	7,071	6,079	5,451
Operating Income	852	895	869
Other Income and (Expense)
Other income (expense)	30	60	18
Earnings (losses) from equity method investments	262	7	(3)
Interest expense, net of capitalization	(303)	(298)	(316)
Income Before Income Tax	841	664	568
Income tax expense	20	21	29
Net Income	821	643	539
Net loss attributable to noncontrolling interests	60	64	42
Net Income Attributable to Avangrid, Inc.	$ 881	$ 707	$ 581
Earnings Per Common Share, Basic (in dollars per share)	$ 2.28	$ 1.97	$ 1.88
Earnings Per Common Share, Diluted (in dollars per share)	$ 2.27	$ 1.97	$ 1.88
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	386,727,246	358,086,621	309,494,939
Diluted (in shares)	387,215,785	358,578,608	309,559,387

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Net Income	$ 821	$ 643	$ 539
Other Comprehensive Income
Gain for defined benefit plans, net of income taxes of $3, $0 and $0, respectively	14	2	0
Amortization of pension cost, net of income taxes of $1, $(1) and $3, respectively	4	(8)	(13)
Unrealized gain (loss) from equity method investment, net of income taxes of $6, $(3) and $0, respectively	22	(9)	0
Unrealized loss during the year on derivatives qualifying as cash flow hedges, net of income taxes of $0, $(44) and $(7), respectively	(1)	(159)	(22)
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $19, $(3) and $2, respectively	54	12	19
Other Comprehensive Income (Loss)	93	(162)	(16)
Comprehensive Income	914	481	523
Net loss attributable to noncontrolling interests	60	64	42
Comprehensive Income Attributable to Avangrid, Inc.	$ 974	$ 545	$ 565

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, income tax expense (benefit)	$ 3	$ 0	$ 0
Amortization of pension cost, income tax expense (benefit)	(1)	(1)	(3)
Unrealized (loss) gain from equity method investment, income tax (benefit) expense	6	(3)	0
Unrealized loss during the year on derivatives qualifying as cash flow hedges, income tax expense (benefit)	0	(44)	(7)
Reclassification to net income of losses on cash flow hedges, income tax expense (benefit)	$ 19	$ (3)	$ 2

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Current Assets
Cash and cash equivalents	$ 69	$ 1,474
Accounts receivable and unbilled revenues, net	1,737	1,269
Accounts receivable from affiliates	5	11
Notes receivable from affiliates	3	0
Derivative assets	60	35
Fuel and gas in storage	268	139
Materials and supplies	235	204
Prepayments and other current assets	386	245
Regulatory assets	447	400
Total Current Assets	3,210	3,777
Total Property, Plant and Equipment ($2,707 and $1,959 related to VIEs, respectively)	30,994	28,866
Operating lease right-of-use assets	159	148
Equity method investments	437	560
Other investments	49	61
Regulatory assets	2,321	2,247
Other Assets
Goodwill	3,119	3,119
Intangible assets	281	293
Derivative assets	140	59
Other	413	374
Total Other Assets	3,953	3,845
Total Assets	41,123	39,504
Current Liabilities
Current portion of debt	412	372
Notes payable	566	159
Notes payable to affiliate	2	2
Interest accrued	66	69
Accounts payable and accrued liabilities	2,007	1,586
Accounts payable to affiliates	39	61
Dividends payable	170	170
Taxes accrued	61	43
Operating lease liabilities	13	12
Derivative liabilities	133	64
Other current liabilities	593	484
Regulatory liabilities	354	307
Total Current Liabilities	4,416	3,329
Regulatory liabilities	2,915	3,022
Other Non-current Liabilities
Deferred income taxes	2,234	2,016
Deferred income	1,062	1,130
Pension and other postretirement	491	684
Operating lease liabilities	161	149
Derivative liabilities	164	160
Asset retirement obligations	273	253
Environmental remediation costs	279	298
Other	563	580
Total Other Non-current Liabilities	5,227	5,270
Total Non-current Debt	8,215	7,922
Non-current debt to affiliate	8	0
Total Non-current Liabilities	16,365	16,214
Total Liabilities	20,781	19,543
Commitments and Contingencies	0	0
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,734,757 and 387,678,630 shares issued; 386,628,586 and 386,568,104 shares outstanding, respectively	3	3
Additional paid-in capital	17,694	17,679
Treasury stock	(47)	(47)
Retained earnings	1,910	1,714
Accumulated other comprehensive loss	(180)	(273)
Total Stockholders’ Equity	19,380	19,076
Noncontrolling interests	962	885
Total Equity	20,342	19,961
Total Liabilities and Equity	$ 41,123	$ 39,504

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Property, plant and equipment	$ 30,994	$ 28,866
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)	387,734,757	387,678,630
Common stock, outstanding (in shares)	386,628,586	386,568,104
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 2,707	$ 1,959

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Flow from Operating Activities
Net income	$ 821	$ 643	$ 539
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	1,085	1,014	987
Accretion expenses	14	12	11
Regulatory assets/liabilities amortization and carrying cost	(65)	(72)	(13)
Pension cost	11	52	82
Earnings from equity method investments	(262)	(7)	3
Distribution of earnings from equity method investments	23	17	19
Unrealized losses on marked to market derivative contracts	0	86	5
Loss (gain) from divestment and disposal of property	2	24	(10)
Deferred taxes	18	11	17
Other non-cash items	(48)	(82)	(83)
Changes in operating assets and liabilities:
Current assets	(837)	(275)	(173)
Noncurrent assets	(123)	(45)	(170)
Current liabilities	385	286	160
Noncurrent liabilities	11	(103)	(86)
Net Cash Provided by Operating Activities	1,035	1,561	1,288
Cash Flow from Investing Activities
Capital expenditures	(2,519)	(2,976)	(2,781)
Contributions in aid of construction	123	130	48
Proceeds from sale of equity method and other investment	0	0	238
Proceeds from sale of property, plant and equipment	31	24	7
(Payments to) receipts from affiliates	(3)	5	(3)
Cash distribution from equity method investments	18	155	3
Other investments and equity method investments, net	(198)	222	(370)
Net Cash Used in Investing Activities	(2,548)	(2,440)	(2,858)
Cash Flow from Financing Activities
Non-current debt issuances	791	833	1,367
Non-current debt issuance with affiliate	0	0	3,000
Repayments of non-current debt	(365)	(304)	(1,011)
Repayment of non-current debt with affiliate	0	(3,000)	0
Receipts (Repayments) of other short-term debt, net	236	(306)	(253)
Repayments of financing leases	(9)	(6)	(9)
Repurchase of common stock	0	(33)	(2)
Issuance of common stock	(1)	3,998	(1)
Distributions to noncontrolling interests	(10)	(10)	(5)
Contributions from noncontrolling interests	147	330	312
Dividends paid	(681)	(613)	(545)
Net Cash Provided by Financing Activities	108	889	2,853
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(1,405)	10	1,283
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,477	1,467	184
Cash, Cash Equivalents and Restricted Cash, End of Year	72	1,477	1,467
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	273	279	278
Cash paid for income taxes	$ 15	$ 2	$ 8

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' Equity Cumulative Effect, Period of Adoption, Adjustment	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Retained Earnings Cumulative Effect, Period of Adoption, Adjustment	Accumulated Other Comprehensive Income (Loss)	Non-controlling Interests
Balance at beginning of period (in shares) at Dec. 31, 2019	[1]					309,005,272
Balance at beginning of period at Dec. 31, 2019		$ 15,539	$ (1)	$ 15,190	$ (1)	$ 3		$ 13,660	$ (12)	$ 1,634	$ (1)	$ (95)	$ 349
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		539		581						581			(42)
Other comprehensive income (loss), net of tax		(16)		(16)								(16)
Comprehensive Income		523
Dividends declared		(545)		(545)						(545)
Release of common stock held in trust (in shares)	[1]					72,028
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	[1]					309,077,300
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 (loss), 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
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		821		881						881			(60)
Other comprehensive income (loss), net of tax		93		93								93
Comprehensive Income		914
Dividends declared		$ (681)		(681)						(681)
Release of common stock held in trust (in shares)		4,355				4,355	[1]
Issuance of common stock (in shares)	[1]					56,127
Issuance of common stock		$ (1)		(1)				(1)
Stock-based compensation		16		16				16
Distributions to noncontrolling interests		(10)											(10)
Contributions from noncontrolling interests		$ 143		(4)						(4)			147
Balance at end of period (in shares) at Dec. 31, 2022		386,628,586				386,628,586	[1]
Balance at end of period at Dec. 31, 2022		$ 20,342		$ 19,380		$ 3		$ 17,694	$ (47)	$ 1,910		$ (180)	$ 962
[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, 2022	Dec. 31, 2021	Dec. 31, 2020
Statement of Stockholders' Equity [Abstract]
Other comprehensive income, tax	$ 29	$ (51)	$ (2)
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, 2022
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 18.4% 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 was 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 (HSR)), 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, 2021, 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's subsidiary, Public Service Company of New Mexico (PNM), AVANGRID and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNM filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. The Statement of Issues was filed on February 2, 2022 and the Brief in Chief was filed on April 7, 2022. On June 14, 2022, the NMPRC filed its Answer Brief. On June 13, 2022, New Energy Economy, an intervener in the Merger proceeding, filed its Answer Brief. AVANGRID's Reply Brief was filed on August 5, 2022. On February 24, 2022, the FCC granted an extension to its approval to transfer operating licenses in connection with the Merger, which was further extended on August 9, 2022. On May 20, 2022, the NRC issued an order extending the effectiveness of its approval until May 25, 2023. On September 21, 2022, New Energy Economy filed a motion to show cause with the NMPRC alleging that AVANGRID and PNM have engaged in a misleading joint advertising and sponsorship strategy and requesting an investigation. AVANGRID and PNM filed a reply to the motion to show cause on October 11, 2022. On December 14, 2022, the NMPRC issued an order denying the motion. 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 acknowledged in the Amendment that the required regulatory approval from the NMPRC had not been obtained and that the parties reasonably determined that such outstanding approval would 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). During the pendency of the appeal described above, 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. For example, AVANGRID and PNMR are preparing new filings under HSR. We cannot predict the outcome of these re-applications or requests for extensions of such 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 (as amended) 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 (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). 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, up to a maximum aggregate amount of approximately $4,300 million, including the payment of the aggregate Merger Consideration. On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which set 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, AVANGRID 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 approximately $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, 2022
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, 2022
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 primarily 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 and other equity investments 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 equity method investments as a reduction in the carrying amount of the investment and not as dividend income. When an equity method investee executes derivative transactions that have cash flow hedge accounting treatment, we recognize our share of the OCI in our consolidated balance sheet. 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 30 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. Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation was 2.8% of average depreciable property for both 2022 and 2021. 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 receivables and unbilled revenues, 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 required them to offer to customers a 24-month repayment plan through June 30, 2022. 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. We record AROs for the decommissioning of the wind and solar farms and thermal facilities. Projected removal costs are based on engineering estimates which are updated on an annual basis based on the relevant inflation and discount rate factors. 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. If a plan meets settlement or curtailment criteria, we recognize a regulatory asset of liability if these costs are probable of recovery from ratepayers. 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 f

Revenue

Revenue	12 Months Ended
	Dec. 31, 2022
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 and 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, 2022 and 2021, 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 $33 million and $16 million at December 31, 2022 and 2021, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $33 million, $22 million and $21 million as revenue related to contract liabilities for the years ended December 31, 2022, 2021 and 2020, respectively. 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, 2022, 2021 and 2020 are as follows: Year Ended December 31, 2022 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,610 $ — $ — $ 4,610 Regulated operations – natural gas 1,931 — — 1,931 Nonregulated operations – wind — 947 — 947 Nonregulated operations – solar — 36 — 36 Nonregulated operations – thermal — 96 — 96 Other (a) 117 48 — 165 Revenue from contracts with customers 6,658 1,127 — 7,785 Leasing revenue 8 — — 8 Derivative revenue — 4 — 4 Alternative revenue programs 68 — — 68 Other revenue 48 10 — 58 Total operating revenues $ 6,782 $ 1,141 $ — $ 7,923 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 — 1028 — 1028 Nonregulated operations – solar — 20 — 20 Nonregulated operations – thermal — 63 — 63 Other (a) 67 84 — 151 Revenue from contracts with customers 5,598 1195 — 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 (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, 2022 and 2021, accounts receivable balances related to contracts with customers were approximately $1,622 million and $1,220 million, respectively, including unbilled revenues of $541 million and $405 million, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets. As of December 31, 2022, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2022 2023 2024 2025 2026 2027 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ — $ — $ — $ — $ 2 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 46 45 17 5 1 2 116 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 81 34 12 10 7 60 204 Total operating revenues $ 128 $ 80 $ 29 $ 15 $ 8 $ 62 $ 322 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, 2022
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. Commencing on 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 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC 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. In accordance with Chapter 120 of MPUC Rules, on May 26, 2022, CMP filed a nonbinding notice of intent to file a distribution rate case on or after sixty days from the issuance of the letter. In the notice, CMP signaled its intent to propose a three-year rate plan, which includes a multi-year capital investment plan to fund investments needed to improve reliability and resiliency, as well as to continue to improve the customer experience and cost-effectively advance clean energy transformation. CMP’s notice estimated a revenue change in the range of $45 to $50 million in the first year of the rate plan followed by increases in the range of $25 to $30 million in the second year and $20 to $25 million in the third year. We cannot predict the outcome of this matter. On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. In its filing, CMP has set the three rate years as May 10, 2023 to May 9, 2024 (“Rate Year 1”); May 10, 2024 to May 9, 2025 (“Rate Year 2”); and May 10, 2025 to May 9, 2026 (“Rate Year 3”). The requested Rate Year revenue requirement increases for the rate years are $48 million, $28 million and $23 million, respectively. The revenue requirement adjustments are based on a test year ending December 31, 2021. The requested revenue changes for each rate year of the proposal are subject to four adjustment mechanisms: (1) a yearly review of plant additions with potential downward reconciliation in the event of an underspend, (2) a capital adjustment mechanism for certain incremental pole replacements, broadband work, electric vehicle work, energy storage projects, and metering system upgrades, (3) a symmetrical inflation reconciliation adjustment, and (4) reconciliation of the benefits associated with the tax basis repair deduction. Other parties filed direct testimony in this proceeding on December 2, 2022 and CMP filed rebuttal testimony on February 7, 2023. New rates are expected to take effect on or around August 2023. We cannot predict the outcome of this matter. 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 November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed 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 % On May 26, 2022, NYSEG and RG&E filed for a new rate plan with the NYPSC. The rate filings are based on test year 2021 financial results adjusted to the rate year May 1, 2023 – April 30, 2024. Since these rate filings were submitted on May 26, 2022, the effective date of new rates, assuming an approximately 11-month approval period, will be May 1, 2023. NYSEG and RG&E filed for a one-year rate plan but expressed interest in exploring a multi-year plan during the pendency of the case (as is the custom in New York). On August 12, 2022, NYSEG and RG&E filed an update to its rate plan filing called for in the litigation schedule. In their filings, the following revenue changes were requested: Requested Revenue Change May 26, 2022 August 12, 2022 Difference Utility (Millions) (Millions) (Millions) NYSEG Electric $ 274 $ 274 $ — NYSEG Gas $ 43 $ 30 $ (13) RG&E Electric $ 94 $ 93 $ (1) RG&E Gas $ 38 $ 32 $ (6) On September 16, 2022, the NYPSC suspended new tariffs and rates through April 21, 2023. On October 19, 2022, consistent with the Administrative Law Judge’s’ July 1, 2022 Ruling on Schedule and Party Status, NYSEG and RG&E voluntarily agreed to 60-day extension of maximum suspension period through June 20, 2023, subject to a make-whole provision. On December 21, 2022, NYSEG and RG&E voluntarily agreed to further 60-day extension of maximum suspension period to postpone through August 19, 2023, subject to a make-whole provision. During this time, the parties have conducted multi-party rate case settlement negotiations. We cannot predict the outcome of this proceeding. 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 2023, 70% of the second half of 2023, and 20% of the first half of 2024. Supplier of last resort service is procured on a quarterly basis and UI is self-managing the last resort service for the first quarter of 2023 and has a wholesale power supply agreement in place for second quarter of 2023. 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. On September 9, 2022, UI filed a distribution revenue requirement case. UI’s filing proposes a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing is based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (“UI Rate Year 1”), September 1, 2024 (“UI Rate Year 2”), and September 1, 2025 (“UI Rate Year 3”). UI is requesting that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $102 million in UI Rate Year 1, an incremental approximately $17 million in UI Rate Year 2, and an incremental approximately $17 million in UI Rate Year 3, compared to total revenues that would otherwise be recovered under UI’s current rate schedules. UI’s Rate Plan also includes several measures to moderate the impact of the proposed rate update for all customers, including, without limitation a rate levelization proposal to spread the proposed total rate increase over the three rate years, which would result in a change in revenue in UI Rate Year 1 of approximately $54 million. Other parties filed direct testimony on December 13, 2022 and UI filed its rebuttal testimony on January 6, 2023. Litigation of the case is expected to take approximately one year with new rates expected to go into effect on or around September 2023. We cannot predict the outcome of this matter. 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 June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval. The Settlement Agreement followed BGC’s December 14, 2021 filing of a Notice of Intent to File Rate Schedules. Following that filing, BGC and the AGO negotiated the Settlement Agreement in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allows for agreed-upon adjustments to BGC’s revenue requirement as well as various step increases BGC shall be entitled to on January 1, 2023 and January 1, 2024. The Settlement Agreement provides that it shall be void unless approved in its entirety by the DPU by November 1, 2022. It provides for the opportunity to increase BGC’s revenue requirement by as much as $5.6 million over current rates (reflective of a 9.70% ROE and a 54.00% equity ratio as well as other stepped adjustments) through January 1, 2024. The Settlement Agreement was approved in its entirety by the DPU on October 27, 2022, and new rates went into effect January 1, 2023. 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. 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, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions. 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. 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 $137 million and $142 million, respectively for this item at December 31, 2022 and 2021. 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 2023. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which indicated the auditor was unable to verify the asset “acquisition value” used to calculate the Power Tax regulatory asset. The audit report requires that CMP must provide support for the beginning balance of the regulatory assets or it will be unable to recover the value of the assets, which is approximately $11 million, excluding carrying costs. CMP responded to the audit report in its rate case filing by providing additional acquisition value support and, therefore, requested full recovery of the Power Tax regulatory asset. MPUC staff expressed concerns about the value CMP has attributed to this issue. The MPUC had an outside firm conduct an audit of CMP's filing and acquisition values, and the auditor found CMP's information was reasonable. In September 2019, CMP filed a report in response to the audit report and addressed MPUC staff concerns. On December 17, 2019, CMP filed a stipulat

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2022
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 $977 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, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Pension and other post-retirement benefits $ 365 $ 545 Pension and other post-retirement benefits cost deferrals 93 95 Storm costs 671 448 Rate adjustment mechanism 41 68 Revenue decoupling mechanism 52 68 Transmission revenue reconciliation mechanism 11 15 Contracts for differences 56 73 Hardship programs 33 24 Plant decommissioning 1 2 Deferred purchased gas 56 52 Deferred transmission expense — 13 Environmental remediation costs 248 256 Debt premium 64 71 Unamortized losses on reacquired debt 19 23 Unfunded future income taxes 492 424 Federal tax depreciation normalization adjustment 137 142 Asset retirement obligation 20 20 Deferred meter replacement costs 55 46 COVID-19 cost recovery and late payment surcharge 17 21 Low income arrears forgiveness 31 — Excess generation service charge 24 6 System Expansion 21 12 Non-bypassable charge 14 10 Other 247 213 Total regulatory assets 2,768 2,647 Less: current portion 447 400 Total non-current regulatory assets $ 2,321 $ 2,247 “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 46 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 and late payment surcharge" represents: a) 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, and b) deferred lost late payment revenue in the state of New York based on the order issued by the NYPSC on June 17, 2022, approving deferral and surcharge/sur-credit mechanism to recover/return deferred balances starting July 1, 2022. “Low-income arrears forgiveness” represents deferred bill credits in the state of New York based on the order issued by the NYPSC on June 16, 2022, approving deferral of bill credits for low-income customers and recovery of regulatory asset from all customers over five years for RG&E and three years for NYSEG. Surcharge will start August 1, 2022. “Excess generation service charge” represents deferred generation-related costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “System expansion” represents expenses not covered by system expansion rates related to expanding the natural gas system and converting customers to natural gas. “Non-bypassable charges” represent non-bypassable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “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, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Energy efficiency portfolio standard $ 30 $ 45 Gas supply charge and deferred natural gas cost 15 7 Pension and other post-retirement benefits cost deferrals 117 73 Carrying costs on deferred income tax bonus depreciation 9 23 Carrying costs on deferred income tax - Mixed Services 263(a) 3 7 2017 Tax Act 1,232 1,327 Rate change levelization 25 99 Revenue decoupling mechanism 13 13 Accrued removal obligations 1,178 1,192 Asset sale gain account — 2 Economic development 20 26 Positive benefit adjustment 16 22 Theoretical reserve flow thru impact 3 6 Deferred property tax 17 22 Net plant reconciliation 11 16 Debt rate reconciliation 32 49 Rate refund – FERC ROE proceeding 36 35 Transmission congestion contracts 31 23 Merger-related rate credits 10 12 Accumulated deferred investment tax credits 22 24 Asset retirement obligation 18 18 Earning sharing provisions 13 13 Middletown/Norwalk local transmission network service collections 17 17 Low income programs 18 25 Non-firm margin sharing credits 27 15 New York 2018 winter storm settlement 1 5 Hedges gains — 19 Non by-passable charges 76 11 Transmission revenue reconciliation mechanism 75 9 Other 204 174 Total regulatory liabilities 3,269 3,329 Less: current portion 354 307 Total non-current regulatory liabilities $ 2,915 $ 3,022 “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, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions. “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 RG&E. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In both of the years ended December 31, 2022 and 2021, $2 million of rate credits were applied against customer bills. "Asset retirement obligation" represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability . "Earning sharing provisions" represents the annual earnings over the earnings sharing threshold. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. "Middletown/Norwalk local transmission network service collections" represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project. “Low income programs” represent various hardship and payment plan programs approved for recovery. “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 NYPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. The balance is being amortized through current rates over an amortization period of three years, beginning in 2020. “Hedge gains” represents the deferred fair value gains on electric and gas hedge contracts. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation.

