Avangrid (AGR) 10-Q 26 Oct 23 2023 Q3 Quarterly report Financial data

Cover

Cover - shares	9 Months Ended
	Sep. 30, 2023	Oct. 25, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Sep. 30, 2023
Document Transition Report	false
Entity File Number	001-37660
Entity Registrant Name	Avangrid, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	14-1798693
Entity Address, Address Line One	180 Marsh Hill Road
Entity Address, City or Town	Orange,
Entity Address, State or Province	CT
Entity Address, Postal Zip Code	06477
City Area Code	207
Local Phone Number	629-1190
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	AGR
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		386,770,915
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q3
Entity Central Index Key	0001634997
Current Fiscal Year End Date	--12-31

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Income Statement [Abstract]
Operating Revenues	$ 1,974	$ 1,838	$ 6,027	$ 5,765
Operating Expenses
Purchased power, natural gas and fuel used	482	535	1,844	1,716
Operations and maintenance	924	758	2,319	2,102
Depreciation and amortization	303	279	868	811
Taxes other than income taxes	176	154	516	501
Total Operating Expenses	1,885	1,726	5,547	5,130
Operating Income	89	112	480	635
Other Income and (Expense)
Other income	42	18	96	38
(Losses) Earnings from equity method investments	(1)	2	5	261
Interest expense, net of capitalization	(107)	(76)	(301)	(226)
Income Before Income Tax	23	56	280	708
Income tax (benefit) expense	(8)	(50)	(17)	14
Net Income	31	106	297	694
Net loss (income) attributable to noncontrolling interests	28	(1)	92	40
Net Income Attributable to Avangrid, Inc.	$ 59	$ 105	$ 389	$ 734
Earnings Per Common Share, Basic (in dollars per share)	$ 0.15	$ 0.27	$ 1	$ 1.90
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.15	$ 0.27	$ 1	$ 1.90
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	386,869,341	386,736,774	386,788,279	386,724,035
Diluted (in shares)	387,322,281	387,280,621	387,122,498	387,200,882

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Net Income	$ 31	$ 106	$ 297	$ 694
Other Comprehensive Income (Loss)
Gain for defined benefit plans, net of income taxes of $0 for the three months ended, and $0 and $3 for the nine months ended, respectively	0	0	0	8
Amortization of pension cost, net of income tax of $0 and $0 for the three months, and $1 and $0 for the nine months ended, respectively	0	0	2	1
Unrealized (loss) gain from equity method investment, net of income taxes of $0 and $(5) for the three months ended, respectively, and $1 and $(1) for the nine months ended, respectively	(1)	(13)	4	(2)
Unrealized gain during the period on derivatives qualifying as cash flow hedges, net of income taxes of $11 and $1 for the three months ended, respectively, and $22 and $1 for the nine months ended, respectively	30	3	62	3
Reclassification to net income of losses on cash flow hedges, net of income taxes $15 and $7 for the three months ended, respectively, and $39 and $13 for the nine months ended, respectively	40	19	107	36
Other Comprehensive Income	69	9	175	46
Comprehensive Income	100	115	472	740
Net loss (income) attributable to noncontrolling interests	28	(1)	92	40
Comprehensive Income Attributable to Avangrid, Inc.	$ 128	$ 114	$ 564	$ 780

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, income tax expense (benefit)	$ 0	$ 0	$ 0	$ 3
Amortization of pension cost, income tax expense (benefit)	0	0	1	0
Unrealized (loss) gain from equity method investment, taxes	0	(5)	1	(1)
Unrealized gain during the period on derivatives qualifying as cash flow hedges, taxes	11	1	22	1
Reclassification to net income of losses on cash flow hedges, taxes	$ 15	$ 7	$ 39	$ 13

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Current Assets
Cash and cash equivalents	$ 75	$ 69
Derivative assets	48	60
Fuel and gas in storage	197	268
Materials and supplies	279	235
Prepayments and other current assets	464	386
Regulatory assets	570	447
Total Current Assets	3,058	3,210
Total Property, Plant and Equipment ($2,663 and $2,707 related to VIEs, respectively)	32,068	30,994
Operating lease right-of-use assets	196	159
Equity method investments	514	437
Other investments	43	49
Regulatory assets	2,487	2,321
Other Assets
Goodwill	3,119	3,119
Intangible assets	290	281
Derivative assets	192	140
Other	419	413
Total Other Assets	4,020	3,953
Total Assets	42,386	41,123
Current Liabilities
Current portion of debt	55	412
Interest accrued	103	66
Accounts payable and accrued liabilities	1,517	2,007
Dividends payable	170	170
Taxes accrued	61	61
Operating lease liabilities	15	13
Derivative liabilities	73	133
Other current liabilities	693	593
Regulatory liabilities	235	354
Total Current Liabilities	3,927	4,416
Regulatory liabilities	2,838	2,915
Other Non-current Liabilities
Deferred income taxes	2,406	2,234
Deferred income	1,013	1,062
Pension and other postretirement	450	491
Operating lease liabilities	197	161
Derivative liabilities	141	164
Asset retirement obligations	296	273
Environmental remediation costs	258	279
Other	566	563
Total Other Non-current Liabilities	5,327	5,227
Total Non-current Liabilities	18,084	16,365
Total Liabilities	22,011	20,781
Commitments and Contingencies
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,872,787 and 387,734,757 shares issued; 386,770,915 and 386,628,586 shares outstanding, respectively	3	3
Additional paid in capital	17,699	17,694
Treasury stock	(47)	(47)
Retained earnings	1,789	1,910
Accumulated other comprehensive loss	(5)	(180)
Total Stockholders’ Equity	19,439	19,380
Non-controlling interests	936	962
Total Equity	20,375	20,342
Total Liabilities and Equity	42,386	41,123
Nonrelated Party
Current Assets
Accounts receivable and unbilled revenues, net	1,417	1,737
Current Liabilities
Notes payable	952	566
Other Non-current Liabilities
Non-current debt	9,111	8,215
Related Party
Current Assets
Accounts receivable and unbilled revenues, net	5	5
Notes receivable from affiliates	3	3
Current Liabilities
Notes payable	6	2
Accounts payable to affiliates	47	39
Other Non-current Liabilities
Non-current debt	$ 808	$ 8

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Property, plant and equipment	$ 32,068	$ 30,994
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)	387,872,787	387,734,757
Common stock, outstanding (in shares)	386,770,915	386,628,586
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 2,663	$ 2,707

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022
Cash Flow from Operating Activities:
Net Income	$ 297	$ 694
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	868	811
Regulatory assets/liabilities amortization and carrying cost	(48)	(37)
Pension cost	(11)	(6)
Earnings from equity method investments	(5)	(261)
Distributions of earnings received from equity method investments	21	19
Unrealized loss on marked-to-market derivative contracts	19	17
Deferred taxes	53	10
Other non-cash items	(49)	(28)
Changes in operating assets and liabilities:
Current assets	170	(360)
Noncurrent assets	(107)	8
Current liabilities	(408)	95
Noncurrent liabilities	(43)	(68)
Net Cash Provided by Operating Activities	757	894
Cash Flow from Investing Activities:
Capital expenditures	(2,078)	(1,940)
Contributions in aid of construction	101	90
Proceeds and refund from disposal of assets	48	16
Proceeds from notes receivable from affiliates	0	(1)
Distributions received from equity method investments	4	4
Other investments and equity method investments, net	(99)	(189)
Net Cash Used in Investing Activities	(2,024)	(2,020)
Cash Flow from Financing Activities:
Repayments of non-current debt	(303)	(332)
Receipts of other short-term debt, net	390	209
Repayments of financing leases	(3)	(8)
Issuance of common stock	(3)	(1)
Distributions to noncontrolling interests	(13)	(8)
Contributions from noncontrolling interests	79	146
Dividends paid	(510)	(510)
Net Cash Provided by (Used in) Financing Activities	1,279	(288)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	12	(1,414)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	72	1,477
Cash, Cash Equivalents and Restricted Cash, End of Period	84	63
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	217	200
Cash (refund) paid for income taxes, net of transferred tax credits (Note 16)	(30)	13
Nonrelated Party
Cash Flow from Financing Activities:
Non-current debt issuances	842	216
Related Party
Cash Flow from Financing Activities:
Non-current debt issuances	$ 800	$ 0

Condensed Consolidated Statem_5

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions		Total	Total Stockholders’ Equity	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Noncontrolling Interests
Balance, beginning of period (in shares) at Dec. 31, 2021	[1]			386,568,104
Balance, beginning 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 (loss)		694	734					734		(40)
Other comprehensive income (loss), net of tax		46	46						46
Comprehensive Income		740
Dividends declared		(510)	(510)					(510)
Issuances of common stock (in shares)	[1]			56,127
Issuance of common stock		(1)	(1)			(1)
Stock-based compensation		10	10			10
Distributions to noncontrolling interests		(8)								(8)
Contributions from noncontrolling interests		142	(4)					(4)		146
Balance, end of period (in shares) at Sep. 30, 2022	[1]			386,624,231
Balance, end of period at Sep. 30, 2022		20,334	19,351	$ 3		17,688	(47)	1,934	(227)	983
Balance, beginning of period (in shares) at Jun. 30, 2022	[1]			386,624,231
Balance, beginning of period at Jun. 30, 2022		20,386	19,410	$ 3		17,687	(47)	2,003	(236)	976
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		106	105					105		1
Other comprehensive income (loss), net of tax		9	9						9
Comprehensive Income		115
Dividends declared		(170)	(170)					(170)
Stock-based compensation		1	1			1
Distributions to noncontrolling interests		(2)								(2)
Contributions from noncontrolling interests		4	(4)					(4)		8
Balance, end of period (in shares) at Sep. 30, 2022	[1]			386,624,231
Balance, end of period at Sep. 30, 2022		$ 20,334	19,351	$ 3		17,688	(47)	1,934	(227)	983
Balance, beginning of period (in shares) at Dec. 31, 2022		386,628,586		386,628,586	[1]
Balance, beginning of period at Dec. 31, 2022		$ 20,342	19,380	$ 3		17,694	(47)	1,910	(180)	962
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		297	389					389		(92)
Other comprehensive income (loss), net of tax		175	175						175
Comprehensive Income		472
Dividends declared		(510)	(510)					(510)
Release of common stock held in trust (in shares)	[1]			4,299
Issuances of common stock (in shares)	[1]			138,030
Issuance of common stock		(4)	(4)			(4)
Stock-based compensation		9	9			9
Distributions to noncontrolling interests		(13)								(13)
Contributions from noncontrolling interests		$ 79								79
Balance, end of period (in shares) at Sep. 30, 2023		386,770,915		386,770,915	[1]
Balance, end of period at Sep. 30, 2023		$ 20,375	19,439	$ 3		17,699	(47)	1,789	(5)	936
Balance, beginning of period (in shares) at Jun. 30, 2023	[1]			386,645,258
Balance, beginning of period at Jun. 30, 2023		20,443	19,477	$ 3		17,695	(47)	1,900	(74)	966
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		31	59					59		(28)
Other comprehensive income (loss), net of tax		69	69						69
Comprehensive Income		100
Dividends declared		(170)	(170)					(170)
Issuances of common stock (in shares)	[1]			125,657
Stock-based compensation		4	4			4
Distributions to noncontrolling interests		(6)								(6)
Contributions from noncontrolling interests		$ 4								4
Balance, end of period (in shares) at Sep. 30, 2023		386,770,915		386,770,915	[1]
Balance, end of period at Sep. 30, 2023		$ 20,375	$ 19,439	$ 3		$ 17,699	$ (47)	$ 1,789	$ (5)	$ 936
[1](*) Par value of share amounts is $0.01

Condensed Consolidated Statem_6

Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Statement of Stockholders' Equity [Abstract]
Other comprehensive Income (loss), tax	$ 26	$ 3	$ 63	$ 16
Dividends declared (in dollars per share)	$ 0.44	$ 0.44	$ 1.32	$ 1.32
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01

Background and Nature of Operat

Background and Nature of Operations	9 Months Ended
	Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Background and Nature of Operations	Background and Nature of Operations Avangrid, Inc. (Avangrid, we or the Company) is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.6% of the outstanding common stock of Avangrid. The remaining outstanding shares are owned by various shareholders, with approximately 14.7% of Avangrid's outstanding shares publicly traded on the New York Stock Exchange (NYSE). Proposed Merger with PNMR On October 20, 2020, Avangrid, PNM Resources, Inc., a New Mexico corporation (PNMR), and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of Avangrid (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement), pursuant to which Merger Sub is expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of Avangrid (Merger). Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (PNMR common stock) (other than (i) the issued shares of PNMR common stock that are owned by Avangrid, Merger Sub, PNMR or any wholly-owned subsidiary of Avangrid or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash (Merger Consideration). Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (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. Oral arguments were held on September 15, 2023. We cannot predict the outcome of this proceeding. 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 and again on February 16, 2023. On May 20, 2022, the NRC issued an order extending the effectiveness of its approval until May 25, 2023, and again on March 14, 2023 until May 25, 2024. Furthermore, a new HSR filing was submitted and the waiting period expired on March 10, 2023, providing HSR clearance for another year. In addition, on January 3, 2022, Avangrid, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the First 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 First 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 First Amendment. Subsequently, on April 12, 2023, Avangrid, PNMR and Merger Sub entered into a Second Amendment to the Merger Agreement (the Second Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to further extend the “End Date” for consummation of the Merger until July 20, 2023. The parties acknowledged in the Second 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, 2023. Subsequently, on June 19, 2023, Avangrid, PNMR and Merger Sub entered into a Third Amendment to the Merger Agreement (the Third Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to further extend the “End Date” for consummation of the Merger until December 31, 2023. The parties acknowledged in the Third Amendment that the required regulatory approval from the NMPRC has not been obtained and the parties reasonably determined that such outstanding approval would not be obtained by July 20, 2023. As amended by the Third Amendment, the Merger Agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by December 31, 2023. The Third Amendment also provides that the Merger Agreement can be further extended by 90 days upon mutual agreement by PNMR and Avangrid. 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. We cannot predict the outcome of any other re-applications or requests for extensions of such approvals that may be required. 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 December 31, 2023. 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 (the 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 sets forth certain terms and conditions relating to the Iberdrola Funding Commitment Letter (the Side Letter Agreement, which was amended on July 19, 2023 to replace the LIBOR-based rates with Secured Overnight Financing Rate (SOFR)-based rates). The Side Letter Agreement, as amended, 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 Adjusted Term SOFR or Adjusted Daily Compounded SOFR, as defined in the Side Letter Agreement, 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 20, 2023, Iberdrola assigned the Side Letter Agreement and the Iberdrola Funding Commitment Letter to Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola. On May 18, 2021, we issued 77,821,012 shares of common stock in two private placements. Iberdrola purchased 63,424,125 shares and Hyde Member LLC, a Delaware limited liability company and a wholly owned subsidiary of Qatar Investment Authority, purchased 14,396,887 shares of our common stock, par value $0.01 per share, at the purchase price of $51.40 per share, which was the closing price of the shares of our common stock on the NYSE as of May 11, 2021. Proceeds of the private placements were $4,000 million. $3,000 million of the proceeds were used to repay the Iberdrola Loan. After the effect of the private placements, Iberdrola retained its 81.6% ownership interest in Avangrid.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 2022. The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of Avangrid and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and nine months ended September 30, 2023, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2023.