Goodwill and Intangible assets

Goodwill and Intangible assets	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible assets	Goodwill and Intangible assets Goodwill by reportable segment as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 372 Total $ 3,119 $ 3,119 During 2022, 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 2022, we utilized a qualitative assessment for the Networks reporting units and a quantitative assessment for the Renewables reporting unit. We had no impairment of goodwill in 2022 and 2021 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, 2022 and 2021: As of December 31, 2022 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 590 $ (313) $ 277 Other 22 (18) 4 Total Intangible Assets $ 612 $ (331) $ 281 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 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 $14 million, $13 million and $14 million for the years ended December 31, 2022, 2021 and 2020, 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, 2022, to be as follows: Year ending December 31, Amount (Millions) 2023 $ 14 2024 $ 14 2025 $ 14 2026 $ 13 2027 $ 13

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2022
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment as of December 31, 2022, consisted of: As of December 31, 2022 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 18,634 $ 14,096 $ 32,730 Natural gas transportation, distribution and other 5,392 14 5,406 Other common operating property — 317 317 Total Property, Plant and Equipment in Service 24,026 14,427 38,453 Total accumulated depreciation (6,277) (5,265) (11,542) Total Net Property, Plant and Equipment in Service 17,749 9,162 26,911 Construction work in progress 2,225 1,858 4,083 Total Property, Plant and Equipment $ 19,974 $ 11,020 $ 30,994 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 Capitalized interest costs were $53 million, $33 million and $51 million for the years ended December 31, 2022, 2021 and 2020, respectively. Accrued liabilities for property, plant and equipment additions were $481 million, $297 million and $285 million as of December 31, 2022, 2021 and 2020, respectively. We impaired or wrote off amounts of $11 million, $20 million and $7 million for the years ended December 31, 2022, 2021 and 2020, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction. Depreciation expense for the years ended December 31, 2022, 2021 and 2020, amounted to $1,071 million, $1,001 million and $973 million, respectively.

Asset retirement obligations

Asset retirement obligations	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021 consisted of: (Millions) 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 Liabilities settled during the year (1) Liabilities incurred during the year 13 Accretion expense 14 Revisions in estimated cash flows (a) (6) As of December 31, 2022 $ 273 (a) Represents an increase (decrease) 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, 2022 and 2021, 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 decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains.

Debt

Debt	12 Months Ended
	Dec. 31, 2022
Debt Disclosure [Abstract]
Debt	Debt Long-term debt as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2025-2052 $ 2,882 1.85%-8.00% $ 2,759 1.85%-8.00% Unsecured pollution control notes - fixed 2023-2029 545 1.40%-4.00% 478 1.40%-4.00% Other various non-current debt - fixed 2023-2052 5,276 1.95%-6.66% 5,110 1.95%-6.66% Unamortized debt issuance costs and discount (76) (53) Total Debt 8,627 8,294 Less: debt due within one year, included in current liabilities 412 372 Total Non-current Debt $ 8,215 $ 7,922 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $8,331 million. 2022 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity UI 1/31/2022 Unsecured Notes $ 150 2.25% 2032 NYSEG 4/6/2022 Tax Exempt Bond $ 67 4.00% 2028 NYSEG 12/15/2022 Unsecured Notes $ 150 4.62% 2032 NYSEG 12/15/2022 Unsecured Notes $ 125 4.96% 2052 RG&E 12/15/2022 First Mortgage Bonds $ 125 4.86% 2052 CMP 12/15/2022 Green First Mortgage Bonds $ 75 4.37% 2032 CMP 12/15/2022 Green First Mortgage Bonds $ 50 4.76% 2052 UI 12/15/2022 Unsecured Notes $ 50 4.62% 2032 Long-term debt maturities, including sinking fund obligations, due over the next five years consist of: 2023 2024 2025 2026 2027 Total (Millions) $ 412 $ 612 $ 1,107 $ 660 $ 484 $ 3,275 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, 2022 and 2021 and throughout 2022 and 2021. Fair Value of Debt As of December 31, 2022 and 2021, the estimated fair value of long-term debt, was $7,991 million and $9,155 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. 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. Short-term Debt AVANGRID had $566 million and $159 million of notes payable as of December 31, 2022 and 2021, 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, 2022 and 2021, the amount of notes payable under the commercial paper program was $397 million and $0, respectively, presented net of discounts on the balance shee t. As of December 31, 2022, the weighted-average interest rate on outstanding commercial paper was 4.66%. 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 contained a commitment from lenders, which expired on April 20, 2022 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 both December 31, 2022 and 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, 2022 was $3,178 million. 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, 2022 and 2021, 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, 2022 and 2021, the amount of notes payable under supplier financing arrangements was $171 million and $161 million, respectively. As of December 31, 2022 and 2021, the weighted average interest rate on the balance was 5.48% and 0.82%, respectively.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2022
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. Our Rabbi Trusts, which cover certain deferred compensation plans and non-qualified pension plan obligations, consists of equity and other investments. The Rabbi Trusts primarily invest in equity securities, fixed income and money market funds. Certain Rabbi Trusts also invest in trust or company owned life insurance policies. 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. NYSEG and RG&E hedge up to approximately 55% of its forecasted winter demand through the use of financial transactions and storage withdrawals. 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 may 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) the Secured Overnight Financing Rate (SOFR), forward interest rate curves or other relevant benchmark. 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 as of both December 31, 2022 and 2021, respectively and is included in “Other Assets” on our consolidated balance sheets. The financial instruments measured at fair value as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 35 $ 13 $ — $ — $ 48 Derivative assets Derivative financial instruments - power $ 37 $ 55 $ 165 $ (177) $ 80 Derivative financial instruments - gas 1 47 — (45) 3 Contracts for differences — — 1 — 1 Derivative financial instruments – Other — 116 — — 116 Total $ 38 $ 218 $ 166 $ (222) $ 200 Derivative liabilities Derivative financial instruments - power $ (46) $ (350) $ (93) $ 364 $ (125) Derivative financial instruments - gas (4) (26) — 30 — Contracts for differences — — (57) — (57) Derivative financial instruments – Other — (115) — — (115) Total $ (50) $ (491) $ (150) $ 394 $ (297) 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 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) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2022, 2021 and 2020 consisted of: (Millions) 2022 2021 2020 Fair value as of January 1, $ (69) $ 13 $ 25 Gains for the year recognized in operating revenues 108 21 8 Losses for the year recognized in operating revenues (30) (34) (2) Total gains or losses for the period recognized in operating revenues 78 (13) 6 Gains recognized in OCI 2 2 1 Losses recognized in OCI (57) (52) (3) Total gains or losses recognized in OCI (55) (50) (2) Net change recognized in regulatory assets and liabilities 17 13 6 Purchases 10 (17) (2) Settlements 8 (13) (15) Transfers out of Level 3 (a) 27 (2) (5) Fair value as of December 31, $ 16 $ (69) $ 13 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 $ 78 $ (13) $ 6 (a) Transfers out of Level 3 were the result of increased observability of market data. Level 3 Fair Value Measurement The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2022. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.18 $ 9.86 $ 2.27 AECO ($/MMBtu) $ 3.05 $ 10.80 $ 1.53 Ameren ($/MWh) $ 46.29 $ 225.62 $ 18.01 COB ($/MWh) $ 58.96 $ 400.10 $ 9.15 ComEd ($/MWh) $ 42.57 $ 222.49 $ 14.98 ERCOT N hub ($/MWh) $ 46.94 $ 324.49 $ 13.66 ERCOT S hub ($/MWh) $ 45.44 $ 320.63 $ 13.88 Indiana hub ($/MWh) $ 49.02 $ 230.14 $ 20.74 Mid C ($/MWh) $ 55.72 $ 400.10 $ 5.15 Minn hub ($/MWh) $ 39.75 $ 183.54 $ 15.23 NoIL hub ($/MWh) $ 42.22 $ 222.18 $ 14.64 PJM W hub ($/MWh) $ 48.80 $ 227.60 $ 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, 2022 Risk of non-performance 0.84% - 0.89% Discount rate 3.99% - 4.22% Forward pricing ($ per KW-month) $2.00 - $3.80

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Derivative Instruments and HedgingOur operating and financing activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our 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, 2022 and 2021, 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, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 30 $ 8 $ 30 $ 7 Derivative liabilities (30) (7) (58) (50) — 1 (28) (43) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral — 1 (28) (43) Cash collateral receivable — — 11 2 Total derivatives as presented in the balance sheet $ — $ 1 $ (17) $ (41) 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) The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (Millions) Wholesale electricity purchase contracts (MWh) 5.7 5.7 Natural gas purchase contracts (Dth) 9.6 9.4 Fleet fuel purchase contracts (Gallons) — 2.0 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, 2022 and 2021 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2022, 2021 and 2020 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2022 Electricity Natural Gas 2022 Electricity Natural Gas Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (127) $ (16) Regulatory liabilities $ — $ — December 31, 2021 2021 Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (23) $ (11) Regulatory liabilities $ (16) $ (3) 2020 Purchased power, natural gas and fuel used $ 55 $ 4 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, 2022, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $56 million, a gross derivative liability of $57 million ($55 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, 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. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2022, 2021 and 2020, respectively, were as follows: Years Ended December 31, 2022 2021 2020 (Millions) Derivative Assets $ (1) $ — $ — Derivative Liabilities $ 18 $ 13 $ 6 Certain foreign currency exchange contracts are not designated as hedging instruments. For the years ended December 31, 2020, we recorded a gain of $4 million, related to our foreign currency contracts not designated as hedging instruments, included in "Other income" in our consolidated statements of income. Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2022, 2021 and 2020, 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) 2022 Interest rate contracts $ — Interest expense $ 4 $ 303 Commodity contracts 2 Purchased power, natural gas and fuel used (3) 2,456 Total $ 2 $ 1 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 (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 $43 million and $47 million as of December 31, 2022 and 2021, respectively. We recorded $4 million in net derivative losses related to discontinued cash flow hedges during each of the years ended December 31, 2022, 2021 and 2020, respectively. We will amortize approximately $4 million of discontinued cash flow hedges in 2023. (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, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (MWh/Dth in Millions) Wholesale electricity purchase contracts 2 4 Wholesale electricity sales contracts 7 10 Natural gas and other fuel purchase contracts 15 20 Financial power contracts 6 9 Basis swaps - purchases 22 30 The fair values of derivative contracts associated with Renewables' activities as of December 31, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (Millions) Wholesale electricity purchase contracts $ 149 $ 36 Wholesale electricity sales contracts (200) (77) Natural gas and other fuel purchase contracts 2 6 Financial power contracts 8 35 Total $ (41) $ — 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, 2022 and 2021, the fair value of the interest rate swap was $116 million and $(58) million, respectively, as a non-current asset and 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, 2022 and 2021, 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, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 121 $ 63 $ 79 $ 4 Derivative liabilities (61) (40) (103) (7) 60 23 (24) (3) Designated as hedging instruments Derivative assets — 116 — 1 Derivative liabilities — — (168) (89) — 116 (168) (88) Total derivatives before offset of cash collateral 60 139 (192) (91) Cash collateral payable — — 105 54 Total derivatives as presented in the balance sheet $ 60 $ 139 $ (87) $ (37) 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) receivable — — 27 57 Total derivatives as presented in the balance sheet $ 18 $ 56 $ (48) $ (81) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2022, 2021 and 2020 consisted of: Year Ended December 31, 2022 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 9 $ 6 Wholesale electricity sales contracts 1 (63) Financial power contracts 1 (52) Financial and natural gas contracts 1 (6) Total loss included in operating revenues $ 12 $ (115) $ 7,923 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 98 Financial and natural gas contracts — 5 Total gain included in purchased power, natural gas and fuel used $ — $ 103 $ 2,456 Total Gain (Loss) $ 12 $ (12) 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) gain 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 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) Gain $ — $ (5) 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, 2022, 2021 and 2020 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) 2022 Interest rate contracts $ 116 Interest Expense $ — $ 303 Commodity contracts $ (178) Operating revenues $ 59 $ 7,923 Total $ (62) $ 59 2021 Interest rate contracts $ (58) Interest Expense $ — $ 298 Commodity contracts $ (142) Operating revenues $ (3) $ 6,974 $ (200) $ (3) 2020 Commodity contracts $ 1 Operating revenues $ 6 $ 6,320 (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 $169 million of loss included in accumulated OCI at December 31, 2022 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, 2022, 2021 and 2020. (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 $38 million and $48 million as of December 31, 2022 and 2021, respectively. We amortized into income $9 million, $9 million and $8 million of the loss related to the settled interest rate contracts for the years ended December 31, 2022, 2021 and 2020, respectively. We will amortize approximately $9 million of the net loss on the interest rate contracts during 2023. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2022, 2021 and 2020 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) 2022 Interest rate contracts $ — Interest expense $ 9 $ 303 2021 Interest rate contracts $ — Interest expense $ 9 $ 298 2020 Interest rate contracts $ (27) Interest expense $ 8 $ 316 (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 years ended December 31, 2022 and 2021 are as follows: Fair value of hedge Location of (Gain) Recognized in Income Statement Loss Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2022 Year Ended December 31, 2022 Current liabilities $ (29) Interest Expense $ 6 $ 303 Non-current liabilities $ (86) Cumulative effect on hedged debt Current debt $ 29 Non-current debt $ 86 Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement (Millions) 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, 2022, UI would have had to post an aggregate of approximately $37 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 $97 million and $67 million as of December 31, 2022 and 2021, 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, 2022 is $13 million, for which we have posted collateral.

Leases

Leases	12 Months Ended
	Dec. 31, 2022
Leases [Abstract]
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 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, 2022, 2021 and 2020 were as follows: For the Year Ended December 31, 2022 2021 2020 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 12 $ 8 $ 17 Interest on lease liabilities 3 3 4 Total finance lease cost 15 11 21 Operating lease cost 20 14 16 Short-term lease cost 6 4 3 Variable lease cost 3 4 — Total lease cost $ 44 $ 33 $ 40 Balance sheet and other information as of December 31, 2022 and 2021 was as follows: As of December 31, 2022 2021 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 159 $ 148 Operating lease liabilities, current 13 12 Operating lease liabilities, long-term 161 149 Total operating lease liabilities $ 174 $ 161 Finance Leases Other assets $ 143 $ 156 Other current liabilities 7 4 Other non-current liabilities 80 91 Total finance lease liabilities $ 87 $ 95 Weighted-average Remaining Lease Term (years) Finance leases 6.4 7.3 Operating leases 16.9 20.5 Weighted-average Discount Rate Finance leases 3.46 % 3.49 % Operating leases 3.69 % 3.06 % For the years ended December 31, 2022, 2021 and 2020 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2022 2021 2020 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 14 $ 16 $ 13 Operating cash flows from finance leases $ 1 $ 3 $ 3 Financing cash flows from finance leases $ 9 $ 6 $ 9 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ (1) $ — $ 46 Operating leases $ 25 $ 10 $ 94 As of December 31, 2022, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2023 $ 9 $ 16 2024 30 14 2025 8 14 2026 9 14 2027 10 16 Thereafter 33 183 Total lease payments 99 257 Less: imputed interest (12) (83) Total $ 87 174 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 $41 million and $45 million at December 31, 2022 and December 31, 2021, 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. During 2022, Renewables elected not to exercise the early buyout option and prospectively adjusted the accounting for the lease, which contains a buyout option at fair value at the end of the lease term. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 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, 2022, 2021 and 2020 were as follows: For the Year Ended December 31, 2022 2021 2020 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 12 $ 8 $ 17 Interest on lease liabilities 3 3 4 Total finance lease cost 15 11 21 Operating lease cost 20 14 16 Short-term lease cost 6 4 3 Variable lease cost 3 4 — Total lease cost $ 44 $ 33 $ 40 Balance sheet and other information as of December 31, 2022 and 2021 was as follows: As of December 31, 2022 2021 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 159 $ 148 Operating lease liabilities, current 13 12 Operating lease liabilities, long-term 161 149 Total operating lease liabilities $ 174 $ 161 Finance Leases Other assets $ 143 $ 156 Other current liabilities 7 4 Other non-current liabilities 80 91 Total finance lease liabilities $ 87 $ 95 Weighted-average Remaining Lease Term (years) Finance leases 6.4 7.3 Operating leases 16.9 20.5 Weighted-average Discount Rate Finance leases 3.46 % 3.49 % Operating leases 3.69 % 3.06 % For the years ended December 31, 2022, 2021 and 2020 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2022 2021 2020 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 14 $ 16 $ 13 Operating cash flows from finance leases $ 1 $ 3 $ 3 Financing cash flows from finance leases $ 9 $ 6 $ 9 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ (1) $ — $ 46 Operating leases $ 25 $ 10 $ 94 As of December 31, 2022, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2023 $ 9 $ 16 2024 30 14 2025 8 14 2026 9 14 2027 10 16 Thereafter 33 183 Total lease payments 99 257 Less: imputed interest (12) (83) Total $ 87 174 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 $41 million and $45 million at December 31, 2022 and December 31, 2021, 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. During 2022, Renewables elected not to exercise the early buyout option and prospectively adjusted the accounting for the lease, which contains a buyout option at fair value at the end of the lease term. 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, 2022
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 $28 million and $8 million, respectively, as of December 31, 2022, which has not changed since December 31, 2021, 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 CAPM for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model, or RPM, in addition to the DCF model and CAPM under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. 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. On August 9, 2022, the D.C. Circuit Court vacated FERC’s orders and remanded the matter back to FERC. The D.C. Circuit Court held that FERC failed to offer a reasoned explanation for its decision to reintroduce the RPM after initially, and forcefully, rejecting it and that because FERC adopted that significant portion of its model in an arbitrary and capricious fashion, the new ROE produced by that model cannot stand. We cannot predict the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for the NETO’s 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 three 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. 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. On June 23, 2022, the administrative law judge issued additional findings and analysis to FERC with respect to the other party in the matter. These did not address any of the Renewables’ claims. The entire case has now been fully remanded to FERC. We cannot predict the outcome of this proceeding. Customer Service Invoice Dispute On May 4, 2021, a buyer under a virtual PPA with a subsidiary of Renewables provided notice that the buyer disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations. The buyer has requested an adjustment to the invoices that would increase the amount payable by approximately $29 million. Renewables has responded in writing stating that the invoice was properly calculated in accordance with the provisions of the PPA. The parties are scheduled to mediate this matter in March 2023 in order to reach a potential resolution. 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, 2022. 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 2022 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, 2022 consisted of: Year Purchases Sales (Millions) 2023 $ 1,066 $ 321 2024 200 137 2025 112 43 2026 86 28 2027 66 22 Thereafter 993 61 Totals $ 2,523 $ 612 Guarantee Commitments to Third Parties As of December 31, 2022, we had approximately $707 million of standby letters of credit, surety bonds, guarantees and indemnifications outstandin g. 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, 2022, neither we nor our subsidiaries have any liabilities recorded for these instruments. NECEC Commitments On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately $9 million was paid through the end of 2021. In December 2021 the remaining future payments were suspended following the halt in construction of the NECEC project.

Environmental Liabilities

Environmental Liabilities	12 Months Ended
	Dec. 31, 2022
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-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; four sites are included in Maine’s Uncontrolled Sites Program; zero 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-four 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 seven of the twenty-four sites. We have paid remediation costs related to the remaining seventeen 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, 2022, our estimate for costs to remediate these sites ranges from $15 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the allocation of the clean-up costs. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry and one site is included in 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, 2022, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $160 million to $260 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, 2022, 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, 2022 and 2021, the liability associated with our MGP sites in Connecticut was $112 million and $113 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, 2022 and 2021, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $289 million and $303 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 2138. 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, 2022 , FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $10 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. This claim was dismissed with prejudice in April 2022 in connection with the settlement agreement between the parties on the below-referenced state claim. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs appealed the court's decision to strike, which decision the Appeals Court affirmed on May 4, 2021. The plaintiffs filed a petition to appeal to the Connecticut Supreme Court, which was denied, leaving only the claim against UI for unjust enrichment. In April 2022, UI entered into a settlement agreement with Evergreen Power and Asnat settling the remaining claim and the lawsuit was withdrawn. 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 December 31, 2022 and 2021, the amount reserved related to English Station was $19 million and $22 million, respectively. 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, 2022
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes In August 2022, the Inflation Reduction Act of 2022 ("IRA") was signed into law in the United States. The IRA created a new corporate alternative minimum tax ("CAMT") of 15% on adjusted financial statement income and an excise tax of 1% on the value of certain stock repurchases. The IRA also contains a number of additional provisions related to tax incentives for investments in renewable energy production, carbon capture, and other climate actions. The CAMT and other various provisions of the IRA will be effective for periods beginning after December 31, 2022. Based on initial guidance, the Company currently expects to be subject to the CAMT starting in 2023 but does not expect it to have a material impact on our earnings, financial condition, or cash flow as the Company can utilize tax attributes to reduce the overall cash tax impact. Given the complexity and uncertainty around the applicability of the legislation to our specific facts and circumstances, we continue to analyze the IRA provisions while waiting on pending Department of Treasury regulatory guidance. 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, 2022, 2021 and 2020 consisted of: Years Ended December 31, 2022 2021 2020 (Millions) Current Federal $ — $ 6 $ 3 State 2 4 9 Current taxes charged to expense 2 10 12 Deferred Federal 67 49 67 State 49 72 38 Deferred taxes charged to expense 116 121 105 Production tax credits (97) (109) (87) Investment tax credits (1) (1) (1) Total Income Tax Expense $ 20 $ 21 $ 29 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, 2022, 2021 and 2020 consisted of: Years Ended December 31, 2022 2021 2020 (Millions) Tax expense at federal statutory rate $ 176 $ 140 $ 119 Depreciation and amortization not normalized (20) (19) (13) Investment tax credit amortization (1) (1) (1) Tax return related adjustments 2 — 1 Production tax credits (97) (109) (87) Tax equity financing arrangements 13 14 1 State tax expense, net of federal benefit 40 61 37 Excess ADIT amortization (66) (65) (42) Valuation allowance (35) 21 12 Other, net 8 (21) 2 Total Income Tax Expense $ 20 $ 21 $ 29 Deferred tax assets and liabilities as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,504 $ 4,257 Unfunded future income taxes 129 104 Federal and state tax credits (942) (844) Federal and state NOL’s (1,086) (998) Joint ventures/partnerships 210 188 Nontaxable grant revenue (270) (292) Pension and other post-retirement benefits (11) 1 Tax Act - tax on regulatory remeasurement (328) (352) Valuation allowance 87 110 Other (80) (158) Deferred Income Tax Liabilities $ 2,213 $ 2,016 Deferred tax assets $ 2,717 $ 2,644 Deferred tax liabilities 4,930 4,660 Net Accumulated Deferred Income Tax Liabilities $ 2,213 $ 2,016 As of December 31, 2022, we had gross federal tax net operating losses of $3.9 billion, federal PTCs and ITCs, federal R&D tax credits and other federal credits of $924 million, state tax effected net operating losses of $346 million in several jurisdictions and miscellaneous state tax credits of $147 million available to carry forward and reduce future income tax liabilities. 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, 2022 and 2021 was $87 million and $110 million, respectively. The $23 million change includes a $37 million decrease related to federal tax credit carryforwards, a $12 million increase related to state net operating losses and tax credit carryforwards and a $2 million increase related to federal net operating losses. The $87 million balance as of December 31, 2022 includes federal net operating loss and tax credit carryforward valuation allowance of $3 million and state net operating loss and state tax credit carryforward valuation allowance of $84 million. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2022, 2021 and 2020 consisted of: Years ended December 31, 2022 2021 2020 (Millions) Beginning Balance $ 127 $ 127 $ 148 Increases for tax positions related to prior years 2 3 11 Increases for tax positions related to current year 2 — — Decreases for tax positions related to prior years (4) (3) (32) Ending Balance $ 127 $ 127 $ 127 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, 2022, 2021 and 2020. If recognized, $107 million of the total gross unrecognized tax benefits would affect the effective tax rate. It is estimated that no unrecognized tax benefits are anticipated to result in a net increase or decrease within 12 months of December 31, 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, 2022, 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, 2022
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, 2022 and 2021, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2022 2021 2022 2021 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 3,487 $ 3,819 $ 408 $ 452 Service cost 27 40 2 3 Interest cost 111 87 10 10 Plan amendments 1 2 — — Actuarial loss (gain) (716) (184) (103) (23) Curtailments/Settlements (274) (38) — — Benefits paid (184) (239) (33) (34) Benefit Obligation as of December 31, 2,452 3,487 284 408 Change in plan assets Fair Value of Plan Assets as of January 1, 3,079 3,092 127 167 Actual return on plan assets (584) 237 (22) 15 Employer contributions 22 27 17 12 Settlements (182) (38) — — Benefits paid (184) (239) (33) (67) Fair Value of Plan Assets as of December 31, 2,151 3,079 89 127 Funded Status as of December 31, $ (301) $ (408) $ (195) $ (281) During 2022, the pension and postretirement benefit obligations had actuarial gains of, respectively, $716 million and $103 million, primarily due to gains from discount rate increases of $644 million and $70 million, respectively. The pension benefit obligation had a reduction of $274 million from settlements ($182 million) and curtailments ($92 million). The settlements were lump-sum payments made within the pension plan guidelines at the discretion of the plan participants who opted to retire. The curtailments were driven by a Company decision to freeze pension benefit accruals and contribution credits for Networks non-union employees and transition their retirement benefits to a 401(k) plan. 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 in 2021. As of December 31, 2022 and 2021, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2022 2021 2022 2021 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (301) (408) (190) (276) Total $ (301) $ (408) $ (195) $ (281) 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, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2022 2021 2022 2021 (Millions) Net loss (gain) $ 181 $ 271 $ (91) $ (18) Prior service cost (credit) $ 7 $ 10 $ (1) $ (1) Amounts recognized in OCI for ARHI for the years ended December 31, 2022 and 2021, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2022 2021 2022 2021 (Millions) Net loss (gain) $ 12 $ 16 $ (6) $ (5) As of December 31, 2022 and 2021, 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 of our qualified plans, as of December 31, 2022, and for all but one plan, as of December 31, 2021. 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, 2022 2021 (Millions) Projected benefit obligation $ 2,452 $ 3,487 Fair value of plan assets $ 2,151 $ 3,079 ABO in excess of plan assets As of December 31, 2022 2021 (Millions) Accumulated benefit obligation $ 2,429 $ 1,790 Fair value of plan assets $ 2,151 $ 1,536 As of December 31, 2022 and 2021, 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, 2022, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2022 2021 2020 2022 2021 2020 (Millions) Net Periodic Benefit Cost: Service cost $ 26 $ 39 $ 46 $ 2 $ 3 $ 3 Interest cost 109 86 106 10 10 13 Expected return on plan assets (162) (199) (198) (6) (7) (8) Amortization of prior service cost (benefit) 1 2 1 (1) (5) (9) Amortization of net loss 49 115 124 (4) 2 2 Settlement charge 17 6 — — Curtailment charge (32) — — — — — Net Periodic Benefit Cost 8 49 79 1 3 1 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments (59) — (18) — — — Settlement charge (17) (6) — — — — Net loss (gain) 33 (218) 46 (75) (31) 11 Amortization of net loss (49) (115) (124) 4 (2) (2) Current year prior service cost (credit) 1 2 7 — 1 — Amortization of prior service (cost) benefit (1) (2) (1) 1 5 9 Total Other Changes (92) (339) (90) (70) (27) 18 Total Recognized $ (84) $ (290) $ (11) $ (69) $ (24) $ 19 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, 2022, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2022 2021 2020 2022 2021 2020 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ 1 $ — $ — $ — Interest cost 2 1 1 — — — Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) 1 2 2 (1) (1) (1) Settlement/Curtailment charge 1 1 1 — — — Net Periodic Benefit Cost 3 3 3 (1) (1) (1) Other Changes in plan assets and benefit obligations recognized in OCI: Settlement charge (1) (1) — (1) (1) — Net loss (gain) (1) (3) 1 (1) 1 — Amortization of net (loss) gain (1) (2) (2) 1 1 1 Amortization of prior service cost — — — — — — Total Other Changes (3) (6) (1) (1) 1 1 Total Recognized $ — $ (3) $ 2 $ (2) $ — $ — The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the service cost component in other operating expenses net of capitalized portion and include the components of net periodic benefit cost other than the service cost component in other expense. The weighted-average assumptions used to determine our benefit obligations as of December 31, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2022 2021 2022 2021 Discount rate 5.18 % 2.85 % 5.12 % 2.66 % Rate of compensation increase 2.99 % 3.53 % 3.00 % 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, 2022, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2022 2021 2020 2022 2021 2020 Discount rate 2.85 % 2.34 % 3.01 % 2.66 % 2.19 % 2.99 % Expected long-term return on plan assets 6.33 % 7.30 % 7.30 % 4.66 % 4.05 % 5.09 % Rate of compensation increase 3.53 % 3.52 % 3.66 % 3.50 % 3.50 % 3.48 % 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, 2022 and 2021 consisted of: As of December 31, 2022 2021 Health care cost trend rate assumed for next year 5.00%/6.50% 5.00%/7.00% 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 $0 and $9 million, respectively, to our pension and other postretirement benefit plans during 2023. Estimated Future Benefit Payments Expected benefit payments as of December 31, 2022 consisted of: (Millions) Pension Benefits Postretirement Benefits 2023 $ 233 $ 28 2024 $ 218 $ 27 2025 $ 215 $ 26 2026 $ 211 $ 25 2027 $ 206 $ 24 2028 - 2032 $ 938 $ 108 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 $44 million and $63 million at December 31, 2022 and 2021, 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 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, 2022, consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 51 $ — $ 51 $ — U.S. government securities 252 252 — — Common stocks 57 57 — — Registered investment companies 104 104 — — Corporate bonds 708 — 708 — Preferred stocks 1 1 — — Common collective trusts 472 — 472 — Other, principally annuity, fixed income 33 — 33 — $ 1,678 $ 414 $ 1,264 $ — Other investments measured at net asset value 473 Total $ 2,151 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 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 58% 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, 2022 consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 2 $ — $ 2 $ — U.S. government securities 1 1 — — Registered investment companies 69 69 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 8 — 8 — $ 87 $ 70 $ 17 $ — Other investments measured at net asset value 2 Total $ 89 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 — — Registered investment companies 101 101 — — Corporate bonds 3 — 3 — 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 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, 2022 and 2021. 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, 2022, 2021 and 2020, the annual contributions we made to these plans was $68 million, $58 million and $49 million, respectively.

Equity

Equity	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Equity	Equity As of December 31, 2022 and 2021, we had 108,188 and 112,543 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2022 and 2021, we issued 56,127 and 77,883,713 shares of common stock, respectively, and released 4,355 and 301,239 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 relative ownership percentage of approximately 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2022, there were no repurchases pursuant to the stock repurchase program. As of December 31, 2022, 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, 2022, the total cost of all repurchases, including commissions, was $47 million. Accumulated OCI (Loss) Accumulated OCI (Loss) for the years ended December 31, 2022, 2021 and 2020 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2019 2020 Change As of December 31, 2020 2021 Change As of December 31, 2021 2022 Change As of December 31, 2022 (Millions) Loss (gain) for defined benefit plans, net of income tax expense of $0 for 2020, $0 for 2021 and $3 for 2022 $ (12) $ — $ (12) $ 2 $ (10) $ 14 $ 4 Amortization of pension cost, net of income tax expense (benefit) of $3 for 2020, $(1) for 2021 and $1 for 2022 (7) (13) (20) (8) (28) 4 (24) Unrealized (loss) gain from equity method investment, net of income tax (benefit) expense of $0 for 2020, $(3) for 2021 and $6 for 2022 (a) $ — $ — $ — $ (9) $ (9) $ 22 $ 13 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 benefit of $(7) for 2020, $(44) for 2021 and $0 for 2022 (13) (22) (35) (159) (194) (1) (195) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $2 for 2020, $(3) for 2021 and $19 for 2022 (b) (63) 19 (44) 12 (32) 54 22 Loss on derivatives qualifying as cash flow hedges (76) (3) (79) (147) (226) 53 (173) Accumulated Other Comprehensive Loss $ (95) $ (16) $ (111) $ (162) $ (273) $ 93 $ (180) (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, 2022
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the years ended December 31, 2021 and 2020, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations for the years ended December 31, 2021 and 2020. The dilutive securities, which consist of performance and restricted units, did result in a change in our earnings per share calculation for the year ended December 31, 2022. The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2022, 2021 and 2020, respectively, consisted of: Years Ended December 31, 2022 2021 2020 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 881 $ 707 $ 581 Denominator: Weighted average number of shares outstanding - basic 386,727,246 358,086,621 309,494,939 Weighted average number of shares outstanding - diluted 387,215,785 358,578,608 309,559,387 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 2.28 $ 1.97 $ 1.88 Earnings Per Common Share, Diluted $ 2.27 $ 1.97 $ 1.88

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2022
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 April 29, 2022, we closed on a TEF agreement, receiving $14 million from a tax equity investor related to the Lund Hill solar farm that reached partial mechanical completion on the same date. A further investment from our investor is expected shortly after the project’s commercial operations in the estimated amount of $58 million, expected in 2023. Lund Hill is owned by Solis Solar Power I, LLC (Solis I). In June 2022 we received an additional $109 million from a tax equity investor for the addition of Golden Hill wind farms under Aeolus Wind Power VIII, LLC (Aeolus VIII). Montague solar was contributed to Aeolus VIII at the same time, with a future investment from our investor in the estimated amount of $87 million expected after Montague solar project reaches commercial operations, expected in the second quarter of 2023. As of December 31, 2022, the assets and liabilities of the VIEs totaled approximately $2,853 million and $424 million, respectively. As of December 31, 2021, the assets and liabilities of VIEs totaled approximately $2,039 million and $119 million, respectively. At both December 31, 2022 and 2021, 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, 2022, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus Wind Power VII, LLC (Aeolus VII), Aeolus VIII, and Solis I are our consolidated VIEs. Our El Cabo, Patriot, Aeolus VII, Aeolus VIII, and Solis I 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 VIEs we do not consolidate.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2022
Other Liabilities Disclosure [Abstract]
Grants, Government Incentives and Deferred Income	Grants, Government Incentives and Deferred Income The changes in government grants recorded in deferred income as of December 31, 2022 and 2021 consisted of: (Millions) Government grants - Renewables Other deferred income Total 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 Disposals — — — Recognized in income (65) (3) (68) As of December 31, 2022 $ 1,060 $ 2 $ 1,062 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). The changes in government grants recorded as a reduction to the related utility plant as of December 31, 2022 and 2021 consisted of: (Millions) Government grants - Networks Total As of December 31, 2020 $ 67 $ 67 Disposals — — Recognized in income (4) (4) As of December 31, 2021 63 63 Disposals — — Recognized in income (4) (4) As of December 31, 2022 $ 59 $ 59 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 government. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2022 and 2021.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2022
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 both December 31, 2022, and 2021, the carrying value of our Tatanka investment was $23 million. On December 13, 2019, Renewables transferred a 50% ownership interest in a wind farm and a solar project located in Arizona (Poseidon) to Axium involving total consideration of $112 million, excluding closing costs, and recognized a gain of $96 million, net of tax. The 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, 2022 and 2021, the carrying value of our Poseidon investment was $87 million and $96 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 account for the remaining 20% membership interest under the equity method of accounting. As of both December 31, 2022 and 2021, the carrying amount of our Coyote Ridge investment was $15 million. 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, 2022 and 2021, the carrying amount of Flat Rock I was $90 million and $93 million, respectively, and Flat Rock II was $42 million and $44 million, respectively. As of December 31, 2022, Renewables holds a 50% indirect ownership interest in Vineyard Wind 1, LLC (Vineyard Wind 1), a joint venture with Copenhagen Infrastructure Partners (CIP). Prior to a restructuring transaction that took place on January 10, 2022 (Restructuring Transaction), Renewables held a 50% ownership interest in Vineyard Wind, LLC (Vineyard Wind) which held rights to two easements from the U.S. Bureau of Ocean Energy Management (BOEM) for the development of offshore wind generation, Lease Area 501 which contained 166,886 acres and Lease Area 522 which contained 132,370 acres, both located southeast of Martha’s Vineyard. Lease Area 501 was subsequently subdivided in 2021, creating Lease Area 534. On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Among other items, the Vineyard Wind 1 project was transferred into a separate joint venture, Vineyard Wind 1. Following the Restructuring Transaction, Vineyard Wind 1 remained a 50-50 joint venture and kept the rights to develop Lease Area 501, and Vineyard Wind was effectively dissolved where Renewables received rights to the Lease Area 534 and CIP received rights to Lease Area 522 as liquidating distributions. In contemplation of the liquidating distributions, Renewables also made an incremental payment of approximately $168 million to CIP. Consequently, Renewables recognized a pretax gain of $246 million and an after tax gain of $181 million, driven by the increase in the market value of its acquired interest in the leases and related development activities over its carrying value. The gain is classified in Earnings from equity method investments in the condensed consolidated statement of income. Concurrently with the closing on the construction financing for the Vineyard Wind 1 project, 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 for the Vineyard Wind 1 project were returned in 2021. Vineyard Wind 1 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 of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. As of December 31, 2022 and 2021, the carrying amount of Renewables' investments in Vineyard Wind, which was dissolved in 2022, and Vineyard Wind 1 was $9 million and $141 million, respectively. Networks is a party to a 50-50 joint venture with Clearway Energy, Inc. in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is accounted for as an equity investment. As of December 31, 2022 and 2021, the carrying value of our GenConn investment was $94 million and $99 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. The investment in New York TransCo is accounted for as an equity investment. As of December 31, 2022 and 2021, the carrying value of our New York TransCo investment was $77 million and $49 million, respectively.

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Other Financial Statement Items	Other Financial Statement Items Other income (expense) Other income (expense) for the years ended December 31, 2022, 2021 and 2020 consisted of: Years ended December 31, 2022 2021 2020 (Millions) Gain on sale of assets (a) $ — $ — $ 20 Allowance for funds used during construction 63 88 56 Carrying costs on regulatory assets 16 17 28 Non-service component of net periodic benefit cost (58) (37) (62) Other 9 (8) (24) Total Other Income (Expense) $ 30 $ 60 $ 18 (a) 2020 includes a $16 million gain from the Tatanka sale (see Note 22). Accounts receivable and unbilled revenues, net Accounts receivable and unbilled revenues, net as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Trade receivables and unbilled revenues $ 1,892 $ 1,420 Allowance for credit losses (155) (151) Total Accounts receivable and unbilled revenues, net $ 1,737 $ 1,269 The change in the allowance for credit losses as of December 31, 2022 and 2021 consisted of: (Millions) 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 Current period provision 110 Write-off as uncollectible (106) As of December 31, 2022 $ 155 DPA receivable balances were $102 million and $108 million as of December 31, 2022 and 2021, respectively. As of December 31, 2022 and 2021, our allowance for credit losses for DPAs was $67 million and $68 million, respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Prepaid other taxes $ 136 $ 95 Broker margin and collateral accounts 164 87 Other pledged deposits 12 4 Prepaid expenses 68 58 Other 6 1 Total $ 386 $ 245 Other current liabilities Other current liabilities as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Advances received $ 271 $ 204 Accrued salaries 153 127 Short-term environmental provisions 54 52 Collateral deposits received 68 58 Pension and other postretirement 5 5 Finance leases 7 4 Other 35 34 Total $ 593 $ 484 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, 2022
Segment Reporting [Abstract]
Segment Information	Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments, accelerated depreciation derived from repowering of wind farms, costs incurred related to the PNMR Merger, a legal settlement, an offshore contract provision and costs incurred in connection with the COVID-19 pandemic. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our 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, 2022 consisted of: For the Year Ended December 31, 2022 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 6,781 $ 1,141 $ 1 $ 7,923 Revenue - intersegment 1 — (1) — Depreciation and amortization 660 424 1 1,085 Operating income 901 (36) (13) 852 Earnings (losses) from equity method investments 11 251 — 262 Interest expense, net of capitalization 220 16 67 303 Income tax expense (benefit) 94 (114) 40 20 Capital expenditures 1,803 708 8 2,519 Adjusted net income 628 403 (130) 901 As of December 31, 2022 Property, plant and equipment 20,027 10,950 17 30,994 Equity method investments 171 266 — 437 Total assets $ 28,069 $ 13,553 $ (499) $ 41,123 (a) Includes Corporate and intersegment eliminations. 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 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 (a) Includes Corporate and intersegment eliminations. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2022, 2021 and 2020 is as follows: Years Ended December 31, 2022 2021 2020 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 901 $ 780 $ 625 Adjustments: Mark-to-market adjustments - Renewables (1) — (53) (5) Offshore contract provision (2) (24) — — Restructuring charges (3) — — (6) Accelerated depreciation from repowering (4) — — (9) Impact of COVID-19 (5) — (34) (29) Merger costs (6) (4) (12) (6) Legal settlement - Gas storage (7) — — (5) Income tax impact of adjustments 7 26 16 Net Income Attributable to Avangrid, Inc. $ 881 $ 707 $ 581 (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) Costs incurred in connection with an offshore contract provision. (3) Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth. (4) Represents the amount of accelerated depreciation derived from repowering wind farms in Renewables. (5) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (6) Pre-merger costs incurred. (7) 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, 2022
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the years ended December 31, 2022, 2021 and 2020, respectively, consisted of: Years Ended December 31, 2022 2021 2020 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ 1 $ (46) $ — $ (52) $ 1 $ (43) Iberdrola Renovables Energia, S.L. $ 1 $ (5) $ — $ (10) $ — $ (9) Iberdrola Financiación, S.A. $ — $ (12) $ — $ (9) $ — $ (7) Vineyard Wind $ 7 $ — $ 14 $ — $ 9 $ — Iberdrola Solutions $ — $ — $ 7 $ (39) $ 2 $ — Other $ 1 $ (3) $ 2 $ (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, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 1 $ (29) $ 3 $ (43) Iberdrola Financiacion $ — $ (9) $ — $ (9) Vineyard Wind $ 3 $ (8) $ 8 $ (8) Iberdrola Solutions $ — $ (2) $ — $ (2) Other $ 4 $ (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, 2022 and 2021 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, 2022 and 2021, 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 balance of $2 million as of both December 31, 2022 and 2021. Renewables had financial forward power contracts with Iberdrola Solutions to hedge Renewables' merchant wind exposure in Texas that were settled in 2021. 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, 2022
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation	Stock-Based Compensation The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares). As of December 31, 2022, 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 to be earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes. 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, 45,611 shares of common stock were issued to settle the second installment payment. The final payment will occur in 2022. In March 2022, 46,737 shares of common stock were issued to settle the third and final installment payment under this plan. During 2021 and 2022, 1,336,787 PSUs and 215,235 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. In June 2022, 25,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in two equal installments in 2023 and 2024, 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 $47.64 per share. The 1st installment of this RSU grant was settled in January 2023, net of applicable taxes, by issuing 8,690 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 March 2022, $2 million was paid to settle the third and final installment under this plan. In February 2022, 9,000 Phantom Shares were granted to certain AVANGRID executives and employees. These awards vest in three equal installments in 2022 - 2024 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 August 2022, $0.1 million was paid to settle the first installment under this plan. On February 16, 2023, 81,000 Phantom Shares were granted to certain AVANGRID executives and employees. These awards will vest in three equal installments in 2024, 2025 and 2026 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. As of December 31, 2022 and 2021, the total liability was $0 and $2 million, respectively, 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, 2022, 2021 and 2020 was $15 million, $18 million and $14 million, respectively. The total income tax benefits recognized for stock-based compensation arrangements for each of the years ended December 31, 2022, 2021 and 2020, were $4 million, $5 million and $4 million, respectively. A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2022, and changes during the fiscal year ended December 31, 2022, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2021 1,323,328 $ 36.05 Granted 258,168 $ 38.16 Forfeited (412,776) $ 36.21 Vested (83,770) $ 45.91 Nonvested Balance – December 31, 2022 1,084,951 $ 36.55 As of December 31, 2022, total unrecognized costs for non-vested PSUs, RSUs and Phantom Shares was $10 million. The weighted-average period over which the PSU, RSU and Phantom Shares costs will be recognized is approximately 2 years. The weighted-average grant date fair value of PSUs and RSUs granted during the year was $38.16 per share for the year ended December 31, 2022.