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Significant Accounting Policies and New Accounting Pronouncements	Significant Accounting Policies and New Accounting Pronouncements The new accounting pronouncements we have adopted as of January 1, 2023, and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2022, except for those described below resulting from the adoption of new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB). Adoption of New Accounting Pronouncements (a) 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. We adopted the new disclosure requirements pursuant to this guidance on January 1, 2023. Accounting Pronouncements Issued but Not Yet Adopted There are no new accounting pronouncements not yet adopted, including those issued since December 31, 2022, that will materially affect our condensed consolidated financial statements.

Revenue

Revenue	9 Months Ended
	Sep. 30, 2023
Revenue from Contract with Customer [Abstract]
Revenue	Revenue We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 13. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. 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 and Contract Liabilities We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in April 2024 upon commercial operation. Contract assets totaled $9 million at both September 30, 2023 and December 31, 2022, and are presented in "Other non-current assets" on our condensed consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $9 million and $33 million at September 30, 2023 and December 31, 2022, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $8 million and $36 million as revenue during the three and nine months ended September 30, 2023, respectively, and $6 million and $20 million for the three and nine months ended September 30, 2022, respectively. Revenues disaggregated by major source for our reportable segments for the three and nine months ended September 30, 2023 and 2022 are as follows: Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,341 $ — $ — $ 1,341 $ 3,602 $ — $ — $ 3,602 Regulated operations – natural gas 185 — — 185 1,158 — — 1,158 Nonregulated operations – wind — 206 — 206 — 638 — 638 Nonregulated operations – solar — 19 — 19 — 40 — 40 Nonregulated operations – thermal — 69 — 69 — 125 — 125 Other(a) 27 (27) — — 46 (54) — (8) Revenue from contracts with customers 1,553 267 — 1,820 4,806 749 — 5,555 Leasing revenue 4 — — 4 10 — — 10 Derivative revenue — 121 — 121 — 335 — 335 Alternative revenue programs 20 — — 20 90 — — 90 Other revenue 10 (1) — 9 30 8 (1) 37 Total operating revenues $ 1,587 $ 387 $ — $ 1,974 $ 4,936 $ 1,092 $ (1) $ 6,027 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,258 $ — $ — $ 1,258 $ 3,457 $ — $ — $ 3,457 Regulated operations – natural gas 248 — — 248 1,319 — — 1,319 Nonregulated operations – wind — 223 — 223 — 720 — 720 Nonregulated operations – solar — 13 — 13 — 29 — 29 Nonregulated operations – thermal — 8 — 8 — 32 — 32 Other(a) 23 (11) (1) 11 82 31 (1) 112 Revenue from contracts with customers 1,529 233 (1) 1,761 4,858 812 (1) 5,669 Leasing revenue 3 — — 3 7 — — 7 Derivative revenue — 60 — 60 — 2 — 2 Alternative revenue programs 7 — — 7 43 — — 43 Other revenue 7 — — 7 37 7 — 44 Total operating revenues $ 1,546 $ 293 $ (1) $ 1,838 $ 4,945 $ 821 $ (1) $ 5,765 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations. As of September 30, 2023 and December 31, 2022, accounts receivable balances related to contracts with customers were approximately $1,299 million and $1,622 million, respectively, including unbilled revenues of $322 million and $541 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets. As of September 30, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of September 30, 2023 2024 2025 2026 2027 2028 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ — $ — $ — $ — $ — $ 1 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 89 18 10 7 5 54 183 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 71 64 21 13 2 2 173 Total operating revenues $ 161 $ 82 $ 31 $ 20 $ 7 $ 56 $ 357 As of September 30, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2023 was $38 million. 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).

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2023
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and LiabilitiesPursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. As of September 30, 2023, the total net amount of these items is approximately $972 million. CMP Distribution Rate Case On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. Following discovery and technical conferences and settlement negotiations, on May 31, 2023, CMP filed a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 100 basis points of CMP’s allowed ROE. The Stipulation also provides for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. The next three increases will occur on January 1, 2024, July 1, 2024, and January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecast by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets. No party opposed the Stipulation and it was approved in its entirety by the MPUC on June 6, 2023. NYSEG and RG&E Rate Plans On May 26, 2022, NYSEG and RG&E filed for a new rate plan with the NYPSC. The rate filings were based on test year 2021 financial results adjusted to the rate year May 1, 2023 – April 30, 2024. 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. On September 16, 2022, the NYPSC suspended new tariffs and rates through April 21, 2023, and NYSEG and RG&E voluntarily agreed to subsequent suspensions through October 18, 2023, subject to a make-whole provision. Following discovery, settlement negotiations, and a hearing on the settlement, on June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. The 2023 JP proposes a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2023 and continuing through April 30, 2026. For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the JP 2023, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs is November 1, 2023 with a make-whole provision back to May 1, 2023. The 2023 JP, as approved, changes in delivery rates for NYSEG's and RG&E’s Electric and Gas businesses that were levelized. Actual bill impacts will vary by customer class based on the agreed‑upon revenue allocation and rate design. The table below illustrates the Revenue Requirements and provides delivery and total bill percentages with rate levelization: Delivery Rate Increase Summary With Rate Levelization Year 1 Year 2 Year 3 Rate Increase Delivery Rate % Total Rate % Rate Increase Delivery Rate % Total Rate % Rate Increase Delivery Rate % Total Rate % (Millions) Increase Increase (millions) Increase Increase (millions) Increase Increase NYSEG Electric $ 137 14.4 % 6.6 % $ 161 14.7 % 7.3 % $ 201 15.1 % 8.2 % NYSEG Gas $ 12 5.5 % 2.0 % $ 12 5.5 % 2.0 % $ 13 5.5 % 2.1 % RG&E Electric $ 51 10.0 % 5.0 % $ 57 10.1 % 5.3 % $ 65 10.2 % 5.7 % RG&E Gas $ 18 9.7 % 3.4 % $ 20 9.8 % 3.6 % $ 22 9.8 % 3.9 % The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas is 9.20%. The common equity ratio for each business is 48.00%. The Earnings Sharing Mechanism (ESM) applicable to each business will be based on Rate Year ESM thresholds as set forth in the table below. 100% of the customers’ portion of earnings above the sharing threshold that would otherwise be deferred for the benefit of customers will be used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition, 50% of NYSEG's and RG&E’s portion will be used to reduce their respective outstanding storm-related regulatory asset deferral balances to the extent such balances exist. Customers / Shareholders Earned ROE No Sharing ROE ≤ 9.70% 50% / 50% ROE > 9.70% and ≤ 10.20% 75% / 25% ROE > 10.20% and ≤ 10.70% 90% / 10% ROE > 10.70% The 2023 JP further enhances distribution vegetation management at NYSEG Electric. NYSEG Electric’s total distribution vegetation management spending will increase to approximately $66 million in Rate Year 1 through three programs. NYSEG Electric routine distribution vegetation management spending will be approximately $34 million in Rate Year 1. In addition, NYSEG Electric will continue its distribution vegetation management Reclamation Program with planned spending of approximately $21 million in Rate Year 1. NYSEG Electric will also continue its Danger Tree program to address danger trees outside of the distribution right-of-way at approximately $11 million in Rate Year 1. RG&E Electric’s total distribution vegetation management spending will be approximately $10.7 million in Rate Year 1 comprised of approximately $9 million for routine distribution vegetation management and $1.7 million for its Danger Tree program, which addresses danger trees outside of the distribution right-of-way. NYSEG and RG&E will continue to be subject to three Electric Reliability Performance Measures: the SAIFI; the CAIDI; and the Distribution Line Inspection Program Metric for Level II Deficiencies. Beginning with calendar year 2023, if NYSEG is assessed a negative revenue adjustment (NRA) for failing to meet its annual SAIFI performance metric, NYSEG will use such NRA(s) for purposes of accelerating its vegetation management reclamation program. The 2023 JP maintains NYSEG’s and RG&E’s current Gas Safety Performance Measures. NYSEG and RG&E will continue to work with New York State Department of Public Service Staff, local fire departments, and emergency management organizations to adopt the principles of the Pipeline Emergency Responders Initiative. NYSEG and RG&E will continue to conduct scenario and hands-on drill trainings for First Responders. In addition, NYSEG and RG&E will continue their Residential Methane Detection (RMD) Program that distributes RMDs to targeted customers and implement a Meter Relocation Pilot Program through which NYSEG and RG&E will move gas meters and service regulators from the inside of a customer’s premises to the outside of a customer’s premises. The 2023 JP establishes threshold performance levels for designated aspects of customer service quality (PSC Complaint Rate, Customer Satisfaction Survey; Calls Answered in 30 Seconds, and Percent of Estimated Bills) and subjects NYSEG and RG&E to potentially significant NRAs if they fail to meet the performance levels. The 2023 JP, among other things, also: 1) requires NYSEG and RG&E to provide a $35 bill credit if they miss a scheduled appointment with a residential customer; 2) provides that Community Distributed Generation (CDG) value stack customers who have not received a revised/corrected bill with the correct credit amount within 45 days of the bill issuance date, shall receive an additional bill credit of $10 per month for each month in excess of the initial 45-day period that the CDG/value stack bill credits are applied; 3) continues enhanced winter protections for residential customers during the cold weather period of November 1 through April 15; 4) enhances extreme heat protections by suspending residential terminations in a geographic operating region on days when temperatures are forecast at or above 85 degrees in that geographic operating region; and 5) commits NYSEG and RG&E to develop training materials, internal policy documents, and other relevant communications pertaining to situations in which a customer indicates that they have been victims of domestic violence. NYSEG and RG&E will continue a RAM to return or collect the remaining Customer Bill Credits established in the 2020 Rate Plan, and the net balance of other 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; (5) costs associated with the implementation of any NYPSC-ordered EV program which are not covered by any other cost recovery mechanisms; and (6) Covid-Related uncollectibles (Rate Year 1 and Rate Year 2 only). The annual RAM recovery/return has been increased from 2.00% to 2.45% of NYSEG’s and RG&E’s delivery revenues (by business) as follows: (1) $29.4 million for NYSEG Electric; (2) $5.8 million for NYSEG Gas; (3) $15.0 million for RG&E Electric; and (4) $5.4 million for RG&E Gas. Customer Bill Credits shall continue to be recovered from those service classes which were eligible to receive such credits. The 2023 JP provides for partial or full reconciliation of certain expenses including, but not limited to pensions / OPEBs; property taxes; management, operations, and staffing audit expense; gas research and development; pipeline integrity costs; and Economic Development programs. The 2023 JP also includes a downward-only Net Plant reconciliation for certain specific projects as well as for the overall capital plan. In addition, the 2023 JP includes downward-only reconciliations for the costs of electric and gas distribution vegetation management; pipeline integrity; gas reconcilable programs; incremental maintenance and employee labor cost levels. NYSEG and RG&E will continue an Electric Revenue Decoupling Mechanism on a total revenue per class basis. The 2023 JP reflects the recovery of deferred NYSEG Electric and RG&E Electric Major Storm costs of approximately $371 million and $54.6 million, respectively. NYSEG’s remaining super storm regulatory asset of $52.3 million and the non-super storm regulatory asset of $96.6 million from the 2020 Joint Proposal are being amortized over seven years. RG&E’s remaining non-super storm regulatory asset of $19.6 million established prior to the 2020 Joint Proposal is being amortized over two years. All other deferred storm costs at both NYSEG and RG&E are being amortized over 10 years. The 2023 JP gradually increases NYSEG’s and RG&E’s Major Storm rate allowances over the term of the 2023 JP to better align NYSEG’s and RG&E’s actual Major Storm costs with such rate allowances and to support NYSEG’s and RG&E’s credit metrics. The Major Storm annual rate allowance for NYSEG Electric is approximately $31.5 million in New York Rate Year 1, $41.5 million in New York Rate Year 2, and $46.5 million in New York Rate Year 3. The Major Storm annual rate allowance for RG&E Electric is approximately $4.5 million in New York Rate Year 1, $6.0 million in New York Rate Year 2, and $7.6 million in New York Rate Year 3. The 2023 JP contains provisions consistent with, supportive of, and in furtherance of the objectives of the Climate Leadership and Community Protection Act (CLCPA) including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan. 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 and second half of 2023, 80% of the first half of 2024, and 20% for the second half of 2024. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the second, third and fourth quarters 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 proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was 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 requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $91 million in UI Rate Year 1, an incremental increase of approximately $20 million in UI Rate Year 2, and an incremental increase of approximately $19 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 included 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. On July 21, 2023, PURA issued a proposed Final Decision (draft decision), providng for an 8.8% ROE, 50% equity ratio, and for a one-year rate plan. UI filed exceptions to the draft decision on August 7, 2023. On August 25, 2023 PURA issued its Final Decision on UI's one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels. On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because factual and legal errors related to the treatment of deferred assets, plant in service, and operating expenses. We cannot predict the outcome of this matter. In 2017, PURA approved new tariffs for the 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 are be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. In 2018, PURA approved new tariffs for 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 April 24, 2023 the Connecticut Attorney General, Office of Consumer Counsel, Connecticut Public Utilities Regulatory Authority Office of Education, Outreach, and Enforcement and the Connecticut Industrial Energy Consumer filed a Petition requesting that PURA conduct a general rate hearing for CNG. On May 5, 2023, CNG and SCG responded indicating a willingness to file general rate cases for each company by November 1, 2023. PURA assented to the companies’ proposal on May 21, 2023. On September 29, 2023, SCG and CNG filed a notice of intent to file general rate cases on or about November 3, 2023. 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. Connecticut Energy Legislation On October 7, 2020, the Governor of Connecticut signed into law an energy bill that, among other things, instructs PURA to revise the rate-making structure in Connecticut to adopt performance-based rates for each electric distribution company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides for certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines. Pursuant to the legislation, on October 30, 2020, PURA re-opened a docket related to new rate designs and review, expanding the scope to consider (a) the implementation of an interim rate decrease; (b) low-income rates; and (c) economic development rates. Separately, UI was due to make its annual RAM filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and RDM. On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement, which addressed issues in both dockets. In an order dated June 23, 2021, PURA approved the as amended settlement agreement in its entirety and it was executed by the parties. The settlement agreement includes a contribution by UI of $5 million and provides customers rate credits of $50 million while allowing UI to collect $52 million in RAM, all over a 22-month period ending April 2023 and also includes a distribution base rate freeze through April 2023. Pursuant to the legislation, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. On June 29, 2023 the Governor of Connecticut signed SB7 into law, which included language that Level 1 storm events were exempt from the waiver. We will continue to review the requirements of the program for the next legislative session. PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court. On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of approximately $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. Oral arguments were held on October 11, 2022, and on October 17, 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI filed a notice of appeal to Connecticut's Appellate court on November 7, 2022 and briefs in April and June 2023. We cannot predict the outcome of this proceeding. Regulatory Assets and Liabilities The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. Regulatory assets as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (Millions) Pension and other post-retirement benefits $ 362 $ 365 Pension and other post-retirement benefits cost deferrals 38 93 Storm costs 767 671 Rate adjustment mechanism 51 41 Revenue decoupling mechanism 59 52 Transmission revenue reconciliation mechanism 2 11 Contracts for differences 43 56 Hardship programs 33 33 Plant decommissioning — 1 Deferred purchased gas 11 56 Environmental remediation costs 236 248 Debt premium 59 64 Unamortized losses on reacquired debt 19 19 Unfunded future income taxes 545 492 Federal tax depreciation normalization adjustment 132 137 Asset retirement obligation 20 20 Deferred meter replacement costs 59 55 COVID-19 cost recovery and late payment surcharge 12 17 Low income arrears forgiveness 61 31 Excess generation service charge 33 24 System Expansion 23 21 Non-bypassable charge 86 14 Hedges losses 14 13 Energy Efficiency Programs 22 13 Rate change levelization 18 — Electric supply reconciliation 13 19 Value of distributed energy resources 48 36 Other 291 166 Total regulatory assets 3,057 2,768 Less: current portion 570 447 Total non-current regulatory assets $ 2,487 $ 2,321 “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. “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 in

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	9 Months Ended
	Sep. 30, 2023
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. • UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as 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 modeled volumes on unit-contingent contracts, extrapolated power curves through May 2032 and scheduling assumptions on California power exports to cover Nevada physical power sales. 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 SOFR, forward interest rate curves or other relevant benchmark. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate contracts). We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value. Restricted cash was $9 million and $3 million as of September 30, 2023 and December 31, 2022, respectively, and is included in "Other Assets" on our condensed consolidated balance sheets. The financial instruments measured at fair value as of September 30, 2023 and December 31, 2022, respectively, consisted of: As of September 30, 2023 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 27 $ 15 $ — $ — $ 42 Derivative assets Derivative financial instruments - power $ 29 $ 36 $ 84 $ (97) $ 52 Derivative financial instruments - gas — 14 — (9) 5 Contracts for differences — — 1 — 1 Derivative financial instruments - Other — 182 — — 182 Total $ 29 $ 232 $ 85 $ (106) $ 240 Derivative liabilities Derivative financial instruments - power $ (30) $ (119) $ (62) $ 163 $ (48) Derivative financial instruments - gas (12) (16) (1) 29 — Contracts for differences — — (44) — (44) Derivative financial instruments - Other — (122) — — (122) Total $ (42) $ (257) $ (107) $ 192 $ (214) As of December 31, 2022 Level 1 Level 2 Level 3 Netting Total (Millions) Equity 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) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2023 and 2022, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2023 2022 2023 2022 Fair Value Beginning of Period, $ 23 $ (151) $ 16 $ (69) Gains recognized in operating revenues — 17 8 69 (Losses) recognized in operating revenues — (17) (12) (79) Total losses recognized in operating revenues — — (4) (10) Gains recognized in OCI — (1) 8 2 (Losses) recognized in OCI (9) (13) (10) (105) Total (losses) gains recognized in OCI (9) (14) (2) (103) Net change recognized in regulatory assets and liabilities 5 5 13 14 Purchases (2) (4) 29 (5) Settlements (39) (2) (74) 7 Fair Value as of September 30, $ (22) $ (166) $ (22) $ (166) Losses for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ — $ — $ (4) $ (10) 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 September 30, 2023 Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.46 $ 9.86 $ 1.99 AECO ($/MMBtu) $ 3.13 $ 10.80 $ 1.00 Ameren ($/MWh) $ 53.89 $ 225.62 $ 20.92 COB ($/MWh) $ 81.12 $ 400.10 $ 10.85 ComEd ($/MWh) $ 49.05 $ 222.49 $ 16.77 ERCOT S hub ($/MWh) $ 50.40 $ 320.63 $ 16.85 Mid C ($/MWh) $ 78.25 $ 400.10 $ 7.85 AEP-DAYTON hub ($/MWh) $ 54.66 $ 229.75 $ 22.50 PJM W hub ($/MWh) $ 57.33 $ 227.60 $ 21.61 Our Level 3 valuations primarily consist of Hydro PPAs utilized for balancing services for the Northwest wind fleet, power swaps with delivery periods extending through May 2032 hedging Midwest and Texas wind farms and physical power sales agreements in Nevada. 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 primary 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 hydro PPAs are long capacity/energy positions in the Northwest that provide balancing services with increases in power prices resulting in unrealized gains and decreases in power prices resulting in unrealized losses. The gas swaps are economic hedges of fuel purchases for a combined cycle gas plant, with increases in gas prices resulting in unrealized gains and decreases 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 modeled volumes on unit-contingent agreements. 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 prices and estimated volumes. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input September 30, 2023 Risk of non-performance 0.72% - 0.74% Discount rate 4.13% - 4.80% Forward pricing ($ per KW-month) $2.00 - $2.61 Fair Value of Debt As of September 30, 2023 and December 31, 2022, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $9,091 million and $7,991 million as of September 30, 2023 and December 31, 2022, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy.

Derivative Instruments and Hedg

Derivative Instruments and Hedging	9 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Derivative Instruments and Hedging Our operating and financing activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities The tables below present Networks' derivative positions as of September 30, 2023 and December 31, 2022, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of September 30, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 26 $ 4 $ 25 $ 3 Derivative liabilities (25) (3) (56) (30) 1 1 (31) (27) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 1 1 (31) (27) Cash collateral receivable — — 15 — Total derivatives as presented in the balance sheet $ 1 $ 1 $ (16) $ (27) 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) The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts (MWh) 5.2 5.7 Natural gas purchase contracts (Dth) 9.4 9.6 Derivatives not designated as hedging instruments NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of September 30, 2023 and December 31, 2022 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2023 and 2022 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended September 30, Nine Months Ended September 30, September 30, 2023 Electricity Natural Gas 2023 Electricity Natural Gas Electricity Natural Gas Regulatory assets $ 2 $ 12 Purchased power, natural gas and fuel used $ 14 $ — $ 85 $ 6 December 31, 2022 2022 Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (49) $ — $ (113) $ (9) 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 September 30, 2023, 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 $42 million, a gross derivative liability of $44 million ($42 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, 2022, UI had 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. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and nine months ended September 30, 2023 and 2022, respectively, were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Derivative liabilities $ 5 $ 5 $ 13 $ 14 Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 1 $ 107 Commodity contracts — Purchased power, natural gas and fuel used — 482 Total $ — $ 1 2022 Interest rate contracts $ — Interest expense $ 1 $ 76 Commodity contracts — Purchased power, natural gas and fuel used (1) 535 Total $ — $ — Nine Months Ended September 30, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 3 $ 301 Commodity contracts — Purchased power, natural gas and fuel used — 1,844 Total $ — $ 3 2022 Interest rate contracts $ — Interest expense $ 3 $ 226 Commodity contracts 2 Purchased power, natural gas and fuel used (3) 1,716 Total $ 2 $ — (a) Changes in accumulated OCI are reported on a pre-tax basis. As of September 30, 2023 and December 31, 2022, the net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization was $40 million and $43 million, respectively. Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million and $3 million, for the three and nine months ended September 30, 2023 and 2022, respectively. Networks will amortize approximately $4 million of net derivative losses related to discontinued cash flow hedges within the next twelve months. (b) Renewables activities Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed-price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed-price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (MWh/Dth in millions) Wholesale electricity purchase contracts 1 2 Wholesale electricity sales contracts 6 7 Natural gas and other fuel purchase contracts 17 15 Financial power contracts 4 6 Basis swaps – purchases 23 22 Basis swaps – sales 1 — The fair values of derivative contracts associated with Renewables' activities as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts $ 57 $ 149 Wholesale electricity sales contracts (70) (200) Natural gas and other fuel purchase contracts 4 2 Financial power contracts 16 8 Total $ 7 $ (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 19, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of September 30, 2023 and December 31, 2022, the fair value of the interest rate swap was $182 million and $116 million, respectively, as a current and non-current asset. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred. The tables below present Renewables' derivative positions as of September 30, 2023 and December 31, 2022, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of September 30, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 67 $ 29 $ 22 $ 4 Derivative liabilities (32) (12) (33) (7) 35 17 (11) (3) Designated as hedging instruments Derivative assets 14 175 4 3 Derivative liabilities (1) (1) (69) (45) 13 174 (65) (42) Total derivatives before offset of cash collateral 48 191 (76) (45) Cash collateral (payable) receivable (1) — 52 20 Total derivatives as presented in the balance sheet $ 47 $ 191 $ (24) $ (25) 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 receivable — — 105 54 Total derivatives as presented in the balance sheet $ 60 $ 139 $ (87) $ (37) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2023, consisted of: Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ (4) $ (9) $ (5) Wholesale electricity sales contracts (19) 14 9 57 Financial power contracts (5) 14 (6) 39 Financial and natural gas contracts — (1) — 5 Total (loss) gain included in operating revenues $ (25) $ 23 $ 1,974 $ (6) $ 96 $ 6,027 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (23) $ — $ (79) Financial and natural gas contracts — 2 — (30) Total loss included in purchased power, natural gas and fuel used $ — $ (21) $ 482 $ — $ (109) $ 1,844 Total (loss) gain $ (25) $ 2 $ (6) $ (13) The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2022, consisted of: Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ 3 $ 2 $ 3 Wholesale electricity sales contracts (4) (21) 2 (31) Financial power contracts (3) 1 (5) (40) Financial and natural gas contracts (1) (4) (1) (25) Total loss included in operating revenues $ (7) $ (21) $ 1,838 $ (2) $ (93) $ 5,765 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 12 $ — $ 65 Financial power contracts — 1 — — Financial and natural gas contracts — (8) — 13 Total gain included in purchased power, natural gas and fuel used $ — $ 5 $ 535 $ — $ 78 $ 1,716 Total loss $ (7) $ (16) $ (2) $ (15) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts 58 Interest Expense — $ 107 Commodity contracts (17) Operating revenues 52 $ 1,974 Total $ 41 $ 52 2022 Interest rate contracts 40 Interest Expense — $ 76 Commodity contracts (33) Operating revenues 22 $ 1,838 Total $ 7 $ 22 Nine Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts 182 Interest Expense — $ 301 Commodity contracts 18 Operating revenues 136 $ 6,027 Total $ 200 $ 136 2022 Interest rate contracts 167 Interest Expense — $ 226 Commodity contracts (163) Operating revenues 41 $ 5,765 Total $ 4 $ 41 (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 $65 million of losses included in accumulated OCI at September 30, 2023, are expected to be reclassified into earnings within the next twelve months. For all of the three and nine months ended September 30, 2023 and 2022, we did not record any net derivative losses related to discontinued cash flow hedges. (c) Interest rate contracts Avangrid uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. As of September 30, 2023 and December 31, 2022, the net loss in accumulated OCI related to previously settled interest rate contracts was $31 million and $38 million, respectively. We amortized into income $2 million and $7 million, for the three and nine months ended September 30, 2023 and 2022, respectively, of the loss related to settled interest rate contracts. We will amortize approximately $9 million of the net loss on the interest rate contracts within the next twelve months. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 2 $ 107 2022 Interest rate contracts $ — Interest expense $ 2 $ 76 Nine Months Ended September 30, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 7 $ 301 2022 Interest rate contracts $ — Interest expense $ 7 $ 226 (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 three and nine months ended September 30, 2023 and 2022, respectively, are as follows: Fair value of hedge Location of (Gain) Recognized in Income Statement Loss Recognized in Income Statement Total per Income Statement (Millions) As of September 30, 2023 Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Current Liabilities $ (32) Interest Expense $ 9 $ 23 $ 107 $ 301 Non-current liabilities $ (88) Cumulative effect on hedged debt Current debt $ 32 Non-current debt $ 88 Fair value of hedge Location of Loss Recognized in Income Statement Loss Recognized in Income Statement Total per Income Statement (Millions) As of December 31, 2022 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Current Liabilities $ (29) Interest Expense $ 3 $ 1 $ 76 $ 226 Non-current liabilities $ (86) Cumulative effect on hedged debt Current debt $ 29 Non-current debt $ 86 (d) Counterparty credit risk management NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold. The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit ratings on senior debt were to fall below investment grade. If such an event had occurred as of September 30, 2023, UI would have had to post an aggregate of approximately $21 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. As of September 30, 2023 and December 31, 2022, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $60 million and $97 million, respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of September 30, 2023 was $14 million, for which we have posted collateral.

Contingencies and Commitments

Contingencies and Commitments	9 Months Ended
	Sep. 30, 2023
Commitments and Contingencies Disclosure [Abstract]
Contingencies and Commitments	Contingencies and Commitments We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is probable and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC pursuant to sections 206 and 306 of the Federal Power Act: against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $29 million and $8 million, respectively, as of September 30, 2023, which has not changed since December 31, 2022, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million, which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019. On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, the 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 the FERC’s orders and remanded the matter back to the FERC. The D.C. Circuit Court held that the FERC failed to offer a reasoned explanation for its decision to reintroduce the RPM after initially, and forcefully, rejecting it and that because the 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 power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014, the FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC trial staff recommended that the complaint against Renewables be dismissed. A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that the price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. On June 17, 2021, the FERC issued an Order Establishing Limited Remand remanding the case to the administrative law judge for additional detailed findings and legal analysis with respect to the impact of the conduct of one of the parties other than Renewables on their long-term contracts. The order did not address any of the other findings, including all of the findings with respect to Renewables, which remain pending. 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, Nike USA, Inc. (Nike), the buyer under a virtual PPA with a subsidiary of Renewables, provided notice that it 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, most notably during Winter Storm Uri in February of 2021. Nike has requested an adjustment to the invoices that would increase the amount payable by approximately $31 million. Renewables has responded that the invoices have been properly calculated in accordance with the provisions of the PPA. The parties participated in a mediation in March 2023, which was unsuccessful. On June 16, 2023, Nike filed suit against the Company and certain subsidiaries of Renewables alleging breach of contract. The parties have filed motions for summary judgement and oral arguments were held on October 23, 2023. The Company filed to dismiss the complaint, and following oral arguments, on October 25, 2023, the court denied the Company’s motion to dismiss, and the case will proceed. We cannot predict the outcome of this matter. Commonwealth Wind and Park City PPAs In October 2022, Commonwealth Wind and Park City Wind announced that they would seek to re-negotiate the price of the certain Power Purchase Agreements, or PPAs, to help mitigate the impacts of inflation, increased interest rates and supply chain disruptions on the projects. On October 21, 2022, Commonwealth Wind filed a motion with the DPU seeking a one-month suspension in the DPU’s proceeding to review the power purchase agreements between Commonwealth Wind and the Massachusetts electric distribution companies, or EDCs, in order to provide an opportunity for Commonwealth Wind, the EDCs, state and regulatory officials, and other stakeholders to evaluate the current economic challenges facing Commonwealth Wind and assess measures that would return the project to economic viability including, but not limited to, certain amendments to the Power Purchase Agreements, or PPAs. In December 2022, Commonwealth Wind filed a motion opposing approval of the PPAs by the DPU and requesting that the proceeding be dismissed. On December 30, 2022, the DPU entered an order denying Commonwealth Wind’s motion and approving the PPAs. On January 30, 2023, Commonwealth Wind appealed the DPU’s December 30th order to the Supreme Judicial Court of Massachusetts. On July 13, 2023, each of the EDCs filed with the DPU a first amendment, termination agreement and release agreed with Commonwealth Wind, providing for an orderly termination of the PPAs, withdrawal of Commonwealth Wind’s appeal, and payment by Commonwealth Wind of a $48 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs in connection with the regulatory approval that is under appeal. The DPU approved the termination agreements on August 2, 2023 and Commonwealth Wind dismissed its appeal of the DPU’s December 30th order. On October 2, 2023, Park City Wind entered into a first amendment, termination agreement and release with each of the Connecticut EDCs, providing for an orderly termination of the Park City Wind PPAs and payment by Park City Wind of an approximately $16 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs. On October 13, 2023, PURA approved the termination agreements. Guarantee Commitments to Third Parties As of September 30, 2023, we had approximately $801 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind as described in Note 19, 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 September 30, 2023, neither we nor our subsidiaries have any liabilities recorded for these instruments. NECEC Commitments