Subsequent events

Subsequent events	12 Months Ended
	Dec. 31, 2022
Subsequent Events [Abstract]
Subsequent events	Subsequent eventsOn February 16, 2023, 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 3, 2023 to shareholders of record at the close of business on March 1, 2023.

CONDENSED FINANCIAL INFORMATION

CONDENSED FINANCIAL INFORMATION OF PARENT	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021 AND 2020 Years Ended December 31, 2022 2021 2020 (Millions) Operating Revenues $ — $ — $ — Operating Expenses Operating expense 11 19 10 Taxes other than income taxes (1) (11) (11) Total Operating Expenses 10 8 (1) Operating (Loss) Income (10) (8) 1 Other Income Other income 49 22 35 Equity earnings of subsidiaries 999 756 641 Interest expense (117) (93) (109) Income Before Income Tax 921 677 568 Income tax expense (benefit) 40 (30) (13) Net Income $ 881 $ 707 $ 581 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, 2022, 2021, AND 2020 Years Ended December 31, 2022 2021 2020 (Millions) Net Income $ 881 $ 707 $ 581 Other comprehensive income (loss) of subsidiaries 93 (162) (16) Comprehensive Income $ 974 $ 545 $ 565 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, 2022 AND 2021 As of December 31, 2022 2021 (Millions) Assets Current Assets Cash and cash equivalents $ 28 $ 1,424 Accounts receivable from subsidiaries 190 128 Notes receivable from subsidiaries 1,440 1,475 Prepayments and other current assets 17 52 Total current assets 1,675 3,079 Investments in subsidiaries 20,588 18,500 Other assets Deferred income taxes 358 413 Other 3 3 Total other assets 361 416 Total Assets $ 22,624 $ 21,995 Liabilities Current Liabilities Notes payable 396 — Notes payable to subsidiaries 557 643 Accounts payable and accrued liabilities 7 3 Accounts payable to subsidiaries 3 9 Interest accrued 9 9 Interest accrued subsidiaries 9 1 Dividends payable 170 170 Other current liabilities 30 — Total current liabilities 1,181 835 Derivative liabilities 86 19 Non-current debt 1,977 2,065 Total non-current liabilities 2,063 2,084 Total Liabilities 3,244 2,919 Equity Stockholders' Equity: Common stock 3 3 Additional paid-in capital 17,694 17,679 Treasury stock (47) (47) Retained earnings 1,910 1,714 Accumulated other comprehensive loss (180) (273) Total Equity 19,380 19,076 Total Liabilities and Equity $ 22,624 $ 21,995 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, 2022, 2021, AND 2020 Years Ended December 31, 2022 2021 2020 (Millions) Net Cash used in Operating Activities $ (742) $ (397) $ (142) Cash Flow from Investing Activities Notes receivable from subsidiaries (14) 130 (73) Investments in subsidiaries (1,020) (1,026) (591) Return of capital from investments in subsidiaries 664 1,122 419 Other investments — 300 (300) Net Cash (used in) provided by Investing Activities (370) 526 (545) Cash Flow from Financing Activities Receipts (repayments) of short-term notes payable from subsidiaries, net 1 (186) (14) Receipts (repayments) of short-term notes payable 397 (309) (253) Proceeds from non-current debt — — 744 (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 (1) 3,998 (1) Dividends paid (681) (613) (545) Net Cash (used in) provided by Financing Activities (284) (143) 1,979 Net (Decrease) Increase in Cash and Cash Equivalents (1,396) (14) 1,292 Cash and Cash Equivalents, Beginning of Year 1,424 1,438 146 Cash and Cash Equivalents, End of Year $ 28 $ 1,424 $ 1,438 Supplemental Cash Flow Information Cash paid for interest $ 86 $ 74 $ 111 Cash paid (refunded) payment for income taxes $ (33) $ (15) $ 65 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 was 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 acknowledged in the Amendment that the required regulatory approval from the NMPRC had not been obtained and that the parties reasonably determined that such outstanding approval would 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). During the pendency of the appeal described above, 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. For example, AVANGRID and PNMR are preparing new filings under HSR. We cannot predict the outcome of these re-applications or requests for extensions of such 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 set 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, 2022, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 387,734,757 shares issued and 386,628,586 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 $17,694 million. 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 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 $17,679 million. As of December 31, 2022 and 2021, we had 108,188 and 112,543 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2022 and 2021, we issued 56,127 and 77,883,713 shares of common stock, respectively, and released 4,355 and 301,239 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 2022, there were no repurchases pursuant to the stock repurchase program. As of December 31, 2022, 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, 2022, the total cost of all repurchases, including commissions, was $47 million. On February 16, 2023, 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 3, 2023 to shareholders of record at the close of business on March 1, 2023. 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. 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 in 2021 with the proceeds of the common share issuance described in Note 1. Cash dividends paid by subsidiary are as follows: Years ended December 31, 2022 2021 2020 (millions) AVANGRID Networks $ 645 $ 970 $ 419 AVANGRID Renewables $ 19 $ 152 $ — For the years ended December 31, 2022, 2021 and 2020, AVANGRID made capital contributions to Networks of $986 million, $1,011 million and $590 million, respectively. During 2022 and 2021, AVANGRID recorded a net non-cash contribution and dividend of $473 million and $674 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, 2022
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 and 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, 2022 and 2021, 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 $33 million and $16 million at December 31, 2022 and 2021, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $33 million, $22 million and $21 million as revenue related to contract liabilities for the years ended December 31, 2022, 2021 and 2020, respectively. 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 primarily 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 and other equity investments 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 equity method investments as a reduction in the carrying amount of the investment and not as dividend income. When an equity method investee executes derivative transactions that have cash flow hedge accounting treatment, we recognize our share of the OCI in our consolidated balance sheet. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary.
Goodwill and other intangible assets	Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four
Property, plant and equipment	Property, plant and equipment We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment. We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service. We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation. We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations 25-40 Solar power stations 30 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. Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation was 2.8% of average depreciable property for both 2022 and 2021. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income.
Leases	Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on the information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes an option to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets.
Impairment of long-lived assets	Impairment of long-lived assetsWe evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset.
Fair value measurement	Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e.
Equity investments with readily determinable fair values	Equity investments with readily determinable fair valuesWe measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.
Derivatives and hedge accounting	Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. 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 receivables and unbilled revenues, net of allowance for credit losses	Trade receivables and unbilled revenues, 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 required them to offer to customers a 24-month repayment plan through June 30, 2022. 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	Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.”
Government grants and Deferred income	Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses. (t ) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.
Asset retirement obligations	Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. We record AROs for the decommissioning of the wind and solar farms and thermal facilities. Projected removal costs are based on engineering estimates which are updated on an annual basis based on the relevant inflation and discount rate factors. 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. If a plan meets settlement or curtailment criteria, we recognize a regulatory asset of liability if these costs are probable of recovery from ratepayers. 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 regulatory assets and liabilities for the net revenue requirements to be recovered from or refunded to customers for the related future tax expense or benefit 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. We consider the effect of the corporate alternative minimum tax system in determining the need for a valuation allowance for deferred taxes. 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) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification In March 2020, the FASB issued amendments for recognizing the effects of reference rate reform on financial reporting, from the cessation of the London Interbank Offered Rate (LIBOR). The guidance provides optional expedients and exceptions to contract modifications, hedging relationships, and other transactions that reference LIBOR, subject to meeting certain criteria. Our adoption of reference rate reform did 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 guidance that requires an entity to provide certain annual disclosures about government assistance received and accounted for by applying a grant or contribution accounting model by analogy. As the guidance is disclosure only, it did not have an impact to the consolidated financial results. 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) Disclosure of Supplier Finance Program Obligations In September 2022, the FASB issued new disclosure requirements for supplier finance programs. These requirements include key terms of the program, the amount of obligations that remain unpaid at the end of an accounting period, a description of where those obligations are presented in the balance sheet and a roll forward of those obligations during the annual period. The guidance is effective for disclosures starting in 2023, including interim periods, except for the roll forward information, which is effective for annual periods starting in 2024. Our adoption of the guidance on January 1, 2023 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 derived from HLBV (hypothetical liquidation at book value) accounting. 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.
Union collective bargaining agreements	Union collective bargaining agreementsWe have approximately 46.0% of our employees covered by a collective bargaining agreement. There are no union contracts that are scheduled to expire in 2023.

Summary of Significant Accoun_3

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2022
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 30 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, 2022, consisted of: As of December 31, 2022 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 18,634 $ 14,096 $ 32,730 Natural gas transportation, distribution and other 5,392 14 5,406 Other common operating property — 317 317 Total Property, Plant and Equipment in Service 24,026 14,427 38,453 Total accumulated depreciation (6,277) (5,265) (11,542) Total Net Property, Plant and Equipment in Service 17,749 9,162 26,911 Construction work in progress 2,225 1,858 4,083 Total Property, Plant and Equipment $ 19,974 $ 11,020 $ 30,994 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

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021 and 2020 are as follows: Year Ended December 31, 2022 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,610 $ — $ — $ 4,610 Regulated operations – natural gas 1,931 — — 1,931 Nonregulated operations – wind — 947 — 947 Nonregulated operations – solar — 36 — 36 Nonregulated operations – thermal — 96 — 96 Other (a) 117 48 — 165 Revenue from contracts with customers 6,658 1,127 — 7,785 Leasing revenue 8 — — 8 Derivative revenue — 4 — 4 Alternative revenue programs 68 — — 68 Other revenue 48 10 — 58 Total operating revenues $ 6,782 $ 1,141 $ — $ 7,923 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 — 1028 — 1028 Nonregulated operations – solar — 20 — 20 Nonregulated operations – thermal — 63 — 63 Other (a) 67 84 — 151 Revenue from contracts with customers 5,598 1195 — 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 (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, 2022, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2022 2023 2024 2025 2026 2027 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ — $ — $ — $ — $ 2 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 46 45 17 5 1 2 116 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 81 34 12 10 7 60 204 Total operating revenues $ 128 $ 80 $ 29 $ 15 $ 8 $ 62 $ 322

Industry Regulation (Tables)

Industry Regulation (Tables)	12 Months Ended
	Dec. 31, 2022
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 % Requested Revenue Change May 26, 2022 August 12, 2022 Difference Utility (Millions) (Millions) (Millions) NYSEG Electric $ 274 $ 274 $ — NYSEG Gas $ 43 $ 30 $ (13) RG&E Electric $ 94 $ 93 $ (1) RG&E Gas $ 38 $ 32 $ (6)

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Pension and other post-retirement benefits $ 365 $ 545 Pension and other post-retirement benefits cost deferrals 93 95 Storm costs 671 448 Rate adjustment mechanism 41 68 Revenue decoupling mechanism 52 68 Transmission revenue reconciliation mechanism 11 15 Contracts for differences 56 73 Hardship programs 33 24 Plant decommissioning 1 2 Deferred purchased gas 56 52 Deferred transmission expense — 13 Environmental remediation costs 248 256 Debt premium 64 71 Unamortized losses on reacquired debt 19 23 Unfunded future income taxes 492 424 Federal tax depreciation normalization adjustment 137 142 Asset retirement obligation 20 20 Deferred meter replacement costs 55 46 COVID-19 cost recovery and late payment surcharge 17 21 Low income arrears forgiveness 31 — Excess generation service charge 24 6 System Expansion 21 12 Non-bypassable charge 14 10 Other 247 213 Total regulatory assets 2,768 2,647 Less: current portion 447 400 Total non-current regulatory assets $ 2,321 $ 2,247
Schedule of Regulatory Liabilities	Regulatory liabilities as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Energy efficiency portfolio standard $ 30 $ 45 Gas supply charge and deferred natural gas cost 15 7 Pension and other post-retirement benefits cost deferrals 117 73 Carrying costs on deferred income tax bonus depreciation 9 23 Carrying costs on deferred income tax - Mixed Services 263(a) 3 7 2017 Tax Act 1,232 1,327 Rate change levelization 25 99 Revenue decoupling mechanism 13 13 Accrued removal obligations 1,178 1,192 Asset sale gain account — 2 Economic development 20 26 Positive benefit adjustment 16 22 Theoretical reserve flow thru impact 3 6 Deferred property tax 17 22 Net plant reconciliation 11 16 Debt rate reconciliation 32 49 Rate refund – FERC ROE proceeding 36 35 Transmission congestion contracts 31 23 Merger-related rate credits 10 12 Accumulated deferred investment tax credits 22 24 Asset retirement obligation 18 18 Earning sharing provisions 13 13 Middletown/Norwalk local transmission network service collections 17 17 Low income programs 18 25 Non-firm margin sharing credits 27 15 New York 2018 winter storm settlement 1 5 Hedges gains — 19 Non by-passable charges 76 11 Transmission revenue reconciliation mechanism 75 9 Other 204 174 Total regulatory liabilities 3,269 3,329 Less: current portion 354 307 Total non-current regulatory liabilities $ 2,915 $ 3,022

Goodwill and Intangible assets

Goodwill and Intangible assets (Tables)	12 Months Ended
	Dec. 31, 2022
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (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, 2022 and 2021: As of December 31, 2022 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 590 $ (313) $ 277 Other 22 (18) 4 Total Intangible Assets $ 612 $ (331) $ 281 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
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2022, to be as follows: Year ending December 31, Amount (Millions) 2023 $ 14 2024 $ 14 2025 $ 14 2026 $ 13 2027 $ 13

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2022
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 30 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, 2022, consisted of: As of December 31, 2022 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 18,634 $ 14,096 $ 32,730 Natural gas transportation, distribution and other 5,392 14 5,406 Other common operating property — 317 317 Total Property, Plant and Equipment in Service 24,026 14,427 38,453 Total accumulated depreciation (6,277) (5,265) (11,542) Total Net Property, Plant and Equipment in Service 17,749 9,162 26,911 Construction work in progress 2,225 1,858 4,083 Total Property, Plant and Equipment $ 19,974 $ 11,020 $ 30,994 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

Asset retirement obligations (T

Asset retirement obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2022 and 2021 consisted of: (Millions) 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 Liabilities settled during the year (1) Liabilities incurred during the year 13 Accretion expense 14 Revisions in estimated cash flows (a) (6) As of December 31, 2022 $ 273 (a) Represents an increase (decrease) 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, 2022
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2025-2052 $ 2,882 1.85%-8.00% $ 2,759 1.85%-8.00% Unsecured pollution control notes - fixed 2023-2029 545 1.40%-4.00% 478 1.40%-4.00% Other various non-current debt - fixed 2023-2052 5,276 1.95%-6.66% 5,110 1.95%-6.66% Unamortized debt issuance costs and discount (76) (53) Total Debt 8,627 8,294 Less: debt due within one year, included in current liabilities 412 372 Total Non-current Debt $ 8,215 $ 7,922 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $8,331 million. 2022 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity UI 1/31/2022 Unsecured Notes $ 150 2.25% 2032 NYSEG 4/6/2022 Tax Exempt Bond $ 67 4.00% 2028 NYSEG 12/15/2022 Unsecured Notes $ 150 4.62% 2032 NYSEG 12/15/2022 Unsecured Notes $ 125 4.96% 2052 RG&E 12/15/2022 First Mortgage Bonds $ 125 4.86% 2052 CMP 12/15/2022 Green First Mortgage Bonds $ 75 4.37% 2032 CMP 12/15/2022 Green First Mortgage Bonds $ 50 4.76% 2052 UI 12/15/2022 Unsecured Notes $ 50 4.62% 2032
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: 2023 2024 2025 2026 2027 Total (Millions) $ 412 $ 612 $ 1,107 $ 660 $ 484 $ 3,275

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2022
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 35 $ 13 $ — $ — $ 48 Derivative assets Derivative financial instruments - power $ 37 $ 55 $ 165 $ (177) $ 80 Derivative financial instruments - gas 1 47 — (45) 3 Contracts for differences — — 1 — 1 Derivative financial instruments – Other — 116 — — 116 Total $ 38 $ 218 $ 166 $ (222) $ 200 Derivative liabilities Derivative financial instruments - power $ (46) $ (350) $ (93) $ 364 $ (125) Derivative financial instruments - gas (4) (26) — 30 — Contracts for differences — — (57) — (57) Derivative financial instruments – Other — (115) — — (115) Total $ (50) $ (491) $ (150) $ 394 $ (297) 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 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)
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, 2022, 2021 and 2020 consisted of: (Millions) 2022 2021 2020 Fair value as of January 1, $ (69) $ 13 $ 25 Gains for the year recognized in operating revenues 108 21 8 Losses for the year recognized in operating revenues (30) (34) (2) Total gains or losses for the period recognized in operating revenues 78 (13) 6 Gains recognized in OCI 2 2 1 Losses recognized in OCI (57) (52) (3) Total gains or losses recognized in OCI (55) (50) (2) Net change recognized in regulatory assets and liabilities 17 13 6 Purchases 10 (17) (2) Settlements 8 (13) (15) Transfers out of Level 3 (a) 27 (2) (5) Fair value as of December 31, $ 16 $ (69) $ 13 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 $ 78 $ (13) $ 6 (a) Transfers out of Level 3 were the result of increased observability of market data. Range at Unobservable Input December 31, 2022 Risk of non-performance 0.84% - 0.89% Discount rate 3.99% - 4.22% Forward pricing ($ per KW-month) $2.00 - $3.80
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2022. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.18 $ 9.86 $ 2.27 AECO ($/MMBtu) $ 3.05 $ 10.80 $ 1.53 Ameren ($/MWh) $ 46.29 $ 225.62 $ 18.01 COB ($/MWh) $ 58.96 $ 400.10 $ 9.15 ComEd ($/MWh) $ 42.57 $ 222.49 $ 14.98 ERCOT N hub ($/MWh) $ 46.94 $ 324.49 $ 13.66 ERCOT S hub ($/MWh) $ 45.44 $ 320.63 $ 13.88 Indiana hub ($/MWh) $ 49.02 $ 230.14 $ 20.74 Mid C ($/MWh) $ 55.72 $ 400.10 $ 5.15 Minn hub ($/MWh) $ 39.75 $ 183.54 $ 15.23 NoIL hub ($/MWh) $ 42.22 $ 222.18 $ 14.64 PJM W hub ($/MWh) $ 48.80 $ 227.60 $ 17.78