Environmental Liabilities

Environmental Liabilities	9 Months Ended
	Sep. 30, 2023
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; two 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, five 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 $6 million related to six of the twenty-four sites. We have paid remediation costs related to the remaining eighteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $10 million related to another ten sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of September 30, 2023, our estimate for costs to remediate these sites ranges from $15 million to $23 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; thirty-nine sites are included in the New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order of Consent; two sites with individual NYSDEC Orders of Consent; two site under a Brownfield Cleanup Program and two sites are included in Maine Department of Environmental Protection programs (none in the Voluntary Response Action Program, Brownfield Cleanup Program and Uncontrolled Sites Program). The remaining sites are not included in a formal program. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites. As of September 30, 2023, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $129 million to $225 million. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives and changes to current laws and regulations. Certain of our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; as of September 30, 2023, 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 both September 30, 2023 and December 31, 2022, the liability associated with our MGP sites in Connecticut was $112 million, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates. As of September 30, 2023 and December 31, 2022, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $257 million and $289 million, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2053. FirstEnergy NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the sixteen sites in dispute. In 2008, the District Court issued a decision and order in RG&E'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 September 30, 2023, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $8 million and $6 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 On April 8, 2013, DEEP issued an administrative order addressed to UI, 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, 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. On April 18, 2023, DEEP issued a letter to UI requiring a response within 30 days that provides alternative remediation proposals to remediate certain environmental conditions and provides an accounting of costs incurred in connection compliance with the Consent Order. UI responded to the letter on May 18, 2023. UI received a second letter on June 1, 2023 requiring a response in 30 days to provide a schedule to complete investigation of the site and to complete the investigations by September 15, 2023. UI responded on July 3, 2023. As of September 30, 2023 and December 31, 2022, the amount reserved related to English Station was $20 million and $19 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. Eagle Takings Inquiry In April 2023, Avangrid Renewables received a letter from the U.S. Fish and Wildlife Service regarding certain bald and gold eagle fatalities that allegedly occurred at certain Avangrid Renewables facilities that are not covered by an eagle take permit. Avangrid Renewables has responded to the U.S. Fish and Wildlife Service providing information about the relevant eagle

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	9 Months Ended
	Sep. 30, 2023
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar Obligations During the three and nine months ended September 30, 2023, we made $15 million of pension contributions. We do not expect to make any additional contributions in 2023. The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Service cost $ 1 $ 6 $ 4 $ 21 Interest cost 30 10 91 27 Expected return on plan assets (36) (20) (109) (71) Amortization of: Prior service costs — — 1 1 Actuarial loss 1 11 2 40 Curtailment Charge — (1) (24) Net Periodic Benefit Cost $ (4) $ 6 $ (11) $ (6) The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Service cost $ — $ 1 $ 1 $ 2 Interest cost 3 3 10 8 Expected return on plan assets (1) (1) (4) (4) Amortization of: Prior service costs — (1) — (1) Actuarial loss (3) (1) (9) (3) Net Periodic Benefit Cost $ (1) $ 1 $ (2) $ 2

Equity

Equity	9 Months Ended
	Sep. 30, 2023
Equity [Abstract]
Equity	Equity As of September 30, 2023 and December 31, 2022, we had, respectively, 103,889 and 108,188 shares of common stock held in trust and no convertible preferred shares outstanding. During the three and nine months ended September 30, 2023, we released 0 and 4,299 shares of common stock held in trust, respectively. During both the three and nine months ended September 30, 2022, we released 0 shares of common stock held in trust. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of Avangrid, shares of common stock of Avangrid. The purpose of the stock repurchase program is to allow Avangrid to maintain Iberdrola's relative ownership percentage of approximately 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. As of September 30, 2023, a total of 997,983 shares have been repurchased in the open market, all of which are included as Avangrid treasury shares. The total cost of all repurchases, including commissions, was $47 million as of September 30, 2023. Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: As of June 30, Three Months Ended September 30, As of September 30, As of June 30, Three Months Ended September 30, As of September 30, 2023 2023 2023 2022 2022 2022 (Millions) Gain on defined benefit plans, net of income tax expense of $0 and $0 for 2023 and 2022 $ — $ — Amortization of pension cost, net of income tax expense of $0 and $0 for 2023 and 2022 — — Net gain (loss) on pension plans (18) — (18) (29) — (29) Unrealized (loss) gain from equity method investment, net of income tax expense (benefit) of $0 for 2023 and $(5) for 2022 (a) 18 (1) 17 2 (13) (11) Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $11 for 2023 and $1 for 2022 (163) 30 (133) (194) 3 (191) Reclassification to net income of losses on cash flow hedges, net of income tax expense of $15 for 2023 and $7 for 2022 (b) 89 40 129 (15) 19 4 (Loss) Gain on derivatives qualifying as cash flow hedges (74) 70 (4) (209) 22 (187) Accumulated Other Comprehensive Loss $ (74) $ 69 $ (5) $ (236) $ 9 $ (227) As of December 31, Nine Months Ended September 30, As of September 30, As of December 31, Nine Months Ended September 30, As of September 30, 2022 2023 2023 2021 2022 2022 (Millions) Gain on defined benefit plans, net of income tax expense of $0 and $3 for 2023 and 2022 $ — $ 8 Amortization of pension cost, net of income tax expense of $1 and $0 for 2023 and 2022 $ 2 $ 1 Net gain (loss) on pension plans $ (20) $ 2 $ (18) $ (38) $ 9 $ (29) Unrealized (loss) gain from equity method investment, net of income tax expense of $1 for 2023 and $(1) for 2022 (a) $ 13 $ 4 $ 17 $ (9) $ (2) $ (11) Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense of $22 for 2023 and $1 for 2022 (195) 62 (133) (194) 3 (191) Reclassification to net income of losses on cash flow hedges, net of income tax expense of $39 for 2023 and $13 for 2022 (b) 22 107 129 (32) 36 4 (Loss) Gain on derivatives qualifying as cash flow hedges (173) 169 (4) (226) 39 (187) Accumulated Other Comprehensive Loss $ (180) $ 175 $ (5) $ (273) $ 46 $ (227) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization and line items in our condensed consolidated statements of income.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per ShareBasic earnings per share is computed by dividing net income attributable to Avangrid by the weighted-average number of shares of our common stock outstanding. During the three and nine months ended September 30, 2023 and 2022, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations for the both three and nine months ended September 30, 2023 and 2022. The calculations of basic and diluted earnings per share attributable to Avangrid, for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions, except for number of shares and per share data) Numerator: Net income attributable to Avangrid $ 59 $ 105 $ 389 $ 734 Denominator: Weighted average number of shares outstanding - basic 386,869,341 386,736,774 386,788,279 386,724,035 Weighted average number of shares outstanding - diluted 387,322,281 387,280,621 387,122,498 387,200,882 Earnings per share attributable to Avangrid Earnings Per Common Share, Basic $ 0.15 $ 0.27 $ 1.00 $ 1.90 Earnings Per Common Share, Diluted $ 0.15 $ 0.27 $ 1.00 $ 1.90

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2023
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 mark-to-market earnings from changes in the fair value of derivative instruments, offshore contract provision, costs incurred in connection with the COVID-19 pandemic and costs incurred related to the PNMR Merger. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. Segment information as of and for the three and nine months ended September 30, 2023, consisted of: Three Months Ended September 30, 2023 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 1,587 $ 387 $ — $ 1,974 Revenue - intersegment — — — — Depreciation and amortization 175 123 5 303 Operating income (loss) 134 (45) — 89 Earnings (losses) from equity method investments 3 (4) — (1) Interest expense, net of capitalization 76 6 25 107 Income tax expense (benefit) 12 (27) 7 (8) Adjusted net income (loss) 92 55 (42) 105 Nine Months Ended September 30, 2023 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 4,935 $ 1,092 $ — $ 6,027 Revenue - intersegment 1 — (1) — Depreciation and amortization 524 338 6 868 Operating income (loss) 531 (46) (5) 480 Earnings (losses) from equity method investments 11 (6) — 5 Interest expense, net of capitalization 215 16 70 301 Income tax expense (benefit) 70 (87) — (17) Adjusted net income (loss) 364 170 (100) 434 Capital expenditures 1,551 505 22 2,078 As of September 30, 2023 Property, plant and equipment 21,017 11,039 12 32,068 Equity method investments 187 327 — 514 Total assets $ 29,161 $ 13,926 $ (701) $ 42,386 (a) Includes Corporate and intersegment eliminations. Segment information for the three and nine months ended September 30, 2022 and as of December 31, 2022, consisted of: Three Months Ended September 30, 2022 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 1,546 $ 293 $ (1) $ 1,838 Revenue - intersegment — — — — Depreciation and amortization 166 113 — 279 Operating income (loss) 141 (27) (2) 112 Earnings (losses) from equity method investments 3 (1) — 2 Interest expense, net of capitalization 60 2 14 76 Income tax expense (benefit) 13 (56) (7) (50) Adjusted net income (loss) 89 45 (13) 122 Nine Months Ended September 30, 2022 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 4,944 $ 821 $ — $ 5,765 Revenue - intersegment 1 — (1) — Depreciation and amortization 491 319 1 811 Operating income (loss) 660 (17) (8) 635 Earnings from equity method investments 8 253 — 261 Interest expense, net of capitalization 171 8 47 226 Income tax expense (benefit) 65 (35) (16) 14 Adjusted net income (loss) 471 322 (44) 749 Capital expenditures 1,315 617 8 1,940 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. Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the three and nine months ended September 30, 2023 and 2022, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 105 $ 122 $ 434 $ 749 Adjustments: Mark-to-market earnings - Renewables (1) (23) (22) (19) (17) Impact of COVID-19 (2) — — — (2) Merger costs (3) (1) (1) (2) (3) Offshore contract provision (4) (40) — (40) — Income tax impact of adjustments 17 6 16 6 Net Income Attributable to Avangrid, Inc. $ 59 $ 105 $ 389 $ 734 (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) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (3) Pre-merger costs incurred. (4) Costs incurred in connection with offshore contract provision.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2023
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, 2023 2022 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (8) $ — $ (12) Iberdrola Renovables Energía, S.L. $ — $ (2) $ — $ (2) Iberdrola Financiación, S.A.U. $ — $ (12) $ — $ (3) Vineyard Wind $ 2 $ — $ 2 $ — Other $ — $ (1) $ — $ (1) Nine Months Ended September 30, 2023 2022 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (34) $ — $ (34) Iberdrola Renovables Energía, S.L. $ — $ (5) $ — $ (7) Iberdrola Financiación, S.A.U. $ — $ (20) $ — $ (8) Vineyard Wind $ 6 $ — $ 5 $ — Other $ — $ (1) $ — $ (2) Related party balances as of September 30, 2023 and December 31, 2022, respectively, consisted of: As of September 30, 2023 December 31, 2022 (Millions) Owed By Owed To Owed By Owed To Iberdrola $ — $ (34) $ 1 $ (29) Iberdrola Financiación, S.A.U. $ — $ (807) $ — $ (9) Vineyard Wind $ 4 $ (8) $ 3 $ (8) Iberdrola Solutions $ — $ (6) $ — $ (2) Other $ 4 $ (6) $ 4 $ (1) Transactions with Iberdrola relate predominantly to the provision and allocation of corporate services and management fees, and certain financing arrangements described below. 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. We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balance of $6 million and $2 million, respectively, as of September 30, 2023 and December 31, 2022. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances. Avangrid 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 September 30, 2023 and December 31, 2022, was $0. On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of September 30, 2023 and December 31, 2022, there was no outstanding amount under this credit facility. On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan). On July 3, 2023, we entered into a deposit agreement with Iberdrola Financiación, S.A.U., pursuant to which a deposit of $250 million was made on July 3, 2023, which matured on July 24, 2023 at an interest rate of 5.50%. The deposit was paid out on July 24, 2023 with the proceeds of the Intragroup Green Loan. See Note 19 - Equity Method Investments for more information on Vineyard Wind, LLC (Vineyard Wind).

Other Financial Statement Items

Other Financial Statement Items	9 Months Ended
	Sep. 30, 2023
Balance Sheet Related Disclosures [Abstract]
Other Financial Statement Items	Other Financial Statement Items Accounts receivable and unbilled revenue, net Accounts receivable and unbilled revenues, net as of September 30, 2023 and December 31, 2022 consisted of: As of September 30, 2023 December 31, 2022 (Millions) Trade receivables and unbilled revenues $ 1,580 $ 1,892 Allowance for credit losses (163) (155) Accounts receivable and unbilled revenues, net $ 1,417 $ 1,737 The change in the allowance for credit losses for the three and nine months ended September 30, 2023 and 2022 consisted of: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2023 2022 2023 2022 As of Beginning of Period, $ 155 $ 142 $ 155 $ 151 Current period provision 45 45 95 68 Write-off as uncollectible (37) (44) (87) (76) As of September 30, $ 163 $ 143 $ 163 $ 143 The Deferred Payment Arrangements (DPA) receivable balance was $124 million and $102 million at September 30, 2023 and December 31, 2022, respectively. The allowance for credit losses for DPAs at September 30, 2023 and December 31, 2022 was $48 million and $42 million, respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three and nine months ended September 30, 2023 was $1 million and $6 million, respectively, and for the three and nine months ended September 30, 2022 was $(11) million and $(5) million, respectively. Prepayments and other current assets Included in prepayments and other current assets are $190 million and $136 million of prepaid other taxes as of September 30, 2023 and December 31, 2022, respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of September 30, 2023 and December 31, 2022, respectively, were as follows: As of September 30, 2023 December 31, 2022 (Millions) Property, plant and equipment Accumulated depreciation $ 12,278 $ 11,542 Intangible assets Accumulated amortization $ 347 $ 331 As of September 30, 2023 and 2022, accrued liabilities for property, plant and equipment additions were $469 million and $200 million, respectively. Debt On July 3, 2023, NYSEG remarketed $100 million aggregate principal amount of unsecured notes maturing in 2034 at a fixed interest rate of 4.00%. On August 3, 2023, NYSEG issued $350 million aggregate principal amount of unsecured notes maturing in 2028 at a fixed interest rate of 5.65%. On August 3, 2023, NYSEG issued $400 million aggregate principal amount of unsecured notes maturing in 2033 at a fixed interest rate of 5.85%. On October 2, 2023, UI remarketed $65 million aggregate principal amount of unsecured notes maturing in 2033 at a fixed interest rate of 4.50%. Commercial Paper As of September 30, 2023 and December 31, 2022, there was $954 million and $397 million of commercial paper outstanding, respectively. As of September 30, 2023 and December 31, 2022, the weighted-average interest rate on commercial paper was 5.52% and 4.66%, respectively. Supplier Financing Arrangements We operate a supplier financing arrangement. 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, and is reported under financing activity of the consolidated statement of cash flows when the balance is paid. As of September 30, 2023 and December 31, 2022, the amount of notes payable under supplier financing arrangements was $0 and $171 million, respectively. As of December 31, 2022, the weighted average interest rate on the balance was 5.48%. Other current liabilities Included in other current liabilities are $325 million and $271 million of advances received as of September 30, 2023 and December 31, 2022, respectively.