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 and 2021, 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, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 30 $ 8 $ 30 $ 7 Derivative liabilities (30) (7) (58) (50) — 1 (28) (43) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral — 1 (28) (43) Cash collateral receivable — — 11 2 Total derivatives as presented in the balance sheet $ — $ 1 $ (17) $ (41) 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) The tables below present Renewables' derivative positions as of December 31, 2022 and 2021, 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, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 121 $ 63 $ 79 $ 4 Derivative liabilities (61) (40) (103) (7) 60 23 (24) (3) Designated as hedging instruments Derivative assets — 116 — 1 Derivative liabilities — — (168) (89) — 116 (168) (88) Total derivatives before offset of cash collateral 60 139 (192) (91) Cash collateral payable — — 105 54 Total derivatives as presented in the balance sheet $ 60 $ 139 $ (87) $ (37) 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) receivable — — 27 57 Total derivatives as presented in the balance sheet $ 18 $ 56 $ (48) $ (81)
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, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (Millions) Wholesale electricity purchase contracts (MWh) 5.7 5.7 Natural gas purchase contracts (Dth) 9.6 9.4 Fleet fuel purchase contracts (Gallons) — 2.0 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (MWh/Dth in Millions) Wholesale electricity purchase contracts 2 4 Wholesale electricity sales contracts 7 10 Natural gas and other fuel purchase contracts 15 20 Financial power contracts 6 9 Basis swaps - purchases 22 30
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, 2022 and 2021 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2022, 2021 and 2020 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2022 Electricity Natural Gas 2022 Electricity Natural Gas Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (127) $ (16) Regulatory liabilities $ — $ — December 31, 2021 2021 Regulatory assets $ — $ — Purchased power, natural gas and fuel used $ (23) $ (11) Regulatory liabilities $ (16) $ (3) 2020 Purchased power, natural gas and fuel used $ 55 $ 4 The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2022, 2021 and 2020, respectively, were as follows: Years Ended December 31, 2022 2021 2020 (Millions) Derivative Assets $ (1) $ — $ — Derivative Liabilities $ 18 $ 13 $ 6
Derivative Instruments, Gain (Loss)	The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2022, 2021 and 2020, 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) 2022 Interest rate contracts $ — Interest expense $ 4 $ 303 Commodity contracts 2 Purchased power, natural gas and fuel used (3) 2,456 Total $ 2 $ 1 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 (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, 2022, 2021 and 2020 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) 2022 Interest rate contracts $ 116 Interest Expense $ — $ 303 Commodity contracts $ (178) Operating revenues $ 59 $ 7,923 Total $ (62) $ 59 2021 Interest rate contracts $ (58) Interest Expense $ — $ 298 Commodity contracts $ (142) Operating revenues $ (3) $ 6,974 $ (200) $ (3) 2020 Commodity contracts $ 1 Operating revenues $ 6 $ 6,320 (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, 2022, 2021 and 2020 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) 2022 Interest rate contracts $ — Interest expense $ 9 $ 303 2021 Interest rate contracts $ — Interest expense $ 9 $ 298 2020 Interest rate contracts $ (27) Interest expense $ 8 $ 316 (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, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (Millions) Wholesale electricity purchase contracts $ 149 $ 36 Wholesale electricity sales contracts (200) (77) Natural gas and other fuel purchase contracts 2 6 Financial power contracts 8 35 Total $ (41) $ —
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, 2022, 2021 and 2020 consisted of: Year Ended December 31, 2022 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 9 $ 6 Wholesale electricity sales contracts 1 (63) Financial power contracts 1 (52) Financial and natural gas contracts 1 (6) Total loss included in operating revenues $ 12 $ (115) $ 7,923 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 98 Financial and natural gas contracts — 5 Total gain included in purchased power, natural gas and fuel used $ — $ 103 $ 2,456 Total Gain (Loss) $ 12 $ (12) 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) gain 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 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) Gain $ — $ (5)
Schedule of Fair Value Hedging Instruments	The effects on our consolidated financial statements as of and for the years ended December 31, 2022 and 2021 are as follows: Fair value of hedge Location of (Gain) Recognized in Income Statement Loss Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2022 Year Ended December 31, 2022 Current liabilities $ (29) Interest Expense $ 6 $ 303 Non-current liabilities $ (86) Cumulative effect on hedged debt Current debt $ 29 Non-current debt $ 86 Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement (Millions) 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, 2022
Leases [Abstract]
Lease, Cost	The components of lease cost for the years ended December 31, 2022, 2021 and 2020 were as follows: For the Year Ended December 31, 2022 2021 2020 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 12 $ 8 $ 17 Interest on lease liabilities 3 3 4 Total finance lease cost 15 11 21 Operating lease cost 20 14 16 Short-term lease cost 6 4 3 Variable lease cost 3 4 — Total lease cost $ 44 $ 33 $ 40 For the years ended December 31, 2022, 2021 and 2020 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2022 2021 2020 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 14 $ 16 $ 13 Operating cash flows from finance leases $ 1 $ 3 $ 3 Financing cash flows from finance leases $ 9 $ 6 $ 9 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ (1) $ — $ 46 Operating leases $ 25 $ 10 $ 94
Assets And Liabilities, Lessee	Balance sheet and other information as of December 31, 2022 and 2021 was as follows: As of December 31, 2022 2021 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 159 $ 148 Operating lease liabilities, current 13 12 Operating lease liabilities, long-term 161 149 Total operating lease liabilities $ 174 $ 161 Finance Leases Other assets $ 143 $ 156 Other current liabilities 7 4 Other non-current liabilities 80 91 Total finance lease liabilities $ 87 $ 95 Weighted-average Remaining Lease Term (years) Finance leases 6.4 7.3 Operating leases 16.9 20.5 Weighted-average Discount Rate Finance leases 3.46 % 3.49 % Operating leases 3.69 % 3.06 %
Finance Lease Maturity	As of December 31, 2022, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2023 $ 9 $ 16 2024 30 14 2025 8 14 2026 9 14 2027 10 16 Thereafter 33 183 Total lease payments 99 257 Less: imputed interest (12) (83) Total $ 87 174
Operating Lease Maturity	As of December 31, 2022, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2023 $ 9 $ 16 2024 30 14 2025 8 14 2026 9 14 2027 10 16 Thereafter 33 183 Total lease payments 99 257 Less: imputed interest (12) (83) Total $ 87 174

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022 consisted of: Year Purchases Sales (Millions) 2023 $ 1,066 $ 321 2024 200 137 2025 112 43 2026 86 28 2027 66 22 Thereafter 993 61 Totals $ 2,523 $ 612

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, 2021 and 2020 consisted of: Years Ended December 31, 2022 2021 2020 (Millions) Current Federal $ — $ 6 $ 3 State 2 4 9 Current taxes charged to expense 2 10 12 Deferred Federal 67 49 67 State 49 72 38 Deferred taxes charged to expense 116 121 105 Production tax credits (97) (109) (87) Investment tax credits (1) (1) (1) Total Income Tax Expense $ 20 $ 21 $ 29
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, 2022, 2021 and 2020 consisted of: Years Ended December 31, 2022 2021 2020 (Millions) Tax expense at federal statutory rate $ 176 $ 140 $ 119 Depreciation and amortization not normalized (20) (19) (13) Investment tax credit amortization (1) (1) (1) Tax return related adjustments 2 — 1 Production tax credits (97) (109) (87) Tax equity financing arrangements 13 14 1 State tax expense, net of federal benefit 40 61 37 Excess ADIT amortization (66) (65) (42) Valuation allowance (35) 21 12 Other, net 8 (21) 2 Total Income Tax Expense $ 20 $ 21 $ 29
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,504 $ 4,257 Unfunded future income taxes 129 104 Federal and state tax credits (942) (844) Federal and state NOL’s (1,086) (998) Joint ventures/partnerships 210 188 Nontaxable grant revenue (270) (292) Pension and other post-retirement benefits (11) 1 Tax Act - tax on regulatory remeasurement (328) (352) Valuation allowance 87 110 Other (80) (158) Deferred Income Tax Liabilities $ 2,213 $ 2,016 Deferred tax assets $ 2,717 $ 2,644 Deferred tax liabilities 4,930 4,660 Net Accumulated Deferred Income Tax Liabilities $ 2,213 $ 2,016
Schedule of Reconciliation of Unrecognized Income Tax Benefits	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2022, 2021 and 2020 consisted of: Years ended December 31, 2022 2021 2020 (Millions) Beginning Balance $ 127 $ 127 $ 148 Increases for tax positions related to prior years 2 3 11 Increases for tax positions related to current year 2 — — Decreases for tax positions related to prior years (4) (3) (32) Ending Balance $ 127 $ 127 $ 127

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2022
Retirement Benefits [Abstract]
Obligations and Funded Status	As of December 31, 2022 and 2021, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2022 2021 2022 2021 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 3,487 $ 3,819 $ 408 $ 452 Service cost 27 40 2 3 Interest cost 111 87 10 10 Plan amendments 1 2 — — Actuarial loss (gain) (716) (184) (103) (23) Curtailments/Settlements (274) (38) — — Benefits paid (184) (239) (33) (34) Benefit Obligation as of December 31, 2,452 3,487 284 408 Change in plan assets Fair Value of Plan Assets as of January 1, 3,079 3,092 127 167 Actual return on plan assets (584) 237 (22) 15 Employer contributions 22 27 17 12 Settlements (182) (38) — — Benefits paid (184) (239) (33) (67) Fair Value of Plan Assets as of December 31, 2,151 3,079 89 127 Funded Status as of December 31, $ (301) $ (408) $ (195) $ (281)
Schedule of Amounts Recognized in Balance Sheet	As of December 31, 2022 and 2021, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2022 2021 2022 2021 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (301) (408) (190) (276) Total $ (301) $ (408) $ (195) $ (281)
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, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2022 2021 2022 2021 (Millions) Net loss (gain) $ 181 $ 271 $ (91) $ (18) Prior service cost (credit) $ 7 $ 10 $ (1) $ (1) 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, 2022, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2022 2021 2020 2022 2021 2020 (Millions) Net Periodic Benefit Cost: Service cost $ 26 $ 39 $ 46 $ 2 $ 3 $ 3 Interest cost 109 86 106 10 10 13 Expected return on plan assets (162) (199) (198) (6) (7) (8) Amortization of prior service cost (benefit) 1 2 1 (1) (5) (9) Amortization of net loss 49 115 124 (4) 2 2 Settlement charge 17 6 — — Curtailment charge (32) — — — — — Net Periodic Benefit Cost 8 49 79 1 3 1 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments (59) — (18) — — — Settlement charge (17) (6) — — — — Net loss (gain) 33 (218) 46 (75) (31) 11 Amortization of net loss (49) (115) (124) 4 (2) (2) Current year prior service cost (credit) 1 2 7 — 1 — Amortization of prior service (cost) benefit (1) (2) (1) 1 5 9 Total Other Changes (92) (339) (90) (70) (27) 18 Total Recognized $ (84) $ (290) $ (11) $ (69) $ (24) $ 19 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, 2022, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2022 2021 2020 2022 2021 2020 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ 1 $ — $ — $ — Interest cost 2 1 1 — — — Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) 1 2 2 (1) (1) (1) Settlement/Curtailment charge 1 1 1 — — — Net Periodic Benefit Cost 3 3 3 (1) (1) (1) Other Changes in plan assets and benefit obligations recognized in OCI: Settlement charge (1) (1) — (1) (1) — Net loss (gain) (1) (3) 1 (1) 1 — Amortization of net (loss) gain (1) (2) (2) 1 1 1 Amortization of prior service cost — — — — — — Total Other Changes (3) (6) (1) (1) 1 1 Total Recognized $ — $ (3) $ 2 $ (2) $ — $ —
Summary of Amounts Recognized in OCI	Amounts recognized in OCI for ARHI for the years ended December 31, 2022 and 2021, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2022 2021 2022 2021 (Millions) Net loss (gain) $ 12 $ 16 $ (6) $ (5)
Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans	PBO in excess of plan assets As of December 31, 2022 2021 (Millions) Projected benefit obligation $ 2,452 $ 3,487 Fair value of plan assets $ 2,151 $ 3,079 ABO in excess of plan assets As of December 31, 2022 2021 (Millions) Accumulated benefit obligation $ 2,429 $ 1,790 Fair value of plan assets $ 2,151 $ 1,536
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, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2022 2021 2022 2021 Discount rate 5.18 % 2.85 % 5.12 % 2.66 % Rate of compensation increase 2.99 % 3.53 % 3.00 % 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, 2022, 2021 and 2020 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2022 2021 2020 2022 2021 2020 Discount rate 2.85 % 2.34 % 3.01 % 2.66 % 2.19 % 2.99 % Expected long-term return on plan assets 6.33 % 7.30 % 7.30 % 4.66 % 4.05 % 5.09 % Rate of compensation increase 3.53 % 3.52 % 3.66 % 3.50 % 3.50 % 3.48 %
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, 2022 and 2021 consisted of: As of December 31, 2022 2021 Health care cost trend rate assumed for next year 5.00%/6.50% 5.00%/7.00% 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, 2022 consisted of: (Millions) Pension Benefits Postretirement Benefits 2023 $ 233 $ 28 2024 $ 218 $ 27 2025 $ 215 $ 26 2026 $ 211 $ 25 2027 $ 206 $ 24 2028 - 2032 $ 938 $ 108
Fair Values of Pension Plan Assets, by Asset Category	The fair values of pension plan assets, by asset category, as of December 31, 2022, consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 51 $ — $ 51 $ — U.S. government securities 252 252 — — Common stocks 57 57 — — Registered investment companies 104 104 — — Corporate bonds 708 — 708 — Preferred stocks 1 1 — — Common collective trusts 472 — 472 — Other, principally annuity, fixed income 33 — 33 — $ 1,678 $ 414 $ 1,264 $ — Other investments measured at net asset value 473 Total $ 2,151 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
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, 2022 consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 2 $ — $ 2 $ — U.S. government securities 1 1 — — Registered investment companies 69 69 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 8 — 8 — $ 87 $ 70 $ 17 $ — Other investments measured at net asset value 2 Total $ 89 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 — — Registered investment companies 101 101 — — Corporate bonds 3 — 3 — 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

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2022
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) for the years ended December 31, 2022, 2021 and 2020 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2019 2020 Change As of December 31, 2020 2021 Change As of December 31, 2021 2022 Change As of December 31, 2022 (Millions) Loss (gain) for defined benefit plans, net of income tax expense of $0 for 2020, $0 for 2021 and $3 for 2022 $ (12) $ — $ (12) $ 2 $ (10) $ 14 $ 4 Amortization of pension cost, net of income tax expense (benefit) of $3 for 2020, $(1) for 2021 and $1 for 2022 (7) (13) (20) (8) (28) 4 (24) Unrealized (loss) gain from equity method investment, net of income tax (benefit) expense of $0 for 2020, $(3) for 2021 and $6 for 2022 (a) $ — $ — $ — $ (9) $ (9) $ 22 $ 13 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 benefit of $(7) for 2020, $(44) for 2021 and $0 for 2022 (13) (22) (35) (159) (194) (1) (195) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $2 for 2020, $(3) for 2021 and $19 for 2022 (b) (63) 19 (44) 12 (32) 54 22 Loss on derivatives qualifying as cash flow hedges (76) (3) (79) (147) (226) 53 (173) Accumulated Other Comprehensive Loss $ (95) $ (16) $ (111) $ (162) $ (273) $ 93 $ (180) (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, 2022
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, 2022, 2021 and 2020, respectively, consisted of: Years Ended December 31, 2022 2021 2020 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 881 $ 707 $ 581 Denominator: Weighted average number of shares outstanding - basic 386,727,246 358,086,621 309,494,939 Weighted average number of shares outstanding - diluted 387,215,785 358,578,608 309,559,387 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 2.28 $ 1.97 $ 1.88 Earnings Per Common Share, Diluted $ 2.27 $ 1.97 $ 1.88

Grants, Government Incentives_2

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2022
Other Liabilities Disclosure [Abstract]
Schedule of Government Grants Activities	The changes in government grants recorded in deferred income as of December 31, 2022 and 2021 consisted of: (Millions) Government grants - Renewables Other deferred income Total 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 Disposals — — — Recognized in income (65) (3) (68) As of December 31, 2022 $ 1,060 $ 2 $ 1,062 The changes in government grants recorded as a reduction to the related utility plant as of December 31, 2022 and 2021 consisted of: (Millions) Government grants - Networks Total As of December 31, 2020 $ 67 $ 67 Disposals — — Recognized in income (4) (4) As of December 31, 2021 63 63 Disposals — — Recognized in income (4) (4) As of December 31, 2022 $ 59 $ 59

Other Financial Statement Items

Other Financial Statement Items (Tables)	12 Months Ended
	Dec. 31, 2022
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Schedule of Other Income and (Expense)	Other income (expense) for the years ended December 31, 2022, 2021 and 2020 consisted of: Years ended December 31, 2022 2021 2020 (Millions) Gain on sale of assets (a) $ — $ — $ 20 Allowance for funds used during construction 63 88 56 Carrying costs on regulatory assets 16 17 28 Non-service component of net periodic benefit cost (58) (37) (62) Other 9 (8) (24) Total Other Income (Expense) $ 30 $ 60 $ 18 (a) 2020 includes a $16 million gain from the Tatanka 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, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Trade receivables and unbilled revenues $ 1,892 $ 1,420 Allowance for credit losses (155) (151) Total Accounts receivable and unbilled revenues, net $ 1,737 $ 1,269 The change in the allowance for credit losses as of December 31, 2022 and 2021 consisted of: (Millions) 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 Current period provision 110 Write-off as uncollectible (106) As of December 31, 2022 $ 155
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Prepaid other taxes $ 136 $ 95 Broker margin and collateral accounts 164 87 Other pledged deposits 12 4 Prepaid expenses 68 58 Other 6 1 Total $ 386 $ 245
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2022 and 2021 consisted of: As of December 31, 2022 2021 (Millions) Advances received $ 271 $ 204 Accrued salaries 153 127 Short-term environmental provisions 54 52 Collateral deposits received 68 58 Pension and other postretirement 5 5 Finance leases 7 4 Other 35 34 Total $ 593 $ 484

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2022
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the year ended December 31, 2022 consisted of: For the Year Ended December 31, 2022 Networks Renewables Other(a) AVANGRID Consolidated (Millions) Revenue - external $ 6,781 $ 1,141 $ 1 $ 7,923 Revenue - intersegment 1 — (1) — Depreciation and amortization 660 424 1 1,085 Operating income 901 (36) (13) 852 Earnings (losses) from equity method investments 11 251 — 262 Interest expense, net of capitalization 220 16 67 303 Income tax expense (benefit) 94 (114) 40 20 Capital expenditures 1,803 708 8 2,519 Adjusted net income 628 403 (130) 901 As of December 31, 2022 Property, plant and equipment 20,027 10,950 17 30,994 Equity method investments 171 266 — 437 Total assets $ 28,069 $ 13,553 $ (499) $ 41,123 (a) Includes Corporate and intersegment eliminations. 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 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 (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, 2022, 2021 and 2020 is as follows: Years Ended December 31, 2022 2021 2020 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 901 $ 780 $ 625 Adjustments: Mark-to-market adjustments - Renewables (1) — (53) (5) Offshore contract provision (2) (24) — — Restructuring charges (3) — — (6) Accelerated depreciation from repowering (4) — — (9) Impact of COVID-19 (5) — (34) (29) Merger costs (6) (4) (12) (6) Legal settlement - Gas storage (7) — — (5) Income tax impact of adjustments 7 26 16 Net Income Attributable to Avangrid, Inc. $ 881 $ 707 $ 581 (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) Costs incurred in connection with an offshore contract provision. (3) Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth. (4) Represents the amount of accelerated depreciation derived from repowering wind farms in Renewables. (5) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (6) Pre-merger costs incurred. (7) 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, 2022
Related Party Transactions [Abstract]
Schedule of Related Party Transactions and Balances	Related party transactions for the years ended December 31, 2022, 2021 and 2020, respectively, consisted of: Years Ended December 31, 2022 2021 2020 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ 1 $ (46) $ — $ (52) $ 1 $ (43) Iberdrola Renovables Energia, S.L. $ 1 $ (5) $ — $ (10) $ — $ (9) Iberdrola Financiación, S.A. $ — $ (12) $ — $ (9) $ — $ (7) Vineyard Wind $ 7 $ — $ 14 $ — $ 9 $ — Iberdrola Solutions $ — $ — $ 7 $ (39) $ 2 $ — Other $ 1 $ (3) $ 2 $ (3) $ — $ — Related party balances as of December 31, 2022 and 2021, respectively, consisted of: As of December 31, 2022 2021 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 1 $ (29) $ 3 $ (43) Iberdrola Financiacion $ — $ (9) $ — $ (9) Vineyard Wind $ 3 $ (8) $ 8 $ (8) Iberdrola Solutions $ — $ (2) $ — $ (2) Other $ 4 $ (1) $ — $ (1)

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2022
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, 2022, and changes during the fiscal year ended December 31, 2022, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2021 1,323,328 $ 36.05 Granted 258,168 $ 38.16 Forfeited (412,776) $ 36.21 Vested (83,770) $ 45.91 Nonvested Balance – December 31, 2022 1,084,951 $ 36.55

Background and Nature of Oper_2

Background and Nature of Operations (Details) $ / shares in Units, $ in Millions	May 18, 2021 USD ($) placement $ / shares shares	Apr. 15, 2021	Oct. 20, 2020 USD ($) $ / shares	Dec. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares	Dec. 31, 2020 $ / 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%
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%
Merger With PNMR
Noncontrolling Interest [Line Items]
Acquisition, commitment letter amount	$ 4,300
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				18.40%

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, 2022	Dec. 31, 2021
Finite-Lived Intangible Assets [Line Items]
Composite rate	2.80%	2.80%
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	46%
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	0%
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, 2022
Solar power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years
Min. | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	35 years
Min. | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	45 years
Min. | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	41 years
Min. | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	4 years
Min. | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	7 years
Min. | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	3 years
Min. | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years
Min. | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	3 years
Max. | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	90 years
Max. | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Max. | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	85 years
Max. | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	37 years
Max. | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	82 years
Max. | 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, 2022	Dec. 31, 2021	Dec. 31, 2020
Disaggregation of Revenue [Line Items]
Contract assets	$ 9	$ 9
Contract liabilities	33	16
Contract liabilities, revenue recognized	33	22	$ 21
Accounts receivable related to contracts with customers	1,622	1,220
Unbilled contracts receivable	$ 541	$ 405
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 7,785	$ 6,793	$ 5,992
Leasing revenue	8	7	6
Derivative revenue	4	3	136
Alternative revenue programs	68	115	157
Other revenue	58	56	29
Total operating revenues	7,923	6,974	6,320
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
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	0
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,610	4,015	3,642
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	1,931	1,516	1,311
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	947	1,028	822
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	36	20	19
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	96	63	39
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	165	151	159
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers	6,658	5,598	5,011
Leasing revenue	8	7	6
Derivative revenue	0	0	0
Alternative revenue programs	68	115	157
Other revenue	48	34	14
Total operating revenues	6,782	5,754	5,188
Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,610	4,015	3,642
Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,931	1,516	1,311
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	117	67	58
Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,127	1,195	981
Leasing revenue	0	0	0
Derivative revenue	4	3	136
Alternative revenue programs	0	0	0
Other revenue	10	22	15
Total operating revenues	1,141	1,220	1,132
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	947	1,028	822
Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	36	20	19
Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	96	63	39
Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 48	$ 84	$ 101

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, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 322
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	2
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	116
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	204
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	128
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 renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 46
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	$ 81
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	$ 80
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 renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 45
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	$ 34
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	$ 29
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 renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 17
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 15
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 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 renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 5
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 10
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 8
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	1 year
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	$ 1
Remaining performance obligation, period	1 year
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	$ 7
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 62
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | 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]: 2028-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 2
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | 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	$ 60
Remaining performance obligation, period