Income Tax Expense

Income Tax Expense	9 Months Ended
	Sep. 30, 2023
Income Tax Disclosure [Abstract]
Income Tax Expense	Income Tax Expense The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2023, were (34.8)% and (6.1)%, respectively. The effective tax rates for the three and nine months ended September 30, 2023, are below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items. The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2022, were (89.3)% and 2.0%, respectively. The effective tax rates for the three and nine months ended September 30, 2022 are below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction, and the release of our federal valuation allowance in the third quarter of 2022 as a result of the Inflation Reduction Act enacted in August 2022 permitting us to utilize tax attributes that were previously expected to expire, partially offset by the tax on gain from the offshore joint venture restructuring transaction (see Note 19 for further details on the transaction). In the third quarter of 2023, Avangrid executed an agreement to transfer the production tax credits generated in 2023 pursuant to the transferability provisions of the Inflation Reduction Act of 2022. Avangrid received cash of $62 million for the transfer of tax credits in the nine months ended September 30, 2023.

Stock-Based Compensation Expens

Stock-Based Compensation Expense	9 Months Ended
	Sep. 30, 2023
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation Expense	Stock-Based Compensation Expense The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares). Performance Stock Units In March 2023, a total number of 677,752 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and are payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The first installment was paid in June 2023, and 125,657 shares of common stock were issued in July 2023 to settle this installment payment. On April 12, 2023 and July 20, 2023, 487,000 PSUs were granted to certain executives of Avangrid with achievement measured based on certain performance and market-based metrics for the 2023 to 2025 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2026, 2027 and 2028. Restricted Stock Units 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. The RSU grant was settled in March 2023, net of applicable taxes, by issuing 3,642 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 first 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 February 2022, 9,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in three equal installments in 2022, 2023 and 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 February and August 2023, $0.2 million was paid to settle the second and third installments under this plan. In February 2023, 81,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards 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. 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. As of September 30, 2023 and December 31, 2022, the total liability was $2 million and $0, respectively, which is included in other current and non-current liabilities. The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three and nine months ended September 30, 2023 was $4 million and $11 million, respectively, and for the three and nine months ended September 30, 2022 was $2 million and $10 million, respectively.

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	Variable Interest Entities We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). Consolidated VIE's consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights. The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our condensed consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. On 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. In March 2023 we received additional investment from our investor in the amount of $61 million. Lund Hill is owned by Solis Solar Power I, LLC (Solis I). The assets and liabilities of the VIEs totaled approximately $2,768 million and $179 million, respectively, at September 30, 2023. As of December 31, 2022, the assets and liabilities of VIEs totaled approximately $2,853 million and $424 million, respectively. At September 30, 2023 and December 31, 2022, 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 September 30, 2023, 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 19 - Equity Method Investments for information on our VIE we do not consolidate.

Equity Method Investments

Equity Method Investments	9 Months Ended
	Sep. 30, 2023
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investments	Equity Method Investments 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 in 2022, 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 for the three months ended March 31, 2022. 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. During the third quarter of 2023 Renewables made a capital contribution of $78 million to Vineyard Wind 1. As of September 30, 2023 and December 31, 2022, the carrying amount of Renewables' investments in Vineyard Wind 1, LLC and Vineyard Wind 1 Pledgor LLC was $87 million and $9 million, respectively. On October 24, 2023, Vineyard Wind 1 closed on a TEF agreement, pursuant to which Vineyard Wind 1 is expected to receive approximately $1.2 billion from tax equity investors in installments based on the number of turbines reaching or about to reach mechanical completion each month until the entire project reaches commercial operation date.

Subsequent Event

Subsequent Event	9 Months Ended
	Sep. 30, 2023
Subsequent Events [Abstract]
Subsequent Event	Subsequent EventOn October 18, 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 January 2, 2024 to shareholders of record at the close of business on December 1, 2023.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Pay vs Performance Disclosure
Net Income Attributable to Avangrid, Inc.	$ 59	$ 105	$ 389	$ 734

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Sep. 30, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Significant Accounting Polici_2

Significant Accounting Policies and New Accounting Pronouncements (Policies)	9 Months Ended
	Sep. 30, 2023
Accounting Policies [Abstract]
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued but Not Yet Adopted	Adoption of New Accounting Pronouncements (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. We adopted the new disclosure requirements pursuant to this guidance on January 1, 2023. Accounting Pronouncements Issued but Not Yet Adopted
Revenue recognition	We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 13. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. 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 and Contract Liabilities We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in April 2024 upon commercial operation. Contract assets totaled $9 million at both September 30, 2023 and December 31, 2022, and are presented in "Other non-current assets" on our condensed consolidated balance sheets.

Revenue (Tables)

Revenue (Tables)	9 Months Ended
	Sep. 30, 2023
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	Revenues disaggregated by major source for our reportable segments for the three and nine months ended September 30, 2023 and 2022 are as follows: Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,341 $ — $ — $ 1,341 $ 3,602 $ — $ — $ 3,602 Regulated operations – natural gas 185 — — 185 1,158 — — 1,158 Nonregulated operations – wind — 206 — 206 — 638 — 638 Nonregulated operations – solar — 19 — 19 — 40 — 40 Nonregulated operations – thermal — 69 — 69 — 125 — 125 Other(a) 27 (27) — — 46 (54) — (8) Revenue from contracts with customers 1,553 267 — 1,820 4,806 749 — 5,555 Leasing revenue 4 — — 4 10 — — 10 Derivative revenue — 121 — 121 — 335 — 335 Alternative revenue programs 20 — — 20 90 — — 90 Other revenue 10 (1) — 9 30 8 (1) 37 Total operating revenues $ 1,587 $ 387 $ — $ 1,974 $ 4,936 $ 1,092 $ (1) $ 6,027 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Networks Renewables Other (b) Total Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,258 $ — $ — $ 1,258 $ 3,457 $ — $ — $ 3,457 Regulated operations – natural gas 248 — — 248 1,319 — — 1,319 Nonregulated operations – wind — 223 — 223 — 720 — 720 Nonregulated operations – solar — 13 — 13 — 29 — 29 Nonregulated operations – thermal — 8 — 8 — 32 — 32 Other(a) 23 (11) (1) 11 82 31 (1) 112 Revenue from contracts with customers 1,529 233 (1) 1,761 4,858 812 (1) 5,669 Leasing revenue 3 — — 3 7 — — 7 Derivative revenue — 60 — 60 — 2 — 2 Alternative revenue programs 7 — — 7 43 — — 43 Other revenue 7 — — 7 37 7 — 44 Total operating revenues $ 1,546 $ 293 $ (1) $ 1,838 $ 4,945 $ 821 $ (1) $ 5,765 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations	As of September 30, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of September 30, 2023 2024 2025 2026 2027 2028 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ — $ — $ — $ — $ — $ 1 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 89 18 10 7 5 54 183 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 71 64 21 13 2 2 173 Total operating revenues $ 161 $ 82 $ 31 $ 20 $ 7 $ 56 $ 357

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2023
Regulated Operations [Abstract]
Schedule of Delivery Rate Increases with Rate Levelization and Requested Revenue Change	The table below illustrates the Revenue Requirements and provides delivery and total bill percentages with rate levelization: Delivery Rate Increase Summary With Rate Levelization Year 1 Year 2 Year 3 Rate Increase Delivery Rate % Total Rate % Rate Increase Delivery Rate % Total Rate % Rate Increase Delivery Rate % Total Rate % (Millions) Increase Increase (millions) Increase Increase (millions) Increase Increase NYSEG Electric $ 137 14.4 % 6.6 % $ 161 14.7 % 7.3 % $ 201 15.1 % 8.2 % NYSEG Gas $ 12 5.5 % 2.0 % $ 12 5.5 % 2.0 % $ 13 5.5 % 2.1 % RG&E Electric $ 51 10.0 % 5.0 % $ 57 10.1 % 5.3 % $ 65 10.2 % 5.7 % RG&E Gas $ 18 9.7 % 3.4 % $ 20 9.8 % 3.6 % $ 22 9.8 % 3.9 %
Schedule of Earnings Sharing Mechanism	Customers / Shareholders Earned ROE No Sharing ROE ≤ 9.70% 50% / 50% ROE > 9.70% and ≤ 10.20% 75% / 25% ROE > 10.20% and ≤ 10.70% 90% / 10% ROE > 10.70%
Schedule of Current and Non-Current Regulatory Assets	Regulatory assets as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (Millions) Pension and other post-retirement benefits $ 362 $ 365 Pension and other post-retirement benefits cost deferrals 38 93 Storm costs 767 671 Rate adjustment mechanism 51 41 Revenue decoupling mechanism 59 52 Transmission revenue reconciliation mechanism 2 11 Contracts for differences 43 56 Hardship programs 33 33 Plant decommissioning — 1 Deferred purchased gas 11 56 Environmental remediation costs 236 248 Debt premium 59 64 Unamortized losses on reacquired debt 19 19 Unfunded future income taxes 545 492 Federal tax depreciation normalization adjustment 132 137 Asset retirement obligation 20 20 Deferred meter replacement costs 59 55 COVID-19 cost recovery and late payment surcharge 12 17 Low income arrears forgiveness 61 31 Excess generation service charge 33 24 System Expansion 23 21 Non-bypassable charge 86 14 Hedges losses 14 13 Energy Efficiency Programs 22 13 Rate change levelization 18 — Electric supply reconciliation 13 19 Value of distributed energy resources 48 36 Other 291 166 Total regulatory assets 3,057 2,768 Less: current portion 570 447 Total non-current regulatory assets $ 2,487 $ 2,321
Schedule of Current and Non-Current Regulatory Liabilities	Regulatory liabilities as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (Millions) Energy efficiency portfolio standard $ 17 $ 30 Gas supply charge and deferred natural gas cost 7 15 Pension and other post-retirement benefits cost deferrals 108 117 Carrying costs on deferred income tax bonus depreciation 2 9 Carrying costs on deferred income tax - Mixed Services 263(a) 1 3 2017 Tax Act 1,198 1,232 Rate Change Levelization 5 25 Revenue decoupling mechanism 11 13 Accrued removal obligations 1,150 1,178 Economic development 11 20 Positive benefit adjustment 10 16 Theoretical reserve flow thru impact 2 3 Deferred property tax 15 17 Net plant reconciliation 16 11 Debt rate reconciliation 22 32 Rate refund – FERC ROE proceeding 37 36 Transmission congestion contracts 31 31 Merger-related rate credits 8 10 Accumulated deferred investment tax credits 21 22 Asset retirement obligation 18 18 Earning sharing provisions 9 13 Middletown/Norwalk local transmission network service collections 16 17 Low income programs 14 18 Non-firm margin sharing credits 32 27 New York 2018 winter storm settlement 2 1 Non by-passable charges 8 76 Transmission revenue reconciliation mechanism 56 75 Other 246 204 Total regulatory liabilities 3,073 3,269 Less: current portion 235 354 Total non-current regulatory liabilities $ 2,838 $ 2,915

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2023
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of September 30, 2023 and December 31, 2022, respectively, consisted of: As of September 30, 2023 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 27 $ 15 $ — $ — $ 42 Derivative assets Derivative financial instruments - power $ 29 $ 36 $ 84 $ (97) $ 52 Derivative financial instruments - gas — 14 — (9) 5 Contracts for differences — — 1 — 1 Derivative financial instruments - Other — 182 — — 182 Total $ 29 $ 232 $ 85 $ (106) $ 240 Derivative liabilities Derivative financial instruments - power $ (30) $ (119) $ (62) $ 163 $ (48) Derivative financial instruments - gas (12) (16) (1) 29 — Contracts for differences — — (44) — (44) Derivative financial instruments - Other — (122) — — (122) Total $ (42) $ (257) $ (107) $ 192 $ (214) As of December 31, 2022 Level 1 Level 2 Level 3 Netting Total (Millions) Equity 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)
Schedule of Reconciliation of Changes in Fair Value and Additional Quantitative Information of CfDs Based on Level 3 Fair Value Instruments	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2023 and 2022, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2023 2022 2023 2022 Fair Value Beginning of Period, $ 23 $ (151) $ 16 $ (69) Gains recognized in operating revenues — 17 8 69 (Losses) recognized in operating revenues — (17) (12) (79) Total losses recognized in operating revenues — — (4) (10) Gains recognized in OCI — (1) 8 2 (Losses) recognized in OCI (9) (13) (10) (105) Total (losses) gains recognized in OCI (9) (14) (2) (103) Net change recognized in regulatory assets and liabilities 5 5 13 14 Purchases (2) (4) 29 (5) Settlements (39) (2) (74) 7 Fair Value as of September 30, $ (22) $ (166) $ (22) $ (166) Losses for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ — $ — $ (4) $ (10) Range at Unobservable Input September 30, 2023 Risk of non-performance 0.72% - 0.74% Discount rate 4.13% - 4.80% Forward pricing ($ per KW-month) $2.00 - $2.61
Schedule of Level 3 Fair Value Measurement	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. As of September 30, 2023 Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.46 $ 9.86 $ 1.99 AECO ($/MMBtu) $ 3.13 $ 10.80 $ 1.00 Ameren ($/MWh) $ 53.89 $ 225.62 $ 20.92 COB ($/MWh) $ 81.12 $ 400.10 $ 10.85 ComEd ($/MWh) $ 49.05 $ 222.49 $ 16.77 ERCOT S hub ($/MWh) $ 50.40 $ 320.63 $ 16.85 Mid C ($/MWh) $ 78.25 $ 400.10 $ 7.85 AEP-DAYTON hub ($/MWh) $ 54.66 $ 229.75 $ 22.50 PJM W hub ($/MWh) $ 57.33 $ 227.60 $ 21.61

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	9 Months Ended
	Sep. 30, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivative Positions including Subject to Master Netting Agreements and Location of Net Derivative Position on Condensed Consolidated Balance Sheets	The tables below present Networks' derivative positions as of September 30, 2023 and December 31, 2022, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of September 30, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 26 $ 4 $ 25 $ 3 Derivative liabilities (25) (3) (56) (30) 1 1 (31) (27) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 1 1 (31) (27) Cash collateral receivable — — 15 — Total derivatives as presented in the balance sheet $ 1 $ 1 $ (16) $ (27) 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) The tables below present Renewables' derivative positions as of September 30, 2023 and December 31, 2022, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of September 30, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 67 $ 29 $ 22 $ 4 Derivative liabilities (32) (12) (33) (7) 35 17 (11) (3) Designated as hedging instruments Derivative assets 14 175 4 3 Derivative liabilities (1) (1) (69) (45) 13 174 (65) (42) Total derivatives before offset of cash collateral 48 191 (76) (45) Cash collateral (payable) receivable (1) — 52 20 Total derivatives as presented in the balance sheet $ 47 $ 191 $ (24) $ (25) 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 receivable — — 105 54 Total derivatives as presented in the balance sheet $ 60 $ 139 $ (87) $ (37)
Schedule of Net Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts (MWh) 5.2 5.7 Natural gas purchase contracts (Dth) 9.4 9.6 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (MWh/Dth in millions) Wholesale electricity purchase contracts 1 2 Wholesale electricity sales contracts 6 7 Natural gas and other fuel purchase contracts 17 15 Financial power contracts 4 6 Basis swaps – purchases 23 22 Basis swaps – sales 1 —
Schedule of Unrealized Gains and Losses from Fair Value Adjustments	The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of September 30, 2023 and December 31, 2022 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2023 and 2022 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended September 30, Nine Months Ended September 30, September 30, 2023 Electricity Natural Gas 2023 Electricity Natural Gas Electricity Natural Gas Regulatory assets $ 2 $ 12 Purchased power, natural gas and fuel used $ 14 $ — $ 85 $ 6 December 31, 2022 2022 Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (49) $ — $ (113) $ (9) The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three and nine months ended September 30, 2023 and 2022, respectively, were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Derivative liabilities $ 5 $ 5 $ 13 $ 14
Schedule of Effect of Derivatives in Cash Flow Hedging Relationships	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 1 $ 107 Commodity contracts — Purchased power, natural gas and fuel used — 482 Total $ — $ 1 2022 Interest rate contracts $ — Interest expense $ 1 $ 76 Commodity contracts — Purchased power, natural gas and fuel used (1) 535 Total $ — $ — Nine Months Ended September 30, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 3 $ 301 Commodity contracts — Purchased power, natural gas and fuel used — 1,844 Total $ — $ 3 2022 Interest rate contracts $ — Interest expense $ 3 $ 226 Commodity contracts 2 Purchased power, natural gas and fuel used (3) 1,716 Total $ 2 $ — (a) Changes in accumulated OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts 58 Interest Expense — $ 107 Commodity contracts (17) Operating revenues 52 $ 1,974 Total $ 41 $ 52 2022 Interest rate contracts 40 Interest Expense — $ 76 Commodity contracts (33) Operating revenues 22 $ 1,838 Total $ 7 $ 22 Nine Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives (a) Location of (Gain) Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts 182 Interest Expense — $ 301 Commodity contracts 18 Operating revenues 136 $ 6,027 Total $ 200 $ 136 2022 Interest rate contracts 167 Interest Expense — $ 226 Commodity contracts (163) Operating revenues 41 $ 5,765 Total $ 4 $ 41 (a) Changes in OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 2 $ 107 2022 Interest rate contracts $ — Interest expense $ 2 $ 76 Nine Months Ended September 30, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 7 $ 301 2022 Interest rate contracts $ — Interest expense $ 7 $ 226 (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 of Derivative Contract	The fair values of derivative contracts associated with Renewables' activities as of September 30, 2023 and December 31, 2022, respectively, consisted of: September 30, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts $ 57 $ 149 Wholesale electricity sales contracts (70) (200) Natural gas and other fuel purchase contracts 4 2 Financial power contracts 16 8 Total $ 7 $ (41)
Schedule of Effects of Trading and Non-Trading Derivatives	The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2023, consisted of: Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1) $ (4) $ (9) $ (5) Wholesale electricity sales contracts (19) 14 9 57 Financial power contracts (5) 14 (6) 39 Financial and natural gas contracts — (1) — 5 Total (loss) gain included in operating revenues $ (25) $ 23 $ 1,974 $ (6) $ 96 $ 6,027 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (23) $ — $ (79) Financial and natural gas contracts — 2 — (30) Total loss included in purchased power, natural gas and fuel used $ — $ (21) $ 482 $ — $ (109) $ 1,844 Total (loss) gain $ (25) $ 2 $ (6) $ (13) The effects of trading and non-trading derivatives associated with Renewables' activities for the three and nine months ended September 30, 2022, consisted of: Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Trading Non-trading Total amount per income statement Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ 3 $ 2 $ 3 Wholesale electricity sales contracts (4) (21) 2 (31) Financial power contracts (3) 1 (5) (40) Financial and natural gas contracts (1) (4) (1) (25) Total loss included in operating revenues $ (7) $ (21) $ 1,838 $ (2) $ (93) $ 5,765 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 12 $ — $ 65 Financial power contracts — 1 — — Financial and natural gas contracts — (8) — 13 Total gain included in purchased power, natural gas and fuel used $ — $ 5 $ 535 $ — $ 78 $ 1,716 Total loss $ (7) $ (16) $ (2) $ (15)
Schedule of Fair Value Hedging Instruments	The effects on our consolidated financial statements as of and for the three and nine months ended September 30, 2023 and 2022, respectively, are as follows: Fair value of hedge Location of (Gain) Recognized in Income Statement Loss Recognized in Income Statement Total per Income Statement (Millions) As of September 30, 2023 Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Three Months Ended September 30, 2023 Nine Months Ended September 30, 2023 Current Liabilities $ (32) Interest Expense $ 9 $ 23 $ 107 $ 301 Non-current liabilities $ (88) Cumulative effect on hedged debt Current debt $ 32 Non-current debt $ 88 Fair value of hedge Location of Loss Recognized in Income Statement Loss Recognized in Income Statement Total per Income Statement (Millions) As of December 31, 2022 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Three Months Ended September 30, 2022 Nine Months Ended September 30, 2022 Current Liabilities $ (29) Interest Expense $ 3 $ 1 $ 76 $ 226 Non-current liabilities $ (86) Cumulative effect on hedged debt Current debt $ 29 Non-current debt $ 86

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	9 Months Ended
	Sep. 30, 2023
Retirement Benefits [Abstract]
Schedule of Components of Net Periodic Pension and Postretirement Benefits	The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Service cost $ 1 $ 6 $ 4 $ 21 Interest cost 30 10 91 27 Expected return on plan assets (36) (20) (109) (71) Amortization of: Prior service costs — — 1 1 Actuarial loss 1 11 2 40 Curtailment Charge — (1) (24) Net Periodic Benefit Cost $ (4) $ 6 $ (11) $ (6) The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Service cost $ — $ 1 $ 1 $ 2 Interest cost 3 3 10 8 Expected return on plan assets (1) (1) (4) (4) Amortization of: Prior service costs — (1) — (1) Actuarial loss (3) (1) (9) (3) Net Periodic Benefit Cost $ (1) $ 1 $ (2) $ 2

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2023
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: As of June 30, Three Months Ended September 30, As of September 30, As of June 30, Three Months Ended September 30, As of September 30, 2023 2023 2023 2022 2022 2022 (Millions) Gain on defined benefit plans, net of income tax expense of $0 and $0 for 2023 and 2022 $ — $ — Amortization of pension cost, net of income tax expense of $0 and $0 for 2023 and 2022 — — Net gain (loss) on pension plans (18) — (18) (29) — (29) Unrealized (loss) gain from equity method investment, net of income tax expense (benefit) of $0 for 2023 and $(5) for 2022 (a) 18 (1) 17 2 (13) (11) Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $11 for 2023 and $1 for 2022 (163) 30 (133) (194) 3 (191) Reclassification to net income of losses on cash flow hedges, net of income tax expense of $15 for 2023 and $7 for 2022 (b) 89 40 129 (15) 19 4 (Loss) Gain on derivatives qualifying as cash flow hedges (74) 70 (4) (209) 22 (187) Accumulated Other Comprehensive Loss $ (74) $ 69 $ (5) $ (236) $ 9 $ (227) As of December 31, Nine Months Ended September 30, As of September 30, As of December 31, Nine Months Ended September 30, As of September 30, 2022 2023 2023 2021 2022 2022 (Millions) Gain on defined benefit plans, net of income tax expense of $0 and $3 for 2023 and 2022 $ — $ 8 Amortization of pension cost, net of income tax expense of $1 and $0 for 2023 and 2022 $ 2 $ 1 Net gain (loss) on pension plans $ (20) $ 2 $ (18) $ (38) $ 9 $ (29) Unrealized (loss) gain from equity method investment, net of income tax expense of $1 for 2023 and $(1) for 2022 (a) $ 13 $ 4 $ 17 $ (9) $ (2) $ (11) Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense of $22 for 2023 and $1 for 2022 (195) 62 (133) (194) 3 (191) Reclassification to net income of losses on cash flow hedges, net of income tax expense of $39 for 2023 and $13 for 2022 (b) 22 107 129 (32) 36 4 (Loss) Gain on derivatives qualifying as cash flow hedges (173) 169 (4) (226) 39 (187) Accumulated Other Comprehensive Loss $ (180) $ 175 $ (5) $ (273) $ 46 $ (227) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization and line items in our condensed consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2023
Earnings Per Share [Abstract]
Schedule of Calculations of Basic and Diluted Earnings Per Share	The calculations of basic and diluted earnings per share attributable to Avangrid, for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions, except for number of shares and per share data) Numerator: Net income attributable to Avangrid $ 59 $ 105 $ 389 $ 734 Denominator: Weighted average number of shares outstanding - basic 386,869,341 386,736,774 386,788,279 386,724,035 Weighted average number of shares outstanding - diluted 387,322,281 387,280,621 387,122,498 387,200,882 Earnings per share attributable to Avangrid Earnings Per Common Share, Basic $ 0.15 $ 0.27 $ 1.00 $ 1.90 Earnings Per Common Share, Diluted $ 0.15 $ 0.27 $ 1.00 $ 1.90

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2023
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the three and nine months ended September 30, 2023, consisted of: Three Months Ended September 30, 2023 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 1,587 $ 387 $ — $ 1,974 Revenue - intersegment — — — — Depreciation and amortization 175 123 5 303 Operating income (loss) 134 (45) — 89 Earnings (losses) from equity method investments 3 (4) — (1) Interest expense, net of capitalization 76 6 25 107 Income tax expense (benefit) 12 (27) 7 (8) Adjusted net income (loss) 92 55 (42) 105 Nine Months Ended September 30, 2023 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 4,935 $ 1,092 $ — $ 6,027 Revenue - intersegment 1 — (1) — Depreciation and amortization 524 338 6 868 Operating income (loss) 531 (46) (5) 480 Earnings (losses) from equity method investments 11 (6) — 5 Interest expense, net of capitalization 215 16 70 301 Income tax expense (benefit) 70 (87) — (17) Adjusted net income (loss) 364 170 (100) 434 Capital expenditures 1,551 505 22 2,078 As of September 30, 2023 Property, plant and equipment 21,017 11,039 12 32,068 Equity method investments 187 327 — 514 Total assets $ 29,161 $ 13,926 $ (701) $ 42,386 (a) Includes Corporate and intersegment eliminations. Segment information for the three and nine months ended September 30, 2022 and as of December 31, 2022, consisted of: Three Months Ended September 30, 2022 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 1,546 $ 293 $ (1) $ 1,838 Revenue - intersegment — — — — Depreciation and amortization 166 113 — 279 Operating income (loss) 141 (27) (2) 112 Earnings (losses) from equity method investments 3 (1) — 2 Interest expense, net of capitalization 60 2 14 76 Income tax expense (benefit) 13 (56) (7) (50) Adjusted net income (loss) 89 45 (13) 122 Nine Months Ended September 30, 2022 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 4,944 $ 821 $ — $ 5,765 Revenue - intersegment 1 — (1) — Depreciation and amortization 491 319 1 811 Operating income (loss) 660 (17) (8) 635 Earnings from equity method investments 8 253 — 261 Interest expense, net of capitalization 171 8 47 226 Income tax expense (benefit) 65 (35) (16) 14 Adjusted net income (loss) 471 322 (44) 749 Capital expenditures 1,315 617 8 1,940 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.
Schedule of Reconciliation of Adjusted Net Income to Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the three and nine months ended September 30, 2023 and 2022, respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2023 2022 2023 2022 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 105 $ 122 $ 434 $ 749 Adjustments: Mark-to-market earnings - Renewables (1) (23) (22) (19) (17) Impact of COVID-19 (2) — — — (2) Merger costs (3) (1) (1) (2) (3) Offshore contract provision (4) (40) — (40) — Income tax impact of adjustments 17 6 16 6 Net Income Attributable to Avangrid, Inc. $ 59 $ 105 $ 389 $ 734 (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) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (3) Pre-merger costs incurred. (4) Costs incurred in connection with offshore contract provision.