Industry Regulation - Additiona

Industry Regulation - Additional Information (Details) MWh in Millions

1 Months Ended

12 Months Ended

Dec. 21, 2022

Oct. 19, 2022

Sep. 09, 2022 USD ($)

Jun. 24, 2022 USD ($)

May 26, 2022 USD ($)

Jul. 14, 2021 USD ($)

Jun. 23, 2021 USD ($)

May 06, 2021 USD ($)

Apr. 15, 2021

Dec. 31, 2020 MW

Nov. 19, 2020

May 21, 2020

Mar. 01, 2020

Feb. 19, 2020 USD ($)

Jan. 21, 2020

Dec. 09, 2019 USD ($)

Nov. 21, 2019

Jan. 01, 2019

Sep. 10, 2018 USD ($)

Jan. 01, 2018

Jan. 01, 2017

Mar. 31, 2010 USD ($) MW

Sep. 30, 2021

Dec. 31, 2019 MWh project

Oct. 31, 2018 agreement MW

Mar. 31, 2017 order project

Dec. 31, 2022 USD ($) company

Apr. 30, 2019

Aug. 11, 2022 USD ($)

Dec. 31, 2021 USD ($)

Jun. 30, 2021 USD ($) hour

Jul. 16, 2020 USD ($)

Jan. 31, 2018 USD ($)

Public Utilities, General Disclosures [Line Items]

Number of networks supply companies | company

8

Period from letter issuance to file distribution rate case

60 days

Approved return on equity

10.02%

9.88%

Equity ratio

50%

3%

Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2023

70%

Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2024

20%

Number of REV related orders issued | order

3

Number of energy storage projects | project

2

Direct Current Fast Charger incentive program, approved amount

$ 700,000,000

Regulatory assets

$ 2,768,000,000

$ 2,647,000,000

$ 11,000,000

Number of average months used to set rate

13 months

Restricted net assets

$ 6,241,000,000

Purchase obligation per year

2,523,000,000

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

PURA

Public Utilities, General Disclosures [Line Items]

Equity ratio

50%

Percentage of return on equity (ROE)

9.10%

New distribution rate schedule, period

3 years

Public utilities regulatory authority distribution rate

50%

PURA | Electric And Gas Service Rate Plan Year One

Public Utilities, General Disclosures [Line Items]

Distribution revenue requirement

$ 102,000,000

PURA | Electric And Gas Service Rate Plan Year Two

Public Utilities, General Disclosures [Line Items]

Distribution revenue requirement

17,000,000

PURA | Electric And Gas Service Rate Plan Year Three

Public Utilities, General Disclosures [Line Items]

Distribution revenue requirement

17,000,000

DEEP

Public Utilities, General Disclosures [Line Items]

PPA capacity (in MWH) | MWh

12

Storm costs

Public Utilities, General Disclosures [Line Items]

Regulatory assets

671,000,000

448,000,000

Power Tax

Public Utilities, General Disclosures [Line Items]

Depreciation amortization period

32 years 6 months

Depreciation amortization period

32 years 6 months

Federal tax depreciation normalization adjustment

Public Utilities, General Disclosures [Line Items]

Regulatory assets

$ 137,000,000

$ 142,000,000

Central Maine Power

Public Utilities, General Disclosures [Line Items]

Distribution revenue requirement

$ 17,000,000

Annual distribution tariff increase percentage

7%

Distribution tariff rate increased based on ROE

9.25%

Distribution tariff rate increased based on equity capital

50%

ROE reduction

1%

Proposed distribution tariff rate decrease based on return on equity

8.25%

Customer service performance period

18 months

Central Maine Power | Electric And Gas Service Rate Plan Year One

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

$ 48,000,000

Central Maine Power | Electric And Gas Service Rate Plan Year Two

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

28,000,000

Central Maine Power | Electric And Gas Service Rate Plan Year Three

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

$ 23,000,000

Central Maine Power | Min. | Electric And Gas Service Rate Plan Year One

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

$ 45,000,000

Central Maine Power | Min. | Electric And Gas Service Rate Plan Year Two

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

25,000,000

Central Maine Power | Min. | Electric And Gas Service Rate Plan Year Three

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

20,000,000

Central Maine Power | Max. | Electric And Gas Service Rate Plan Year One

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

50,000,000

Central Maine Power | Max. | Electric And Gas Service Rate Plan Year Two

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

30,000,000

Central Maine Power | Max. | Electric And Gas Service Rate Plan Year Three

Public Utilities, General Disclosures [Line Items]

Estimated revenue change amount

$ 25,000,000

NYSEG Gas

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

50%

Percentage of return on equity (ROE)

9.75%

RG&E Electric

Public Utilities, General Disclosures [Line Items]

Percentage of earnings customers received

75%

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%

Percentage of return on equity (ROE)

10.75%

NYSEG Electric

Public Utilities, General Disclosures [Line Items]

Approved return on equity

9%

Equity ratio

48%

Equity ratio for earnings sharing

50%

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

BGC

Public Utilities, General Disclosures [Line Items]

Equity ratio for earnings sharing

54%

Percentage of return on equity (ROE)

9.70%

Requested revenue increase amount

$ 5,600,000

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

NYDPS

Public Utilities, General Disclosures [Line Items]

Equity ratio for earnings sharing

48%

Percentage of return on equity (ROE)

8.80%

SCG | PURA

Public Utilities, General Disclosures [Line Items]

Equity ratio

52%

Percentage of return on equity (ROE)

9.25%

Connecticut Natural Gas Corporation (CNG) | PURA

Public Utilities, General Disclosures [Line Items]

Percentage of return on equity (ROE)

9.30%

Equity ratio, year one

54%

Equity ratio, year two

54.50%

Equity ratio, year three

55%

NYSEG and RG&E

Public Utilities, General Disclosures [Line Items]

Suspension period

11 months

Direct Current Fast Charger incentive program, approved amount

$ 118,000,000

Public Utilities, Extension Of Suspension Period

60 days

60 days

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

UI | Electric And Gas Service Rate Plan Year One | Rate change levelization

Public Utilities, General Disclosures [Line Items]

Distribution revenue requirement

$ 54,000,000

Vineyard Wind

Public Utilities, General Disclosures [Line Items]

Proposed off shore wind capacity (in MW) | MW

804

Industry Regulation - Rate Incr

Industry Regulation - Rate Increases and Delivery Rate Percentages (Details) - Year 3 - USD ($) $ in Millions	Nov. 19, 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	Nov. 19, 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%
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%
RG&E Gas | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0%
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 - Requested Revenue Change (Details) - USD ($) $ in Millions	3 Months Ended
	Aug. 12, 2022	May 26, 2022
NYSEG Electric
Regulatory Liabilities [Line Items]
Requested Revenue Change	$ 274	$ 274
Requested Revenue Change, Difference	0
NYSEG Gas
Regulatory Liabilities [Line Items]
Requested Revenue Change	30	43
Requested Revenue Change, Difference	(13)
RG&E Electric
Regulatory Liabilities [Line Items]
Requested Revenue Change	93	94
Requested Revenue Change, Difference	(1)
RG&E Gas
Regulatory Liabilities [Line Items]
Requested Revenue Change	32	$ 38
Requested Revenue Change, Difference	$ (6)

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Regulatory Assets Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($)
Regulated Operations [Abstract]
Unrecorded regulatory assets	$ 977
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_5

Regulatory Assets and Liabilities - Schedule of Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Jan. 31, 2018
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,768	$ 2,647	$ 11
Less: current portion	447	400
Total non-current regulatory assets	2,321	2,247
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	365	545
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	93	95
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	671	448
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	41	68
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	52	68
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	11	15
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	56	73
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	33	24
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	1	2
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	56	52
Deferred transmission expense
Regulatory Assets [Line Items]
Total regulatory assets	0	13
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	248	256
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	64	71
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	19	23
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	492	424
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	137	142
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	20
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	55	46
COVID-19 cost recovery and late payment surcharge
Regulatory Assets [Line Items]
Total regulatory assets	17	21
Low income arrears forgiveness
Regulatory Assets [Line Items]
Total regulatory assets	31	0
Excess generation service charge
Regulatory Assets [Line Items]
Total regulatory assets	24	6
System Expansion
Regulatory Assets [Line Items]
Total regulatory assets	21	12
Non-bypassable charge
Regulatory Assets [Line Items]
Total regulatory assets	14	10
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 247	$ 213

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,269	$ 3,329
Less: current portion	354	307
Regulatory liabilities	2,915	3,022
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	30	45
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	7
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	117	73
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	23
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3	7
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,232	1,327
Rate change levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	25	99
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	13
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,178	1,192
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	0	2
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20	26
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	22
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3	6
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	22
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	16
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	49
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	36	35
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	31	23
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	10	12
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	24
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	18
Earning sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	13
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	17
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	25
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	27	15
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1	5
Hedges gains
Regulatory Liabilities [Line Items]
Total regulatory liabilities	0	19
Non by-passable charges
Regulatory Liabilities [Line Items]
Total regulatory liabilities	76	11
Transmission revenue reconciliation mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	75	9
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 204	$ 174

Regulatory Assets and Liabili_7

Regulatory Assets and Liabilities - Regulatory Liabilities Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
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 | 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
NYSEG and RG&E | Economic development
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years

Goodwill and Intangible asset_2

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
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)		12 Months Ended
	Dec. 16, 2015 USD ($)	Dec. 31, 2022 USD ($) reportingUnit	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2002 USD ($)	Dec. 31, 2000 USD ($)
Goodwill [Line Items]
Impairment of goodwill		$ 0	$ 0
Amortization expense		$ 14,000,000	$ 13,000,000	$ 14,000,000
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, 2022	Dec. 31, 2021
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 612	$ 610
Accumulated Amortization	(331)	(317)
Net Carrying Amount	281	293
Wind development
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	590	592
Accumulated Amortization	(313)	(301)
Net Carrying Amount	277	291
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	22	18
Accumulated Amortization	(18)	(16)
Net Carrying Amount	$ 4	$ 2

Goodwill and Intangible asset_5

Goodwill and Intangible assets - Schedule of Amortization Expense (Details) $ in Millions	Dec. 31, 2022 USD ($)
Year ending December 31,
2023	$ 14
2024	14
2025	14
2026	13
2027	$ 13

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 38,453	$ 36,169
Total accumulated depreciation	(11,542)	(10,589)
Total Net Property, Plant and Equipment in Service	26,911	25,580
Construction work in progress	4,083	3,286
Total Property, Plant and Equipment	30,994	28,866
Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	32,730	30,838
Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,406	5,045
Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	317	286
Regulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	24,026	22,424
Total accumulated depreciation	(6,277)	(5,806)
Total Net Property, Plant and Equipment in Service	17,749	16,618
Construction work in progress	2,225	2,064
Total Property, Plant and Equipment	19,974	18,682
Regulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	18,634	17,392
Regulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,392	5,032
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	14,427	13,745
Total accumulated depreciation	(5,265)	(4,783)
Total Net Property, Plant and Equipment in Service	9,162	8,962
Construction work in progress	1,858	1,222
Total Property, Plant and Equipment	11,020	10,184
Nonregulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	14,096	13,446
Nonregulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	14	13
Nonregulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 317	$ 286

Property, Plant and Equipment_2

Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Abstract]
Interest costs capitalized	$ 53	$ 33	$ 51
Accrued liabilities for property, plant and equipment additions	481	297	285
Tangible asset impairment charges	11	20	7
Depreciation	1,071	1,001	$ 973
New England Clean Energy Connect (NECEC) project, capitalized amount	$ 585	$ 546

Asset retirement obligations -

Asset retirement obligations - Reconciliation of ARO (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 253	$ 210
Liabilities settled during the year	(1)	(2)
Liabilities incurred during the year	13	7
Accretion expense	14	12
Revisions in estimated cash flows	(6)	26
Ending Balance	$ 273	$ 253

Asset retirement obligations _2

Asset retirement obligations - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
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, 2022	Dec. 31, 2021
Debt Instrument [Line Items]
Unamortized debt issuance costs and discount	$ (76)	$ (53)
Total Debt	8,627	8,294
Less: debt due within one year, included in current liabilities	412	372
Total Non-current Debt	8,215	7,922
First mortgage bonds - fixed
Debt Instrument [Line Items]
Long-term debt	2,882	$ 2,759
Bond pledged as collateral	$ 8,331
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%	8%
Unsecured pollution control notes - fixed
Debt Instrument [Line Items]
Long-term debt	$ 545	$ 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	4%	4%
Other various non-current debt - fixed
Debt Instrument [Line Items]
Long-term debt	$ 5,276	$ 5,110
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%	6.66%

Debt - 2022 Long-Term Debt Issu

Debt - 2022 Long-Term Debt Issuance (Details) - USD ($) $ in Millions	Dec. 15, 2022	Apr. 06, 2022	Jan. 31, 2022
Unsecured Notes | UI | 2.25% Unsecured Notes Due 3032
Debt Instrument [Line Items]
Debt instrument principal amount			$ 150
Debt instrument, interest rate			2.25%
Unsecured Notes | UI | 4.62% Unsecured Notes Due 2032
Debt Instrument [Line Items]
Debt instrument principal amount	$ 50
Debt instrument, interest rate	4.62%
Unsecured Notes | NYSEG | 4.62% Unsecured Notes Due 2032
Debt Instrument [Line Items]
Debt instrument principal amount	$ 150
Debt instrument, interest rate	4.62%
Unsecured Notes | NYSEG | 4.96% Unsecured Notes Due 2052
Debt Instrument [Line Items]
Debt instrument principal amount	$ 125
Debt instrument, interest rate	4.96%
Tax Exempt Bond | NYSEG | 4.00% Tax exempt Bond Due 2028
Debt Instrument [Line Items]
Debt instrument principal amount		$ 67
Debt instrument, interest rate		4%
First Mortgage Bonds | RG&E | 4.86% First Mortgage Bonds Due 2052
Debt Instrument [Line Items]
Debt instrument principal amount	$ 125
Debt instrument, interest rate	4.86%
Green First Mortgage Bonds | CMP | 4.37% Green First Mortgage Bonds 2032
Debt Instrument [Line Items]
Debt instrument principal amount	$ 75
Debt instrument, interest rate	4.37%
Green First Mortgage Bonds | CMP | 4.76% Green First Mortgage Bonds 2052
Debt Instrument [Line Items]
Debt instrument principal amount	$ 50
Debt instrument, interest rate	4.76%

Debt - Additional Information (

Debt - Additional Information (Details)		12 Months Ended
	Nov. 23, 2021 USD ($)	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Nov. 22, 2021 USD ($)	Dec. 14, 2020 USD ($)
Debt Instrument [Line Items]
Estimated fair value of debt		$ 7,991,000,000	$ 9,155,000,000
Notes payable		566,000,000	159,000,000
Commercial paper		$ 397,000,000	$ 0
Supplier Financing Arrangements
Debt Instrument [Line Items]
Weighted-average interest rate		5.48%	0.82%
Notes payable, including to affiliates		$ 171,000,000	$ 161,000,000
Commercial Paper
Debt Instrument [Line Items]
Weighted-average interest rate		4.66%
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	3,178,000,000
Debt covenant, ratio of consolidated debt to consolidated total capitalization	0.65
Line of credit borrowing outstanding		0	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
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 - Schedule of Long-term _2

Debt - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2022 USD ($)
Debt Disclosure [Abstract]
2023	$ 412
2024	612
2025	1,107
2026	660
2027	484
Total	$ 3,275

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, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Restricted cash	$ 3	$ 3
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%
NYSEG and RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of natural gas load obligations hedged	55%

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, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	$ 48	$ 60
Netting adjustment	(222)	(110)
Derivative assets	200	94
Netting adjustment	394	194
Derivative liabilities	(297)	(224)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(177)	(78)
Derivative assets	80	77
Netting adjustment	364	176
Derivative liabilities	(125)	(67)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(45)	(32)
Derivative assets	3	15
Netting adjustment	30	18
Derivative liabilities	0	(5)
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	1	2
Netting adjustment	0	0
Derivative liabilities	(57)	(75)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0
Derivative assets	116
Netting adjustment	0	0
Derivative liabilities	(115)	(77)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	35	45
Derivative assets, before netting	38	35
Derivative liabilities, before netting	(50)	(17)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	37	31
Derivative liabilities, before netting	(46)	(16)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	1	4
Derivative liabilities, before netting	(4)	(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	13	15
Derivative assets, before netting	218	73
Derivative liabilities, before netting	(491)	(236)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	55	39
Derivative liabilities, before netting	(350)	(137)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	47	34
Derivative liabilities, before netting	(26)	(22)
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	116
Derivative liabilities, before netting	(115)	(77)
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	166	96
Derivative liabilities, before netting	(150)	(165)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	165	85
Derivative liabilities, before netting	(93)	(90)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	9
Derivative liabilities, before netting	0	0
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	1	2
Derivative liabilities, before netting	(57)	(75)
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value as of January 1,	$ (69)	$ 13	$ 25
Gains for the year recognized in operating revenues	108	21	8
Losses for the year recognized in operating revenues	$ (30)	$ (34)	$ (2)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating Revenues	Operating Revenues	Operating Revenues
Total gains or losses for the period recognized in operating revenues	$ 78	$ (13)	$ 6
Gains recognized in OCI	2	2	1
Losses recognized in OCI	$ (57)	(52)	(3)
Fair Value, Recurring Basis Unobservable Input Reconciliation, Net Derivative Asset (Liability), Gain (Loss), Statement Of Other Comprehensive Income, Extensible List Not Disclosed Flag	Total gains or losses recognized in OCI
Total gains or losses recognized in OCI	$ (55)	(50)	(2)
Net change recognized in regulatory assets and liabilities	17	13	6
Purchases	10	(17)	(2)
Settlements	8	(13)	(15)
Transfers out of Level 3 (a)	27	(2)	(5)
Fair value as of December 31,	16	(69)	13
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	$ 78	$ (13)	$ 6
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating Revenues	Operating Revenues	Operating Revenues

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, 2022 $ / MWh
NYMEX | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	4.18
NYMEX | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	9.86
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	3.05
AECO | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	10.80
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	46.29
Ameren | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	225.62
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	58.96
COB | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	400.10
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	42.57
ComEd | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	222.49
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	46.94
ERCOT N hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	324.49
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	45.44
ERCOT S hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	320.63
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	49.02
Indiana hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	230.14
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	55.72
Mid C | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	400.10
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	39.75
Minn hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	183.54
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	42.22
Noil hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	222.18
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	48.80
PJM W hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	227.60
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) - Contracts for differences - Level 3	Dec. 31, 2022 $ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0084
Min. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0399
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	0.0089
Max. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0422
Max. | Measurement Input, Commodity Forward Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	3.80

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, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 200	$ 94
Derivative Liability	(297)	(224)
Cash collateral (payable) receivable, asset	(97)	(67)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	0	17
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	0	17
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	30	29
Derivative liabilities	(30)	(12)
Derivative Asset	0	17
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	1	3
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	1	3
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	8	7
Derivative liabilities	(7)	(4)
Derivative Asset	1	3
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(28)	(16)
Cash collateral (payable) receivable, liability	11	0
Total derivatives as presented in the balance sheet	(17)	(16)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	30	12
Derivative liabilities	(58)	(27)
Derivative Liability	(28)	(15)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	(1)
Derivative Liability	0	(1)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(43)	(60)
Cash collateral (payable) receivable, liability	2	0
Total derivatives as presented in the balance sheet	(41)	(60)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	7	4
Derivative liabilities	(50)	(64)
Derivative Liability	(43)	(60)
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	60	18
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	60	18
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	121	29
Derivative liabilities	(61)	(11)
Derivative Asset	60	18
Renewables | 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
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	139	56
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	139	56
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	63	70
Derivative liabilities	(40)	(14)
Derivative Asset	23	56
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	116	0
Derivative liabilities	0	0
Derivative Asset	116	0
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(192)	(75)
Cash collateral (payable) receivable, liability	105	27
Total derivatives as presented in the balance sheet	(87)	(48)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	79	52
Derivative liabilities	(103)	(65)
Derivative Liability	(24)	(13)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	5
Derivative liabilities	(168)	(67)
Derivative Liability	(168)	(62)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(91)	(138)
Cash collateral (payable) receivable, liability	54	57
Total derivatives as presented in the balance sheet	(37)	(81)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	9
Derivative liabilities	(7)	(11)
Derivative Liability	(3)	(2)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	6
Derivative liabilities	(89)	(142)
Derivative Liability	$ (88)	$ (136)

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, 2022 USD ($) MMBTU MWh gal	Dec. 31, 2021 USD ($) MMBTU MWh gal
Networks | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	5.7	5.7
Networks | Natural gas purchase contracts (Dth) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	9.6	9.4
Networks | Fleet fuel purchase contracts (Gallons) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount | gal	0	2
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (41)	$ 0
Renewables | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	2	4
Derivative assets (liabilities), fair value	$ 149	$ 36
Renewables | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	7	10
Derivative assets (liabilities), fair value	$ (200)	$ (77)
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	15	20
Derivative assets (liabilities), fair value	$ 2	$ 6
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	6	9
Derivative assets (liabilities), fair value	$ 8	$ 35
Renewables | Basis Swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	22	30

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ (1)	$ 0	$ 0
Derivative Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	18	13	6
Electricity
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			55
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	9	0
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(127)	(23)
Electricity | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	(16)
Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			$ 4
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	4	0
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(16)	(11)
Natural Gas | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ 0	$ (3)

Derivative Instruments and He_6

Derivative Instruments and Hedging - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 USD ($) instrument	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Sep. 15, 2021 USD ($)	Jul. 15, 2021 USD ($)	May 27, 2021 USD ($)	Jun. 20, 2019 USD ($)	Jan. 31, 2018 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 2,768,000,000	$ 2,647,000,000						$ 11,000,000
Regulatory liabilities	3,269,000,000	3,329,000,000
(Loss) gain recognized in OCI on derivatives	(62,000,000)	(200,000,000)
Derivative assets	140,000,000	59,000,000
Derivative liabilities	164,000,000	160,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months	(9,000,000)
Derivative liability	297,000,000	224,000,000
Derivative collateral obligation to be paid in decrease in credit rating below investment grade	37,000,000
Cash collateral pledged	97,000,000	67,000,000
Derivative with credit risk contingent features, liability, fair value	$ 13,000,000
Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain on foreign currency contracts not designated as hedging instruments			$ 4,000,000
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of instruments held | instrument	2
Derivative liability	$ 57,000,000	75,000,000
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	(9,000,000)	(9,000,000)	(8,000,000)
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	38,000,000	48,000,000
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]
(Loss) gain recognized in OCI on derivatives	2,000,000	(3,000,000)	0
Loss (Gain) Reclassified from Accumulated OCI into Income	1,000,000	3,000,000	5,000,000
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Forward contract to hedge foreign currency exchange risk							$ 100,000,000
(Loss) gain recognized in OCI on derivatives	(4,000,000)	(4,000,000)	$ (4,000,000)
Expected amortization of discontinued cash flow hedges, next fiscal year	(4,000,000)
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	43,000,000	47,000,000
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	59,000,000	(3,000,000)
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	169,000,000
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount				$ 956,000,000		$ 935,000,000
Derivative assets	$ 116,000,000
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%
Derivative assets	$ 1,000,000	2,000,000
Regulatory assets	56,000,000	73,000,000
Derivative liabilities	57,000,000	75,000,000
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%
Derivative assets	$ 0	0
Derivative liabilities	$ 55,000,000	$ 72,000,000

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	$ (62)	$ (200)
Interest expense	303	298	$ 316
Purchased power, natural gas and fuel used	2,456	1,719	1,379
Operating revenues	7,923	6,974	6,320
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	2	(3)	0
Loss (Gain) Reclassified from Accumulated OCI into Income	1	3	5
Operating revenues	6,782	5,754	5,188
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	59	(3)
Operating revenues	1,141	1,220	1,132
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	0	(27)
Loss (Gain) Reclassified from Accumulated OCI into Income	9	9	8
Interest rate contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	4	4	4
Interest rate contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	116	(58)
Loss (Gain) Reclassified from Accumulated OCI into Income	0	0
Interest expense	303	298
Commodity contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	2	2	(1)
Loss (Gain) Reclassified from Accumulated OCI into Income	(3)	(1)	1
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	(178)	(142)	1
Loss (Gain) Reclassified from Accumulated OCI into Income	59	(3)	6
Operating revenues	$ 7,923	6,974	6,320
Foreign currency exchange contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives		$ (5)	$ 1

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (41)	$ 0
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	8	35
Long | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	149	36
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	2	6
Short | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (200)	$ (77)

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Operating revenues	$ 7,923	$ 6,974	$ 6,320
Purchased power, natural gas and fuel used	2,456	1,719	1,379
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,141	1,220	1,132
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	12	2	0
Renewables | Trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 12	$ 2	$ 0
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Trading | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 0	$ 0	$ 0
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Trading | Wholesale electricity contracts | Long | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 9	$ 1	$ (1)
Renewables | Trading | Wholesale electricity contracts | Long | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	1	(2)	(1)
Renewables | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	1	4	2
Renewables | Trading | Financial and natural gas contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	1	(1)	0
Renewables | Trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(12)	(57)	(5)
Operating revenues	7,923	6,974	6,320
Purchased power, natural gas and fuel used	2,456	1,719	1,379
Renewables | Non-trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ (115)	$ (101)	$ (7)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Non-trading | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 103	$ 44	$ 2
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Non-trading | Wholesale electricity contracts | Long | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 6	$ (1)	$ 0
Renewables | Non-trading | Wholesale electricity contracts | Long | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	98	32	(4)
Renewables | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(63)	(33)	6
Renewables | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(52)	(42)	0
Renewables | Non-trading | Financial and natural gas contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(6)	(25)	(13)
Renewables | Non-trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 5	$ 12	$ 6

Derivative Instruments and H_10

Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Recognized in Income Statement	$ 6	$ (3)
Current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(29)
Non-current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(86)	(19)
Current assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged asset, fair value hedge		0
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	29	0
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	86	19
Fair Value Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Year to date total per Income Statement	$ 303	$ 298

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Lessee, Lease, Description [Line Items]
Renewal term	40 years
Finance lease liabilities	$ 87	$ 95
Renewables
Lessee, Lease, Description [Line Items]
Finance lease liabilities	$ 41	$ 45
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Finance lease cost
Amortization of right-of-use assets	$ 12	$ 8	$ 17
Interest on lease liabilities	3	3	4
Total finance lease cost	15	11	21
Operating lease cost	20	14	16
Short-term lease cost	6	4	3
Variable lease cost	3	4	0
Total lease cost	$ 44	$ 33	$ 40

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Operating Leases
Operating lease right-of-use assets	$ 159	$ 148
Operating lease liabilities, current	13	12
Operating lease liabilities, long-term	161	149
Total operating lease liabilities	174	161
Finance Leases
Other assets	$ 143	$ 156
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Other current liabilities	$ 7	$ 4
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Other non-current liabilities	$ 80	$ 91
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Total finance lease liabilities	$ 87	$ 95
Weighted-average Remaining Lease Term (years)
Finance leases	6 years 4 months 24 days	7 years 3 months 18 days
Operating leases	16 years 10 months 24 days	20 years 6 months
Weighted-average Discount Rate
Finance leases	3.46%	3.49%
Operating leases	3.69%	3.06%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 14	$ 16	$ 13
Operating cash flows from finance leases	1	3	3
Financing cash flows from finance leases	9	6	9
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	(1)	0	46
Operating leases	$ 25	$ 10	$ 94

Leases - Lease Maturities (Deta

Leases - Lease Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Finance Leases
2023	$ 9
2024	30
2025	8
2026	9
2027	10
Thereafter	33
Total lease payments	99
Less: imputed interest	(12)
Total	87	$ 95
Operating Leases
2023	16
2024	14
2025	14
2026	14
2027	16
Thereafter	183
Total lease payments	257
Less: imputed interest	(83)
Total	$ 174	$ 161

Commitments and Contingent Li_3

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

1 Months Ended

12 Months Ended

May 21, 2020

Nov. 21, 2019 complaint

Jan. 11, 2019 complaint

Mar. 22, 2016

Mar. 03, 2015

Oct. 16, 2014

Sep. 30, 2011

Apr. 30, 2018

Dec. 31, 2022 USD ($) project MW

Dec. 31, 2021 USD ($)

Dec. 31, 2002 plaintiff

May 04, 2021 USD ($)

Jan. 04, 2021 USD ($)

Apr. 12, 2016 USD ($)

Loss Contingencies [Line Items]

Refund period, term

15 months

Approved return on equity

10.02%

9.88%

Regulatory liabilities

$ 2,915

$ 3,022

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

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

2

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

$ 1

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

707

NECEC commitment, amount

$ 90

NECEC commitment, payment during period

$ 9

Complaint III

Loss Contingencies [Line Items]

Regulatory liabilities

8

Complaint II

Loss Contingencies [Line Items]

Regulatory liabilities

28

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

Customer Service Invoice Dispute

Loss Contingencies [Line Items]

Litigation settlement, adjustment amount requested

$ 29

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 2022 and Expiring in 2024 | 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

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, 2022 USD ($)
Purchases
2023	$ 1,066
2024	200
2025	112
2026	86
2027	66
Thereafter	993
Totals	2,523
Sales
2023	321
2024	137
2025	43
2026	28
2027	22
Thereafter	61
Totals	$ 612

Environmental Liabilities (Deta

Environmental Liabilities (Details)	12 Months Ended			77 Months Ended
	Dec. 31, 2022 USD ($) site	Dec. 31, 2011 site	Dec. 31, 2008 site	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Aug. 04, 2016 USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site	24
Number of sites with liability recorded | site	7
Number of sites note expected to incur additional liabilities | site	17
Number of additional sites with liability recorded | site	12
Number of sites where gas was manufactured in the past | site	53
Number of sites for which we have entered into consent orders to investigate and remediate | site	41
FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute | site		16	2
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site	16
Number of sites where gas was manufactured in the past | site	6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site	4
Number of sites where gas was manufactured in the past | site	1
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site	0
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site	1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site	6
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 7,000,000			$ 7,000,000
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	9,000,000			9,000,000
Another Ten Sites | Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	15,000,000			15,000,000
Another Ten Sites | Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	22,000,000			22,000,000
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	112,000,000			112,000,000	$ 113,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	160,000,000			160,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	260,000,000			260,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	0			0
NYSEG | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	10,000,000			10,000,000
RG&E | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	7,000,000			7,000,000
Inactive Manufactured Gas Plants
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	289,000,000			289,000,000	303,000,000
Generation Site On The Mill River In New Haven (English Station)
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation, amount recorded to date | $				35,000,000
Generation Site On The Mill River In New Haven (English Station) | United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 19,000,000			$ 19,000,000	$ 22,000,000
Environmental remediation and investigation cost, remit threshold amount | $						$ 30,000,000

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Current
Federal	$ 0	$ 6	$ 3
State	2	4	9
Current taxes charged to expense	2	10	12
Deferred
Federal	67	49	67
State	49	72	38
Deferred taxes charged to expense	116	121	105
Production tax credits	(97)	(109)	(87)
Investment tax credits	(1)	(1)	(1)
Total Income Tax Expense	$ 20	$ 21	$ 29

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 176	$ 140	$ 119
Depreciation and amortization not normalized	(20)	(19)	(13)
Investment tax credit amortization	(1)	(1)	(1)
Tax return related adjustments	2	0	1
Production tax credits	(97)	(109)	(87)
Tax equity financing arrangements	13	14	1
State tax expense, net of federal benefit	40	61	37
Excess ADIT amortization	(66)	(65)	(42)
Valuation allowance	(35)	21	12
Other, net	8	(21)	2
Total Income Tax Expense	$ 20	$ 21	$ 29

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Deferred Income Tax Liabilities (Assets)
Property related	$ 4,504	$ 4,257
Unfunded future income taxes	129	104
Federal and state tax credits	(942)	(844)
Federal and state NOL’s	(1,086)	(998)
Joint ventures/partnerships	210	188
Nontaxable grant revenue	(270)	(292)
Pension and other post-retirement benefits	(11)	1
Tax Act - tax on regulatory remeasurement	(328)	(352)
Valuation allowance	87	110
Other	(80)	(158)
Deferred Income Tax Liabilities	2,213	2,016
Deferred tax assets	2,717	2,644
Deferred tax liabilities	4,930	4,660
Net Accumulated Deferred Income Tax Liabilities	$ 2,213	$ 2,016

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Income Taxes [Line Items]
Deferred tax assets, valuation allowance	$ 87	$ 110
Increase (decrease) in validation allowance	(23)
Unrecognized tax benefits that would impact effective tax rate	107
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	3,900
Increase (decrease) in validation allowance	(37)
Increase of net operating losses	2
Operating loss and tax credit carryforward, valuation allowance	3
Federal | Renewable Energy and Investment
Income Taxes [Line Items]
Tax credit carry forward	924
State
Income Taxes [Line Items]
Net operating loss carry forwards	346
Tax credit carry forward	147
Increase (decrease) in validation allowance	12
Operating loss and tax credit carryforward, valuation allowance	$ 84

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning Balance	$ 127	$ 127	$ 148
Increases for tax positions related to prior years	2	3	11
Increases for tax positions related to current year	2	0	0
Decreases for tax positions related to prior years	(4)	(3)	(32)
Ending Balance	$ 127	$ 127	$ 127

Post-retirement and Similar O_3

Post-retirement and Similar Obligations - Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	$ 3,487	$ 3,819
Service cost	27	40
Interest cost	111	87
Plan amendments	1	2
Actuarial loss (gain)	(716)	(184)
Curtailments/Settlements	(274)	(38)
Benefits paid	(184)	(239)
Benefit Obligation as of December 31,	2,452	3,487
Change in plan assets
Fair Value of Plan Assets as of January 1,	3,079	3,092
Actual return on plan assets	(584)	237
Employer contributions	22	27
Settlements	(182)	(38)
Benefits paid	(184)	(239)
Fair Value of Plan Assets as of December 31,	2,151	3,079
Funded Status as of December 31,	(301)	(408)
Postretirement Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	408	452
Service cost	2	3
Interest cost	10	10
Plan amendments	0	0
Actuarial loss (gain)	(103)	(23)
Curtailments/Settlements	0	0
Benefits paid	(33)	(34)
Benefit Obligation as of December 31,	284	408
Change in plan assets
Fair Value of Plan Assets as of January 1,	127	167
Actual return on plan assets	(22)	15
Employer contributions	17	12
Settlements	0	0
Benefits paid	(33)	(67)
Fair Value of Plan Assets as of December 31,	89	127
Funded Status as of December 31,	$ (195)	$ (281)

Post-retirement and Similar O_4

Post-retirement and Similar Obligations - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2022 USD ($) trust	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Actuarial gain due to change in discount rates		$ 205
Amortization period	10 years
Annual contributions made	$ 68	58	$ 49
Non-Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Other current and other non-current liabilities	44	63
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	(716)	(184)
Actuarial gain due to change in discount rates	644
Reduction of benefit obligation from settlement and curtailment	274	38
Settlements	182
Curtailments	92
Expected contribution for pension benefit plans during next fiscal year	0
Other current and other non-current liabilities	$ 301	408
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%
Pension Benefits | Return-Seeking assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	60%
Pension Benefits | Liability-Hedging assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	40%
Pension Benefits | Liability-Hedging assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	75%
Pension Benefits | Equity Securities | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation			49%
Pension Benefits | Equity Securities | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation			69%
Pension Benefits | Fixed Income Investments | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation			31%
Pension Benefits | Fixed Income Investments | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation			51%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	$ (103)	(23)
Actuarial gain due to change in discount rates	70
Reduction of benefit obligation from settlement and curtailment	0	0
Expected contribution for pension benefit plans during next fiscal year	9
Other current and other non-current liabilities	$ 195	$ 281
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	58%

Post-retirement and Similar O_5

Post-retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	$ 0	$ 0
Non-current liabilities	(301)	(408)
Total	(301)	(408)
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(190)	(276)
Total	$ (195)	$ (281)

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, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 181	$ 271
Prior service cost (credit)	7	10
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	(91)	(18)
Prior service cost (credit)	$ (1)	$ (1)

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, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 12	$ 16
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ (6)	$ (5)

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, 2022	Dec. 31, 2021
Retirement Benefits [Abstract]
Projected benefit obligation	$ 2,452	$ 3,487
Fair value of plan assets	2,151	3,079
Accumulated benefit obligation	2,429	1,790
Fair value of plan assets	$ 2,151	$ 1,536

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Net Periodic Benefit Cost:
Service cost	$ 27	$ 40
Interest cost	111	87
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	12	16
Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	2	3
Interest cost	10	10
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	(6)	(5)
Networks | Pension Benefits
Net Periodic Benefit Cost:
Service cost	26	39	$ 46
Interest cost	109	86	106
Expected return on plan assets	(162)	(199)	(198)
Amortization of prior service cost (benefit)	1	2	1
Amortization of net loss	49	115	124
Settlement/Curtailment charge	17	6
Curtailment charge	(32)	0	0
Net Periodic Benefit Cost	8	49	79
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	(59)	0	(18)
Settlement charge	(17)	(6)	0
Net loss (gain)	33	(218)	46
Amortization of net loss	(49)	(115)	(124)
Current year prior service cost (credit)	1	2	7
Amortization of prior service (cost) benefit	(1)	(2)	(1)
Net loss (gain)	(92)	(339)	(90)
Total Recognized	(84)	(290)	(11)
Networks | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	2	3	3
Interest cost	10	10	13
Expected return on plan assets	(6)	(7)	(8)
Amortization of prior service cost (benefit)	(1)	(5)	(9)
Amortization of net loss	(4)	2	2
Settlement/Curtailment charge	0	0
Curtailment charge	0	0	0
Net Periodic Benefit Cost	1	3	1
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)	(75)	(31)	11
Amortization of net loss	4	(2)	(2)
Current year prior service cost (credit)	0	1	0
Amortization of prior service (cost) benefit	1	5	9
Net loss (gain)	(70)	(27)	18
Total Recognized	(69)	(24)	19
ARHI | Pension Benefits
Net Periodic Benefit Cost:
Service cost	1	1	1
Interest cost	2	1	1
Expected return on plan assets	(2)	(2)	(2)
Amortization of net loss	1	2	2
Settlement/Curtailment charge	1	1	1
Net Periodic Benefit Cost	3	3	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlement charge	(1)	(1)	0
Net loss (gain)	(1)	(3)	1
Amortization of net loss	(1)	(2)	(2)
Amortization of prior service (cost) benefit	0	0	0
Net loss (gain)	(3)	(6)	(1)
Total Recognized	0	(3)	2
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/Curtailment 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)	(1)	0
Net loss (gain)	(1)	1	0
Amortization of net loss	1	1	1
Amortization of prior service (cost) benefit	0	0	0
Net loss (gain)	(1)	1	1
Total Recognized	$ (2)	$ 0	$ 0

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	5.18%	2.85%
Rate of compensation increase - benefit obligations	2.99%	3.53%
Interest crediting rate	2.87%	2.87%
Discount rate - net periodic benefit	2.85%	2.34%	3.01%
Expected long-term return on plan assets	6.33%	7.30%	7.30%
Rate of compensation increase - net periodic benefit	3.53%	3.52%	3.66%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	5.12%	2.66%
Rate of compensation increase - benefit obligations	3%	3.50%
Discount rate - net periodic benefit	2.66%	2.19%	2.99%
Expected long-term return on plan assets	4.66%	4.05%	5.09%
Rate of compensation increase - net periodic benefit	3.50%	3.50%	3.48%

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, 2022	Dec. 31, 2021
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%	5%
Max.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	6.50%	7%

Post-retirement and Similar _12

Post-retirement and Similar Obligations - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2022 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2023	$ 233
2024	218
2025	215
2026	211
2027	206
2028 - 2032	938
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2023	28
2024	27
2025	26
2026	25
2027	24
2028 - 2032	$ 108

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, 2022	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 2,151	$ 3,079	$ 3,092
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,678	2,532
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	51	69
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	252	298
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	57	138
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	104	276
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	708	837
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	472	862
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	33	51
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	414	733
Pension Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	20
Pension Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	252	298
Pension Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	57	138
Pension Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	104	276
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	0
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,264	1,799
Pension Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	51	49
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	708	837
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	472	862
Pension Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	33	51
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	473	547
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	89	127	$ 167
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	87	125
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	2	5
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 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	69	101
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 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	4	5
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	8	9
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	70	103
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 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	69	101
Postretirement Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	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	17	22
Postretirement Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	2	5
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 | 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 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	4	5
Postretirement Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	8	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 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	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	$ 2

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	May 18, 2021	Dec. 31, 2020
Class of Stock [Line Items]
Treasury stock, shares (in shares)	108,188	112,543
Release of common stock held in trust (in shares)	4,355	301,239
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Number of shares repurchased during period (in shares)	0
Treasury shares (in shares)	997,983
Repurchases of common stock	$ 47	$ 47
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)	56,127	77,883,713
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, 2022	Dec. 31, 2021	Dec. 31, 2020
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	$ 19,961	$ 15,826	$ 15,539
Change	93	(162)	(16)
Balance at end of period	20,342	19,961	15,826
Loss (Gain) for defined benefit plans, income tax expense	3	0	0
Amortization of pension cost, income tax expense (benefit)	(1)	(1)	(3)
Unrealized (loss) gain from equity method investment, income tax (benefit) expense	6	(3)	0
Unrealized loss during the year on derivatives qualifying as cash flow hedges, income tax expense (benefit)	0	(44)	(7)
Reclassification to net income of losses on cash flow hedges, income tax expense (benefit)	19	(3)	2
Loss (gain) for defined benefit plans, net of income tax expense
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(10)	(12)	(12)
Change	14	2	0
Balance at end of period	4	(10)	(12)
Amortization of pension cost, net of income tax expense (benefit)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(28)	(20)	(7)
Change	4	(8)	(13)
Balance at end of period	(24)	(28)	(20)
Unrealized (loss) gain from equity method investment, net of income tax (benefit) expense
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(9)	0	0
Change	22	(9)	0
Balance at end of period	13	(9)	0
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(194)	(35)	(13)
Change	(1)	(159)	(22)
Balance at end of period	(195)	(194)	(35)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(32)	(44)	(63)
Change	54	12	19
Balance at end of period	22	(32)	(44)
Loss on derivatives qualifying as cash flow hedges
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(226)	(79)	(76)
Change	53	(147)	(3)
Balance at end of period	(173)	(226)	(79)
Accumulated Other Comprehensive Loss
AOCI Including Portion Attributable to Noncontrolling Interest, Net of Tax [Roll Forward]
Balance at beginning of period	(273)	(111)	(95)
Change	93	(162)	(16)
Balance at end of period	$ (180)	$ (273)	$ (111)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Numerator:
Net income attributable to AVANGRID, basic	$ 881	$ 707	$ 581
Net income attributable to AVANGRID, diluted	$ 881	$ 707	$ 581
Denominator:
Weighted average number of shares outstanding - basic (in shares)	386,727,246	358,086,621	309,494,939
Weighted average number of shares outstanding - diluted (in shares)	387,215,785	358,578,608	309,559,387
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)	$ 2.28	$ 1.97	$ 1.88
Earnings Per Common Share, Diluted (in dollars per share)	$ 2.27	$ 1.97	$ 1.88