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2023
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three and nine months ended September 30, 2023 and 2022, respectively, consisted of: Three Months Ended September 30, 2023 2022 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (8) $ — $ (12) Iberdrola Renovables Energía, S.L. $ — $ (2) $ — $ (2) Iberdrola Financiación, S.A.U. $ — $ (12) $ — $ (3) Vineyard Wind $ 2 $ — $ 2 $ — Other $ — $ (1) $ — $ (1) Nine Months Ended September 30, 2023 2022 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (34) $ — $ (34) Iberdrola Renovables Energía, S.L. $ — $ (5) $ — $ (7) Iberdrola Financiación, S.A.U. $ — $ (20) $ — $ (8) Vineyard Wind $ 6 $ — $ 5 $ — Other $ — $ (1) $ — $ (2) Related party balances as of September 30, 2023 and December 31, 2022, respectively, consisted of: As of September 30, 2023 December 31, 2022 (Millions) Owed By Owed To Owed By Owed To Iberdrola $ — $ (34) $ 1 $ (29) Iberdrola Financiación, S.A.U. $ — $ (807) $ — $ (9) Vineyard Wind $ 4 $ (8) $ 3 $ (8) Iberdrola Solutions $ — $ (6) $ — $ (2) Other $ 4 $ (6) $ 4 $ (1)

Other Financial Statement Ite_2

Other Financial Statement Items (Tables)	9 Months Ended
	Sep. 30, 2023
Balance Sheet Related Disclosures [Abstract]
Schedule of Accounts Receivable and Unbilled Revenues, Net	Accounts receivable and unbilled revenues, net as of September 30, 2023 and December 31, 2022 consisted of: As of September 30, 2023 December 31, 2022 (Millions) Trade receivables and unbilled revenues $ 1,580 $ 1,892 Allowance for credit losses (163) (155) Accounts receivable and unbilled revenues, net $ 1,417 $ 1,737
Schedule of Allowance for Credit Loss	The change in the allowance for credit losses for the three and nine months ended September 30, 2023 and 2022 consisted of: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2023 2022 2023 2022 As of Beginning of Period, $ 155 $ 142 $ 155 $ 151 Current period provision 45 45 95 68 Write-off as uncollectible (37) (44) (87) (76) As of September 30, $ 163 $ 143 $ 163 $ 143
Schedule of Accumulated Depreciation and Amortization	The accumulated depreciation and amortization as of September 30, 2023 and December 31, 2022, respectively, were as follows: As of September 30, 2023 December 31, 2022 (Millions) Property, plant and equipment Accumulated depreciation $ 12,278 $ 11,542 Intangible assets Accumulated amortization $ 347 $ 331

Background and Nature Of Oper_2

Background and Nature Of Operations (Details) $ / shares in Units, $ in Millions	Apr. 12, 2023 USD ($)	May 18, 2021 USD ($) placement $ / shares shares	Apr. 15, 2021	Sep. 30, 2023 $ / shares	Jun. 30, 2023 $ / shares	Dec. 31, 2022 $ / shares	Sep. 30, 2022 $ / shares	Jun. 30, 2022 $ / shares	Dec. 31, 2021 $ / shares	Oct. 20, 2020 $ / shares
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares		77,821,012
Sale of stock, number of placements | placement		2
Common stock, par value (in dollars per share) | $ / shares		$ 0.01		$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Sale of stock, price (in dollars per share) | $ / shares		$ 51.40
Proceeds of private placements		$ 4,000
Proceeds of private placements, used to repay debt		$ 3,000
Iberdrola Financiación, S.A.U.
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares		63,424,125
Hyde Member LLC And Subsidiary Of Qatar Investment Authority
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares		14,396,887
NM Green Holdings, Inc.
Nature Of Business [Line Items]
Merger agreement, share price (in dollars per share) | $ / shares										$ 50.30
Merger agreement term, ownership percentage benchmark (no more than)										15%
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
Nature Of Business [Line Items]
Debt basis spread on variable rate			0.75%
Facility fee percentage on undrawn portion of funding commitment			0.12%
Merger With PNMR
Nature Of Business [Line Items]
Acquisition, commitment letter amount	$ 4,300
Avangrid | Iberdrola Financiación, S.A.U.
Nature Of Business [Line Items]
Parent company, ownership percentage				81.60%
Avangrid | Various Shareholders
Nature Of Business [Line Items]
Ownership percentage by various shareholders				14.70%

Revenue - Narrative (Details)

Revenue - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Contract assets	$ 9		$ 9		$ 9
TCC contract liabilities	9		9		33
Revenue recognized	8	$ 6	36	$ 20
Accounts receivable related to contracts with customers	1,299		1,299		1,622
Unbilled revenues	322		322		$ 541
Revenue, remaining performance obligation, amount	$ 357		$ 357
Transmission congestion contracts | Min.
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing			6 months
Transmission congestion contracts | Max.
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing			2 years
Networks
Disaggregation of Revenue [Line Items]
Period between the delivery of promised goods or service and customer payment (or less)			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	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 1,820	$ 1,761	$ 5,555	$ 5,669
Leasing revenue	4	3	10	7
Derivative revenue	121	60	335	2
Alternative revenue programs	20	7	90	43
Other revenue	9	7	37	44
Total operating revenues	1,974	1,838	6,027	5,765
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,341	1,258	3,602	3,457
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	185	248	1,158	1,319
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	206	223	638	720
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	19	13	40	29
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	69	8	125	32
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	11	(8)	112
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	(1)	0	(1)
Leasing revenue	0	0	0	0
Derivative revenue	0	0	0	0
Alternative revenue programs	0	0	0	0
Other revenue	0	0	(1)	0
Total operating revenues	0	(1)	(1)	(1)
Other | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	(1)	0	(1)
Networks
Segment Reporting Information [Line Items]
Total operating revenues	1,587	1,546	4,935	4,944
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,553	1,529	4,806	4,858
Leasing revenue	4	3	10	7
Derivative revenue	0	0	0	0
Alternative revenue programs	20	7	90	43
Other revenue	10	7	30	37
Total operating revenues	1,587	1,546	4,936	4,945
Networks | Operating Segments | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,341	1,258	3,602	3,457
Networks | Operating Segments | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	185	248	1,158	1,319
Networks | Operating Segments | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Networks | Operating Segments | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Networks | Operating Segments | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Networks | Operating Segments | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	27	23	46	82
Renewables
Segment Reporting Information [Line Items]
Total operating revenues	387	293	1,092	821
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	267	233	749	812
Leasing revenue	0	0	0	0
Derivative revenue	121	60	335	2
Alternative revenue programs	0	0	0	0
Other revenue	(1)	0	8	7
Total operating revenues	387	293	1,092	821
Renewables | Operating Segments | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Renewables | Operating Segments | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0	0
Renewables | Operating Segments | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	206	223	638	720
Renewables | Operating Segments | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	19	13	40	29
Renewables | Operating Segments | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	69	8	125	32
Renewables | Operating Segments | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ (27)	$ (11)	$ (54)	$ 31

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Sep. 30, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 357
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
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	183
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	173
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-10-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 38
Remaining performance obligation, period	3 months
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	$ 161
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 89
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	$ 71
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	$ 82
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 18
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	$ 64
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	$ 31
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 10
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 21
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	$ 20
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 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]: 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	$ 13
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	$ 7
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	1 year
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	$ 5
Remaining performance obligation, period	1 year
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	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 56
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | 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]: 2029-01-01 | 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	$ 54
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 2
Remaining performance obligation, period

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Narrative (Details) - USD ($)

3 Months Ended

9 Months Ended

Aug. 25, 2023

Jul. 21, 2023

Jun. 14, 2023

May 31, 2023

Sep. 09, 2022

Jun. 24, 2022

Jul. 14, 2021

Jun. 23, 2021

May 06, 2021

Apr. 15, 2021

Nov. 21, 2019

Jan. 01, 2019

Jan. 01, 2018

Jan. 01, 2017

Sep. 30, 2023

Sep. 30, 2022

Sep. 30, 2023

Sep. 30, 2022

Dec. 31, 2022

Regulatory Assets And Liabilities [Line Items]

Unrecorded regulatory assets

$ 972,000,000

$ 972,000,000

Public utilities, approved return on equity

9.88%

Regulatory assets

3,057,000,000

$ 3,057,000,000

$ 2,768,000,000

Deferred storm costs, amortization period

10 years

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

80%

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

20%

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

Civil penalty amount

$ 1,000,000

$ 2,000,000

Unfunded future income tax expense collection period

46 years

UIL Holdings

Regulatory Assets And Liabilities [Line Items]

Business combination merger related rate credits

$ 1,000,000

$ 0

$ 2,000,000

$ 2,000,000

Rate Change Levelization

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

5 years

Regulatory liability, amortization period

5 years

5 years

Energy efficiency portfolio standard

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

3 years

Carrying costs on deferred income tax bonus depreciation

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

3 years

Carrying costs on deferred income tax - Mixed Services 263(a)

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

3 years

Positive benefit adjustment

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

3 years

Deferred property tax

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

5 years

Net plant reconciliation

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

5 years

Transmission congestion contracts

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

5 years

New York 2018 winter storm settlement

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

3 years

Max. | Theoretical reserve flow thru impact

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

5 years

Min. | Theoretical reserve flow thru impact

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

3 years

PURA

Regulatory Assets And Liabilities [Line Items]

Public utilities, requested return on equity, percentage

8.80%

Customer receiving percentage

50%

Rate Increase

$ 23,000,000

PURA | Year 1

Regulatory Assets And Liabilities [Line Items]

Public utilities, approved revenue increase

$ 91,000,000

PURA | Year 2

Regulatory Assets And Liabilities [Line Items]

Public utilities, approved revenue increase

20,000,000

PURA | Year 3

Regulatory Assets And Liabilities [Line Items]

Public utilities, approved revenue increase

19,000,000

PURA | Max.

Regulatory Assets And Liabilities [Line Items]

Average increase in base distribution rate, percentage

6.60%

PURA | Min.

Regulatory Assets And Liabilities [Line Items]

Average increase in customer bills, percentage

2%

Central Maine Power

Regulatory Assets And Liabilities [Line Items]

Public utilities, approved return on equity

9.35%

Equity ratio

50%

Equity ratio for earnings sharing

50%

Public utilities, earnings sharing percentage calculation basis

1%

Public utilities, approved revenue increase

$ 16,750,000

Maximum penalty per year for failure to meet specified service quality indicator target

$ 8,800,000

Deferred income tax recovery period

32 years 6 months

NYSEG | Super Storm Costs

Regulatory Assets And Liabilities [Line Items]

Regulatory assets

$ 52,300,000

NYSEG | Non-Super Storm Costs

Regulatory Assets And Liabilities [Line Items]

Regulatory assets

$ 96,600,000

Regulatory items amortization period

7 years

NYSEG | Electricity

Regulatory Assets And Liabilities [Line Items]

Public utilities, requested return on equity, percentage

9.20%

Customer receiving percentage

48%

Total distribution vegetation management spending

$ 66,000,000

Routine distribution vegetation management spending

34,000,000

Planned spending for vegetation management Reclamation Program

21,000,000

Distribution vegetation management spending for Danger Tree program

11,000,000

Amount of annual RAM recovery/return

29,400,000

Public utilities, recovery of Major Storm costs

371,000,000

Public utilities, Storm annual rate allowance, year 1

31,500,000

Public utilities, Storm annual rate allowance, year 2

41,500,000

Public utilities, Storm annual rate allowance, year 3

46,500,000

NYSEG | Gas

Regulatory Assets And Liabilities [Line Items]

Public utilities, requested return on equity, percentage

9.20%

Customer receiving percentage

48%

Amount of annual RAM recovery/return

5,800,000

NYSEG | Year 1 | Electricity

Regulatory Assets And Liabilities [Line Items]

Rate Increase

137,000,000

NYSEG | Year 1 | Gas

Regulatory Assets And Liabilities [Line Items]

Rate Increase

12,000,000

NYSEG | Year 2 | Electricity

Regulatory Assets And Liabilities [Line Items]

Rate Increase

161,000,000

NYSEG | Year 2 | Gas

Regulatory Assets And Liabilities [Line Items]

Rate Increase

12,000,000

NYSEG | Year 3 | Electricity

Regulatory Assets And Liabilities [Line Items]

Rate Increase

201,000,000

NYSEG | Year 3 | Gas

Regulatory Assets And Liabilities [Line Items]

Rate Increase

13,000,000

RG&E | Non-Super Storm Costs

Regulatory Assets And Liabilities [Line Items]

Regulatory assets

$ 19,600,000

Regulatory items amortization period

2 years

RG&E | Electricity

Regulatory Assets And Liabilities [Line Items]

Public utilities, requested return on equity, percentage

9.20%

Customer receiving percentage

48%

Total distribution vegetation management spending

$ 10,700,000

Routine distribution vegetation management spending

9,000,000

Distribution vegetation management spending for Danger Tree program

1,700,000

Amount of annual RAM recovery/return

15,000,000

Public utilities, recovery of Major Storm costs

54,600,000

Public utilities, Storm annual rate allowance, year 1

4,500,000

Public utilities, Storm annual rate allowance, year 2

6,000,000

Public utilities, Storm annual rate allowance, year 3

7,600,000

RG&E | Gas

Regulatory Assets And Liabilities [Line Items]

Public utilities, requested return on equity, percentage

9.20%

Customer receiving percentage

48%

Amount of annual RAM recovery/return

5,400,000

RG&E | Year 1 | Electricity

Regulatory Assets And Liabilities [Line Items]

Rate Increase

51,000,000

RG&E | Year 1 | Gas

Regulatory Assets And Liabilities [Line Items]

Rate Increase

18,000,000

RG&E | Year 2 | Electricity

Regulatory Assets And Liabilities [Line Items]

Rate Increase

57,000,000

RG&E | Year 2 | Gas

Regulatory Assets And Liabilities [Line Items]

Rate Increase

20,000,000

RG&E | Year 3 | Electricity

Regulatory Assets And Liabilities [Line Items]

Rate Increase

65,000,000

RG&E | Year 3 | Gas

Regulatory Assets And Liabilities [Line Items]

Rate Increase

22,000,000

NYSEG and RG&E

Regulatory Assets And Liabilities [Line Items]

Percentage of customers' portion of earnings above sharing threshold deferred To reduce outstanding regulatory asset deferral balances

100%

100%

Percentage of service provider's portion used to reduce outstanding storm-related regulatory asset deferral balance

50%

50%

Amount of bill credit if miss scheduled appointment per residential customer

$ 35

Amount of bill credit, period within bill issuance date

45 days

Amount of additional bill credit

$ 10

Amount of bill credit, period in excess of stack bill credits applied

45 days

Capital investment amount projected

$ 634,000,000

NYSEG and RG&E | Economic development

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

3 years

NYSEG and RG&E | Max.

Regulatory Assets And Liabilities [Line Items]

Amount of annual RAM recovery/return, percentage of delivery revenues

2.45%

NYSEG and RG&E | Min.