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions		1 Months Ended
	Apr. 29, 2022	Jun. 30, 2022	Dec. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)			$ 41,123	$ 39,504
Liabilities of variable interest entities (VIEs)			20,781	19,543
Solis I
Variable Interest Entity [Line Items]
TEF agreement, investment amount received from tax equity investor	$ 14
TEF agreement, investment amount expected from tax equity investor	$ 58
Aeolus VIII
Variable Interest Entity [Line Items]
TEF agreement, investment amount received from tax equity investor		$ 109
TEF agreement, investment amount expected from tax equity investor			87
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)			2,853	2,039
Liabilities of variable interest entities (VIEs)			$ 424	$ 119

Grants, Government Incentives_3

Grants, Government Incentives and Deferred Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021
Recorded In Deferred Income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	$ 1,130	$ 1,204
Disposals	0	0
Recognized in income	(68)	(74)
Balance at end of period	1,062	1,130
Recorded As Reduction To Related Utility Plant
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	63	67
Disposals	0	0
Recognized in income	(4)	(4)
Balance at end of period	59	63
Other deferred income | Recorded In Deferred Income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	5	14
Disposals	0	0
Recognized in income	(3)	(9)
Balance at end of period	2	5
Renewables | Government grants - Renewables | Recorded In Deferred Income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	1,125	1,190
Disposals	0	0
Recognized in income	(65)	(65)
Balance at end of period	1,060	1,125
Networks | Government grants - Renewables | Recorded As Reduction To Related Utility Plant
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	63	67
Disposals	0	0
Recognized in income	(4)	(4)
Balance at end of period	$ 59	$ 63

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Millions				1 Months Ended	12 Months Ended
	Jan. 10, 2022 USD ($)	Dec. 16, 2020 USD ($)	Dec. 13, 2019 USD ($)	Dec. 31, 2018 USD ($)	Dec. 31, 2022 USD ($) jointVenture plant MW	Dec. 31, 2021 USD ($) a easement	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Sep. 15, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments					$ 437	$ 560
Distribution of earnings from equity method investments					41	21	$ 22
Equity method investment, distributions received in RECs					12	11	14
Undistributed earnings from equity method investees					10
Capitalized interest costs					0	6	$ 8
South Dokata Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 24			23	23
Enterprise value		$ 298
Gain related to remeasurement of retained investment					$ 4
Equity method investment, ownership percentage					15%
South Dokata Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold		85%
Consideration from disposition		$ 238
Gain on sale of business, net of tax		12
Gain on sale of business, pre-tax		$ 16
Effective percentage of economic benefits retained		7.97%
Arizona Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments					$ 87	96
Equity method investment, ownership percentage					50%
Arizona Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold			50%
Consideration from disposition			$ 112
Gain on sale of business, net of tax			$ 96
Coyote Ridge Wind LLC
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold				80%
Equity method investments					$ 15
Equity method investment, ownership percentage					20%
Proceeds from sale of portion of subsidiary				$ 144				$ 84
Horizon Wind Energy LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage					50%
Number of joint ventures | jointVenture					2
Flat Rock Wind Power LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments					$ 90	93
Leased are transmission capacity (in MW) | MW					231
Flat Rock Wind Power II LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments					$ 42	44
Leased are transmission capacity (in MW) | MW					91
Vineyard Wind
Schedule of Equity Method Investments [Line Items]
Equity method investments					$ 9	$ 141
Equity method investment, ownership percentage	50%				50%	50%
Number of easements | easement						2
Vineyard Wind | Lease Area 501
Schedule of Equity Method Investments [Line Items]
Area of land | a						166,886
Vineyard Wind | Lease Area 522
Schedule of Equity Method Investments [Line Items]
Area of land | a						132,370
Joint Venture With CIP
Schedule of Equity Method Investments [Line Items]
Amount of guaranty issued									$ 827
Amount contributed to acquire easement contract, returned						$ 152
Joint Venture With CIP | Letter of Credit
Schedule of Equity Method Investments [Line Items]
Credit facility maximum borrowing capacity									$ 1,200
Joint Venture With CIP | Renewables
Schedule of Equity Method Investments [Line Items]
Joint venture restructuring agreement, payment amount	$ 168
Joint venture restructuring agreement, pretax gain recognized	246
Joint venture restructuring agreement, after tax gain recognized	$ 181
Clearway Energy, Inc
Schedule of Equity Method Investments [Line Items]
Equity method investments					$ 94	99
Equity method investment, ownership percentage					50%
Number of peaking generation plants | plant					2
New York TransCo.
Schedule of Equity Method Investments [Line Items]
Equity method investments					$ 77	$ 49
Equity method investment, ownership percentage					20%
Leased are transmission capacity (in MW) | MW					3,200
Amount funded to date					$ 600

Other Financial Statement Ite_2

Other Financial Statement Items - Schedule of Other Income and (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gain on sale of assets	$ 0	$ 0	$ 20
Allowance for funds used during construction	63	88	56
Carrying costs on regulatory assets	16	17	28
Non-service component of net periodic benefit cost	(58)	(37)	(62)
Other	9	(8)	(24)
Total Other Income (Expense)	$ 30	$ 60	18
Tatanka Project
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee			$ 16

Other Financial Statement Ite_3

Other Financial Statement Items - Schedule of Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Trade receivables and unbilled revenues	$ 1,892	$ 1,420
Allowance for credit losses	(155)	(151)	$ (108)	$ (69)
Total Accounts receivable and unbilled revenues, net	$ 1,737	$ 1,269

Other Financial Statement Ite_4

Other Financial Statement Items - Schedule of Change in Allowance For Bad Debts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 151	$ 108	$ 69
Current period provision	110	110	83
Write-off as uncollectible	(106)	(67)	(44)
Ending balance	$ 155	$ 151	$ 108

Other Financial Statement Ite_5

Other Financial Statement Items - Additional Information (Details) $ in Millions	May 13, 2021 USD ($) project	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for credit losses		$ 155	$ 151	$ 108	$ 69
Sale of Business | Solar Projects In Nevada
Accounts, Notes, Loans and Financing Receivable [Line Items]
Percentage disposed	100%
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		102	108
Allowance for credit losses		$ 67	$ 68

Other Financial Statement Ite_6

Other Financial Statement Items - Schedule of Prepayments and Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid other taxes	$ 136	$ 95
Broker margin and collateral accounts	164	87
Other pledged deposits	12	4
Prepaid expenses	68	58
Other	6	1
Total	$ 386	$ 245

Other Financial Statement Ite_7

Other Financial Statement Items - Schedule of Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021
Payables and Accruals [Abstract]
Advances received	$ 271	$ 204
Accrued salaries	153	127
Short-term environmental provisions	54	52
Collateral deposits received	68	58
Pension and other postretirement	5	5
Finance leases	7	4
Other	35	34
Total	$ 593	$ 484

Segment Information - Additiona

Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2022 segment
Segment Reporting Information [Line Items]
Number of reportable segments	2
Networks
Segment Reporting Information [Line Items]
Number of reportable segments	1
Number of operating segments	9

Segment Information - By Segmen

Segment Information - By Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting Information [Line Items]
Operating Revenues	$ 7,923	$ 6,974	$ 6,320
Depreciation and amortization	1,085	1,014	987
Operating income	852	895	869
Earnings (losses) from equity method investments	262	7	(3)
Interest expense, net of capitalization	303	298	316
Income tax expense (benefit)	20	21	29
Capital expenditures	2,519	2,976	2,781
Adjusted net income	901	780	625
Property, plant and equipment	30,994	28,866
Equity method investments	437	560
Total assets	41,123	39,504
Other
Segment Reporting Information [Line Items]
Operating Revenues	1	1	1
Depreciation and amortization	1	1	1
Operating income	(13)	(7)	8
Earnings (losses) from equity method investments	0	0	0
Interest expense, net of capitalization	67	80	75
Income tax expense (benefit)	40	(29)	(11)
Capital expenditures	8	2	0
Adjusted net income	(130)	(51)	(58)
Property, plant and equipment	17	11
Equity method investments	0	0
Total assets	(499)	800
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	(1)	(1)	(1)
Networks
Segment Reporting Information [Line Items]
Operating Revenues	6,782	5,754	5,188
Networks | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	1	1	1
Networks | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	6,781	5,753	5,187
Depreciation and amortization	660	616	592
Operating income	901	876	877
Earnings (losses) from equity method investments	11	12	10
Interest expense, net of capitalization	220	217	234
Income tax expense (benefit)	94	98	120
Capital expenditures	1,803	2,294	1,838
Adjusted net income	628	661	568
Property, plant and equipment	20,027	18,737
Equity method investments	171	148
Total assets	28,069	26,126
Renewables
Segment Reporting Information [Line Items]
Operating Revenues	1,141	1,220	1,132
Renewables | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	0	0	0
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	1,141	1,220	1,132
Depreciation and amortization	424	397	394
Operating income	(36)	26	(16)
Earnings (losses) from equity method investments	251	(5)	(13)
Interest expense, net of capitalization	16	1	7
Income tax expense (benefit)	(114)	(48)	(80)
Capital expenditures	708	680	943
Adjusted net income	403	170	$ 115
Property, plant and equipment	10,950	10,118
Equity method investments	266	412
Total assets	$ 13,553	$ 12,578

Segment Information - Reconcili

Segment Information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 901	$ 780	$ 625
Adjustments:
Mark-to-market adjustments - Renewables	0	(53)	(5)
Offshore contract provision	(24)	0	0
Restructuring charges	0	0	(6)
Accelerated depreciation from repowering	0	0	(9)
Impact of COVID-19	0	(34)	(29)
Merger costs	(4)	(12)	(6)
Legal settlement - Gas storage	0	0	(5)
Income tax impact of adjustments	7	26	16
Net Income Attributable to Avangrid, Inc.	$ 881	$ 707	$ 581

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To	$ 1	$ 0	$ 1
Purchases From	(46)	(52)	(43)
Iberdrola Renovables Energia, S.L.
Related Party Transaction [Line Items]
Sales To	1	0	0
Purchases From	(5)	(10)	(9)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(12)	(9)	(7)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	7	14	9
Purchases From	0	0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Sales To	0	7	2
Purchases From	0	(39)	0
Other
Related Party Transaction [Line Items]
Sales To	1	2	0
Purchases From	$ (3)	$ (3)	$ 0

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2020	Dec. 31, 2021	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		$ 2,000,000
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, 2022	Dec. 31, 2021
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	$ 1	$ 3
Owed To	(29)	(43)
Iberdrola Financiacion
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(9)	(9)
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	3	8
Owed To	(8)	(8)
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(2)	(2)
Other
Related Party Transaction [Line Items]
Owed By	4	0
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
	Feb. 16, 2023 shares	Aug. 31, 2022 USD ($)	Jun. 30, 2022 installment $ / shares shares	Mar. 31, 2022 USD ($) shares	Feb. 28, 2022 installment shares	Jan. 31, 2022 $ / shares shares	Jun. 30, 2021 $ / shares shares	Mar. 31, 2021 installment $ / shares shares	Feb. 28, 2021 shares	Dec. 31, 2020 installment	Aug. 31, 2020 installment $ / shares shares	Jun. 30, 2020 USD ($) installment shares	May 31, 2020 shares	Mar. 31, 2020 installment shares	Feb. 29, 2020 installment shares	Oct. 31, 2018 set $ / shares shares	Jun. 30, 2018 set $ / shares shares	Dec. 31, 2022 USD ($) $ / shares shares	Dec. 31, 2021 USD ($) installment $ / shares shares	Dec. 31, 2020 USD ($)	Dec. 31, 2019 shares	Dec. 31, 2018 shares	Dec. 31, 2017 shares	Dec. 31, 2016 $ / shares shares
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)																		258,168
Share-based payment award grant date fair value (in dollars per share) | $ / shares																		$ 38.16
Number of shares forfeited (in shares)													2,605					412,776
Number of vesting installments | installment																			3
Grant date fair value (in dollars per share) | $ / shares																		$ 36.55	$ 36.05
Number of awards set granted | set																2	2
Stock-based compensation expense | $																		$ 15	$ 18	$ 14
Income tax benefit recognized for stock-based compensation arrangements | $																		4	$ 5	$ 4
Unrecognized cost for non-vested PSUs | $																		$ 10
Recognition of PSU costs, weighted-average period																		2 years
Performance Shares Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)															208,268			215,235	1,336,787
Share-based payment award options requisite service period																			4 years
Number of shares issued (in shares)				46,737				45,611					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)			25,000			17,500	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			2					1		1	3	1
Number of shares issued (in shares)			8,690			9,390	9,390		1,697
Grant date fair value (in dollars per share) | $ / shares			$ 47.64			$ 48.16	$ 53.59	$ 48.83			$ 48.99
Phantom Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)					9,000									167,060
Number of vesting installments | installment					3									3
Cash used to settle award | $		$ 0.1		$ 2
Share based compensation liability | $																		$ 0	$ 2
Phantom Shares | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	81,000

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, 2022
Number of PSUs and RSUs
Nonvested Balance – beginning of year (in shares)		1,323,328
Granted (in shares)		258,168
Forfeited (in shares)	(2,605)	(412,776)
Vested (in shares)		(83,770)
Nonvested Balance – end of year (in shares)		1,084,951
Weighted Average Grant Date Fair Value
Nonvested Balance – beginning of year (in dollars per share)		$ 36.05
Granted (in dollars per share)		38.16
Forfeited (in dollars per share)		36.21
Vested (in dollars per share)		45.91
Nonvested Balance – end of year (in dollars per share)		$ 36.55

Subsequent events (Details)

Subsequent events (Details) - $ / shares		12 Months Ended
	Feb. 16, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
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, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Income Statements, Captions [Line Items]
Operating Revenues	$ 7,923	$ 6,974	$ 6,320
Operating Expenses
Taxes other than income taxes	658	640	619
Total Operating Expenses	7,071	6,079	5,451
Operating Income	852	895	869
Other Income
Other income	30	60	18
Interest expense	(303)	(298)	(316)
Income Before Income Tax	841	664	568
Income tax expense (benefit)	20	21	29
Net Income Attributable to Avangrid, Inc.	881	707	581
AVANGRID
Condensed Income Statements, Captions [Line Items]
Operating Revenues	0	0	0
Operating Expenses
Operating expense	11	19	10
Taxes other than income taxes	(1)	(11)	(11)
Total Operating Expenses	10	8	(1)
Operating Income	(10)	(8)	1
Other Income
Other income	49	22	35
Equity earnings of subsidiaries	999	756	641
Interest expense	(117)	(93)	(109)
Income Before Income Tax	921	677	568
Income tax expense (benefit)	40	(30)	(13)
Net Income Attributable to Avangrid, Inc.	$ 881	$ 707	$ 581

CONDENSED FINANCIAL INFORMATI_3

CONDENSED FINANCIAL INFORMATION OF PARENT - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Statement of Income Captions [Line Items]
Net Income	$ 881	$ 707	$ 581
Comprehensive Income Attributable to Avangrid, Inc.	974	545	565
AVANGRID
Condensed Statement of Income Captions [Line Items]
Net Income	881	707	581
Other comprehensive income (loss) of subsidiaries	93	(162)	(16)
Comprehensive Income Attributable to Avangrid, Inc.	$ 974	$ 545	$ 565

CONDENSED FINANCIAL INFORMATI_4

CONDENSED FINANCIAL INFORMATION OF PARENT - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 69	$ 1,474
Accounts receivable from subsidiaries	5	11
Notes receivable from affiliates	3	0
Prepayments and other current assets	386	245
Total Current Assets	3,210	3,777
Other assets
Other	413	374
Total Other Assets	3,953	3,845
Total Assets	41,123	39,504
Current Liabilities
Accounts payable and accrued liabilities	2,007	1,586
Accounts payable to subsidiaries	39	61
Interest accrued	66	69
Dividends payable	170	170
Other current liabilities	593	484
Total Current Liabilities	4,416	3,329
Derivative liabilities	164	160
Total non-current liabilities	16,365	16,214
Total Liabilities	20,781	19,543
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	17,694	17,679
Treasury stock	(47)	(47)
Retained earnings	1,910	1,714
Accumulated other comprehensive loss	(180)	(273)
Total Equity	20,342	19,961	$ 15,826	$ 15,539
Total Liabilities and Equity	41,123	39,504
AVANGRID
Current Assets
Cash and cash equivalents	28	1,424
Accounts receivable from subsidiaries	190	128
Notes receivable from affiliates	1,440	1,475
Prepayments and other current assets	17	52
Total Current Assets	1,675	3,079
Investments in subsidiaries	20,588	18,500
Other assets
Deferred income taxes	358	413
Other	3	3
Total Other Assets	361	416
Total Assets	22,624	21,995
Current Liabilities
Notes payable	396	0
Notes payable to subsidiaries	557	643
Accounts payable and accrued liabilities	7	3
Accounts payable to subsidiaries	3	9
Interest accrued	9	9
Interest accrued subsidiaries	9	1
Dividends payable	170	170
Other current liabilities	30	0
Total Current Liabilities	1,181	835
Derivative liabilities	86	19
Non-current debt	1,977	2,065
Total non-current liabilities	2,063	2,084
Total Liabilities	3,244	2,919
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	17,694	17,679
Treasury stock	(47)	(47)
Retained earnings	1,910	1,714
Accumulated other comprehensive loss	(180)	(273)
Total Equity	19,380	19,076
Total Liabilities and Equity	$ 22,624	$ 21,995

CONDENSED FINANCIAL INFORMATI_5

CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	$ 1,035	$ 1,561	$ 1,288
Cash Flow from Investing Activities
Net Cash Used in Investing Activities	(2,548)	(2,440)	(2,858)
Cash Flow from Financing Activities
Proceeds from non-current debt	791	833	1,367
(Repayments) proceeds from non-current debt with affiliate	0	0	3,000
Repurchase of common stock	0	(33)	(2)
Dividends paid	(681)	(613)	(545)
Net Cash Provided by Financing Activities	108	889	2,853
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(1,405)	10	1,283
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,477	1,467	184
Cash, Cash Equivalents and Restricted Cash, End of Year	72	1,477	1,467
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	273	279	278
Cash paid for income taxes	15	2	8
AVANGRID
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	(742)	(397)	(142)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	(14)	130	(73)
Investments in subsidiaries	(1,020)	(1,026)	(591)
Return of capital from investments in subsidiaries	664	1,122	419
Other investments	0	300	(300)
Net Cash Used in Investing Activities	(370)	526	(545)
Cash Flow from Financing Activities
Receipts (repayments) of short-term notes payable from subsidiaries, net	1	(186)	(14)
Receipts (repayments) of short-term notes payable	397	(309)	(253)
Proceeds from non-current debt	0	0	744
(Repayments) proceeds from non-current debt with affiliate	0	(3,000)	3,000
Repayments of non-current debt	0	0	(950)
Repurchase of common stock	0	(33)	(2)
Issuance of common stock	(1)	3,998	(1)
Dividends paid	(681)	(613)	(545)
Net Cash Provided by Financing Activities	(284)	(143)	1,979
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(1,396)	(14)	1,292
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,424	1,438	146
Cash, Cash Equivalents and Restricted Cash, End of Year	28	1,424	1,438
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	86	74	111
Cash paid for income taxes	$ (33)	$ (15)	$ 65

CONDENSED FINANCIAL INFORMATI_6

CONDENSED FINANCIAL INFORMATION OF PARENT - Basis Of Presentation (Details) $ / shares in Units, $ in Millions	May 18, 2021 USD ($) placement $ / shares shares	Apr. 15, 2021	Oct. 20, 2020 USD ($) $ / shares	Dec. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares	Dec. 31, 2020 $ / 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%
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		12 Months Ended
	Feb. 16, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	May 18, 2021
Business Acquisition [Line Items]
Common stock, authorized (in shares)		500,000,000	500,000,000
Common stock issued (in shares)		387,734,757	387,678,630
Common stock, outstanding (in shares)		386,628,586	386,568,104
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01	$ 0.01	$ 0.01
Common stock		$ 3	$ 3
Additional paid-in capital		$ 17,694	$ 17,679
Release of common stock held in trust (in shares)		4,355	301,239
Number of shares repurchased during period (in shares)		0
Treasury shares (in shares)		997,983
Treasury stock		$ 47	$ 47
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)		56,127	77,883,713
AVANGRID
Business Acquisition [Line Items]
Common stock, authorized (in shares)		500,000,000	500,000,000
Common stock issued (in shares)		387,734,757	387,678,630
Common stock, outstanding (in shares)		386,628,586	386,568,104
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01		$ 0.01
Common stock		$ 3	$ 3
Additional paid-in capital		$ 17,694	$ 17,679
Common stock held in trust (in shares)		108,188	112,543
Release of common stock held in trust (in shares)		4,355	301,239
Number of shares repurchased during period (in shares)		0
Treasury shares (in shares)		997,983
Treasury stock		$ 47	$ 47
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)		56,127	77,883,713
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%	81.60%
Target ownership percentage by Parent		81.50%

CONDENSED FINANCIAL INFORMATI_8

CONDENSED FINANCIAL INFORMATION OF PARENT - Long-Term Debt (Details) - USD ($)			12 Months Ended
	Apr. 09, 2020	May 16, 2019	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 14, 2020	Nov. 21, 2017
Debt Instrument [Line Items]
Proceeds from non-current debt			$ 791,000,000	$ 833,000,000	$ 1,367,000,000
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	$ 0	$ 744,000,000
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, 2022	Dec. 31, 2021	Dec. 31, 2020
AVANGRID Networks
Cash Dividend [Line Items]
Cash dividends paid	$ 645	$ 970	$ 419
AVANGRID Renewables
Cash Dividend [Line Items]
Cash dividends paid	$ 19	$ 152	$ 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, 2022	Dec. 31, 2021	Dec. 31, 2020
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 1,020	$ 1,026	$ 591
Non cash contribution/dividend recorded by parent company	473	674
UI
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 986	$ 1,011	$ 590