Regulatory Assets And Liabilities [Line Items]

Amount of annual RAM recovery/return, percentage of delivery revenues

2%

United Illuminating Company (UI)

Regulatory Assets And Liabilities [Line Items]

ROE reduction

0.15%

United Illuminating Company (UI) | PURA

Regulatory Assets And Liabilities [Line Items]

Public utilities, approved return on equity

8.63%

9.10%

Equity ratio

50%

50%

New distribution rate schedule, period

3 years

Public utilities regulatory authority distribution rate

50%

Approved debt capital structure, percentage

50%

United Illuminating Company (UI) | PURA | Year 1 | Rate Change Levelization

Regulatory Assets And Liabilities [Line Items]

Public utilities, approved revenue increase

$ 54,000,000

SCG | PURA

Regulatory Assets And Liabilities [Line Items]

Public utilities, approved return on equity

9.25%

Equity ratio

52%

Connecticut Natural Gas Corporation (CNG) | PURA

Regulatory Assets And Liabilities [Line Items]

Percentage of return on equity

9.30%

Equity ratio, year one

54%

Equity ratio, year two

54.50%

Equity ratio, year three

55%

BGC

Regulatory Assets And Liabilities [Line Items]

Public utilities, requested return on equity, percentage

9.70%

Customer receiving percentage

54%

Rate Increase

$ 5,600,000

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Rate Increases and Delivery Rate Percentages (Details) $ in Millions	Jun. 14, 2023 USD ($)
NYSEG | Year 1 | Electricity
Regulatory Liabilities [Line Items]
Rate Increase	$ 137
Delivery Rate %	14.40%
Total Rate %	6.60%
NYSEG | Year 1 | Gas
Regulatory Liabilities [Line Items]
Rate Increase	$ 12
Delivery Rate %	5.50%
Total Rate %	2%
NYSEG | Year 2 | Electricity
Regulatory Liabilities [Line Items]
Rate Increase	$ 161
Delivery Rate %	14.70%
Total Rate %	7.30%
NYSEG | Year 2 | Gas
Regulatory Liabilities [Line Items]
Rate Increase	$ 12
Delivery Rate %	5.50%
Total Rate %	2%
NYSEG | Year 3 | Electricity
Regulatory Liabilities [Line Items]
Rate Increase	$ 201
Delivery Rate %	15.10%
Total Rate %	8.20%
NYSEG | Year 3 | Gas
Regulatory Liabilities [Line Items]
Rate Increase	$ 13
Delivery Rate %	5.50%
Total Rate %	2.10%
RG&E | Year 1 | Electricity
Regulatory Liabilities [Line Items]
Rate Increase	$ 51
Delivery Rate %	10%
Total Rate %	5%
RG&E | Year 1 | Gas
Regulatory Liabilities [Line Items]
Rate Increase	$ 18
Delivery Rate %	9.70%
Total Rate %	3.40%
RG&E | Year 2 | Electricity
Regulatory Liabilities [Line Items]
Rate Increase	$ 57
Delivery Rate %	10.10%
Total Rate %	5.30%
RG&E | Year 2 | Gas
Regulatory Liabilities [Line Items]
Rate Increase	$ 20
Delivery Rate %	9.80%
Total Rate %	3.60%
RG&E | Year 3 | Electricity
Regulatory Liabilities [Line Items]
Rate Increase	$ 65
Delivery Rate %	10.20%
Total Rate %	5.70%
RG&E | Year 3 | Gas
Regulatory Liabilities [Line Items]
Rate Increase	$ 22
Delivery Rate %	9.80%
Total Rate %	3.90%

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Earnings Sharing Mechanism (ESM) (Details)	Jun. 14, 2023
No Sharing
Regulatory Liabilities [Line Items]
Public utilities, requested return on equity, percentage	9.70%
50% / 50%
Regulatory Liabilities [Line Items]
ESM, shareholders percentage	50%
ESM, customers percentage	50%
50% / 50% | Min.
Regulatory Liabilities [Line Items]
Public utilities, requested return on equity, percentage	9.70%
50% / 50% | Max.
Regulatory Liabilities [Line Items]
Public utilities, requested return on equity, percentage	10.20%
75% / 25%
Regulatory Liabilities [Line Items]
ESM, shareholders percentage	25%
ESM, customers percentage	75%
75% / 25% | Min.
Regulatory Liabilities [Line Items]
Public utilities, requested return on equity, percentage	10.20%
75% / 25% | Max.
Regulatory Liabilities [Line Items]
Public utilities, requested return on equity, percentage	10.70%
90% / 10%
Regulatory Liabilities [Line Items]
Public utilities, requested return on equity, percentage	10.70%
ESM, shareholders percentage	10%
ESM, customers percentage	90%

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Total regulatory assets	$ 3,057	$ 2,768
Less: current portion	570	447
Total non-current regulatory assets	2,487	2,321
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	362	365
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	38	93
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	767	671
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	51	41
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	59	52
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	2	11
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	43	56
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	33	33
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	0	1
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	11	56
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	236	248
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	59	64
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	19	19
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	545	492
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	132	137
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	20
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	59	55
COVID-19 cost recovery and late payment surcharge
Regulatory Assets [Line Items]
Total regulatory assets	12	17
Low income arrears forgiveness
Regulatory Assets [Line Items]
Total regulatory assets	61	31
Excess generation service charge
Regulatory Assets [Line Items]
Total regulatory assets	33	24
System Expansion
Regulatory Assets [Line Items]
Total regulatory assets	23	21
Non-bypassable charge
Regulatory Assets [Line Items]
Total regulatory assets	86	14
Hedges losses
Regulatory Assets [Line Items]
Total regulatory assets	14	13
Energy Efficiency Programs
Regulatory Assets [Line Items]
Total regulatory assets	22	13
Rate change levelization
Regulatory Assets [Line Items]
Total regulatory assets	18	0
Electric supply reconciliation
Regulatory Assets [Line Items]
Total regulatory assets	13	19
Value of distributed energy resources
Regulatory Assets [Line Items]
Total regulatory assets	48	36
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 291	$ 166

Regulatory Assets and Liabili_7

Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,073	$ 3,269
Less: current portion	235	354
Total non-current regulatory liabilities	2,838	2,915
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	30
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	15
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	108	117
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	9
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1	3
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,198	1,232
Rate Change Levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	5	25
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	13
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,150	1,178
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	20
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	10	16
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	3
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	17
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	11
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	32
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	37	36
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	31	31
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	8	10
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	21	22
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	18
Earning sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	13
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	17
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	18
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	27
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	1
Non by-passable charges
Regulatory Liabilities [Line Items]
Total regulatory liabilities	8	76
Transmission revenue reconciliation mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	56	75
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 246	$ 204

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Restricted cash	$ 419	$ 413
Fair value of debt	9,091	7,991
Restricted Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 9	$ 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	Sep. 30, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	$ 42	$ 48
Netting adjustment	(106)	(222)
Derivative assets	240	200
Netting adjustment	192	394
Derivative liabilities	(214)	(297)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(97)	(177)
Derivative assets	52	80
Netting adjustment	163	364
Derivative liabilities	(48)	(125)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(9)	(45)
Derivative assets	5	3
Netting adjustment	29	30
Derivative liabilities	0	0
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	1	1
Netting adjustment	0	0
Derivative liabilities	(44)	(57)
Derivative financial instruments - Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	182	116
Netting adjustment	0	0
Derivative liabilities	(122)	(115)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	27	35
Derivative assets, before netting	29	38
Derivative liabilities, before netting	(42)	(50)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	29	37
Derivative liabilities, before netting	(30)	(46)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	1
Derivative liabilities, before netting	(12)	(4)
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	0
Derivative liabilities, before netting	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	15	13
Derivative assets, before netting	232	218
Derivative liabilities, before netting	(257)	(491)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	36	55
Derivative liabilities, before netting	(119)	(350)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	14	47
Derivative liabilities, before netting	(16)	(26)
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	182	116
Derivative liabilities, before netting	(122)	(115)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	0	0
Derivative assets, before netting	85	166
Derivative liabilities, before netting	(107)	(150)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	84	165
Derivative liabilities, before netting	(62)	(93)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	(1)	0
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	1	1
Derivative liabilities, before netting	(44)	(57)
Level 3 | Derivative financial instruments - Other
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

Fair Value of Financial Instr_5

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value Beginning of Period,	$ 23	$ (151)	$ 16	$ (69)
Gains recognized in operating revenues	0	17	8	69
(Losses) recognized in operating revenues	0	(17)	(12)	(79)
Total losses recognized in operating revenues	0	0	(4)	(10)
Gains recognized in OCI	0	(1)	8	2
(Losses) recognized in OCI	(9)	(13)	(10)	(105)
Total (losses) gains recognized in OCI	(9)	(14)	(2)	(103)
Net change recognized in regulatory assets and liabilities	5	5	13	14
Purchases	(2)	(4)	29	(5)
Settlements	(39)	(2)	(74)	7
Fair Value as of September 30,	(22)	(166)	(22)	(166)
Losses for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$ 0	$ 0	$ (4)	$ (10)

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Level 3 Fair Value Measurement (Details) - Measurement Input, Commodity Forward Price	Sep. 30, 2023 $ / MMBTU $ / MWh
NYMEX | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	4.46
NYMEX | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	9.86
NYMEX | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	1.99
AECO | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	3.13
AECO | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	10.80
AECO | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	1
Ameren | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	53.89
Ameren | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	225.62
Ameren | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	20.92
COB | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	81.12
COB | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	400.10
COB | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	10.85
ComEd | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	49.05
ComEd | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	222.49
ComEd | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	16.77
ERCOT S hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	50.40
ERCOT S hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	320.63
ERCOT S hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	16.85
Mid C | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	78.25
Mid C | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	400.10
Mid C | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	7.85
AEP-DAYTON hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	54.66
AEP-DAYTON hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	229.75
AEP-DAYTON hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	22.50
PJM W hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	57.33
PJM W hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	227.60
PJM W hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	21.61

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Additional Quantitative Information about Level 3 Fair Value Measurements of CfDs (Details) - Level 3 - Contracts for differences	Sep. 30, 2023 $ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0072
Min. | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0413
Min. | Forward pricing
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	2
Max. | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0074
Max. | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0480
Max. | Forward pricing
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	2.61

Derivative Instruments and He_3

Derivative Instruments and Hedging - Schedule of Derivative Positions including Subject to Master Netting Agreements and Location of Net Derivative Position on Condensed Consolidated Balance Sheets (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 240	$ 200
Derivative liabilities	(214)	(297)
Cash collateral (payable) receivable, Asset	(60)	(97)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	1	0
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	1	0
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	26	30
Derivative liabilities	(25)	(30)
Derivative Asset	1	0
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	1	1
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	1	1
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	8
Derivative liabilities	(3)	(7)
Derivative Asset	1	1
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(31)	(28)
Cash collateral (payable) receivable, Liability	15	11
Total derivatives as presented in the balance sheet, Liability	(16)	(17)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	25	30
Derivative liabilities	(56)	(58)
Derivative liabilities	(31)	(28)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative liabilities	0	0
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(27)	(43)
Cash collateral (payable) receivable, Liability	0	2
Total derivatives as presented in the balance sheet, Liability	(27)	(41)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	7
Derivative liabilities	(30)	(50)
Derivative liabilities	(27)	(43)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative liabilities	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	48	60
Cash collateral (payable) receivable, Asset	(1)	0
Total derivatives as presented in the balance sheet, Asset	47	60
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	67	121
Derivative liabilities	(32)	(61)
Derivative Asset	35	60
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	14	0
Derivative liabilities	(1)	0
Derivative Asset	13	0
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	191	139
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	191	139
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	29	63
Derivative liabilities	(12)	(40)
Derivative Asset	17	23
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	175	116
Derivative liabilities	(1)	0
Derivative Asset	174	116
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(76)	(192)
Cash collateral (payable) receivable, Liability	52	105
Total derivatives as presented in the balance sheet, Liability	(24)	(87)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	22	79
Derivative liabilities	(33)	(103)
Derivative liabilities	(11)	(24)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	0
Derivative liabilities	(69)	(168)
Derivative liabilities	(65)	(168)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(45)	(91)
Cash collateral (payable) receivable, Liability	20	54
Total derivatives as presented in the balance sheet, Liability	(25)	(37)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	4
Derivative liabilities	(7)	(7)
Derivative liabilities	(3)	(3)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	1
Derivative liabilities	(45)	(89)
Derivative liabilities	$ (42)	$ (88)

Derivative Instruments and He_4

Derivative Instruments and Hedging - Net Notional Volume (Details) MWh in Millions, MMBTU in Millions, $ in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2023 USD ($) MWh MMBTU	Dec. 31, 2022 USD ($) MWh MMBTU
Networks | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	5.2	5.7
Networks | Natural Gas Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	9.4	9.6
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value | $	$ 7	$ (41)
Renewables | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	1	2
Derivative assets (liabilities), fair value | $	$ 57	$ 149
Renewables | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	6	7
Derivative assets (liabilities), fair value | $	$ (70)	$ (200)
Renewables | Natural gas and other fuel purchase contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	17	15
Derivative assets (liabilities), fair value | $	$ 4	$ 2
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	4	6
Derivative assets (liabilities), fair value | $	$ 16	$ 8
Renewables | Basis swaps – purchases | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	23	22
Renewables | Basis swaps – purchases | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	1	0

Derivative Instruments and He_5

Derivative Instruments and Hedging - Schedule of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Derivative liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain (loss) on derivatives	$ 5	$ 5	$ 13	$ 14
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	2		2		$ 9
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	14	(49)	85	(113)
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	12		12		$ 4
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 0	$ 0	$ 6	$ (9)

Derivative Instruments and He_6

Derivative Instruments and Hedging - Narrative (Details) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023 USD ($) instrument	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($) instrument	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)	Sep. 15, 2021 USD ($)	Jul. 15, 2021 USD ($)	May 27, 2021 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 3,057		$ 3,057		$ 2,768
Regulatory liabilities	3,073		3,073		3,269
Derivative asset, noncurrent	192		192		140
Derivative asset, current	48		48		60
Derivative liability	214		214		297
Aggregate fair value of additional collateral	21		21
Cash collateral pledged	60		60		97
Collateral already posted	$ 14		$ 14
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative instruments | instrument	2		2
Derivative liability	$ 44		$ 44		57
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(2)	$ (2)	(7)	$ (7)
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0	0
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	31		31		38
Cash Flow Hedging | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months			(9)
Fair Value Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability							$ 750
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0	2
Networks | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0	0
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(1)	(1)	(3)	(3)
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months			(4)
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	40		40		43
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	41	7	200	4
Renewables | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	58	$ 40	182	$ 167
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months			(65)
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount						$ 956		$ 935
Derivative asset, noncurrent	182		182		116
Derivative asset, current	182		$ 182		116
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers			20%
Gross derivative asset	1		$ 1		1
Regulatory assets	42		42		56
Gross amounts of recognized liabilities	44		44		57
Regulatory liabilities	0		$ 0		0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers			80%
Gross derivative asset	0		$ 0		0
Gross amounts of recognized liabilities	$ 42		$ 42		$ 55

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging Relationships (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest expense	$ 107	$ 76	$ 301	$ 226
Purchased power, natural gas and fuel used	482	535	1,844	1,716
Operating Revenues	1,974	1,838	6,027	5,765
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	0	2
Loss Reclassified from Accumulated OCI into Income	1	0	3	0
Operating Revenues	1,587	1,546	4,935	4,944
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	41	7	200	4
Loss Reclassified from Accumulated OCI into Income	52	22	136	41
Operating Revenues	387	293	1,092	821
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	0	0
Interest rate contracts | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	2	2	7	7
Interest rate contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	0	0
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	1	1	3	3
Interest expense	107	76	301	226
Interest rate contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	58	40	182	167
Interest rate contracts | Renewables | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	0	0	0	0
Interest expense	107	76	301	226
Commodity contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0	0	2
Commodity contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	0	(1)	0	(3)
Purchased power, natural gas and fuel used	482		1,844	1,716
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	(17)	(33)	18	(163)
Commodity contracts | Renewables | Operating revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	52	22	136	41
Operating Revenues	$ 1,974	$ 1,838	$ 6,027	$ 5,765

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 7	$ (41)
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	16	8
Long | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	57	149
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	4	2
Short | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (70)	$ (200)

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating Revenues	$ 1,974	$ 1,838	$ 6,027	$ 5,765
Utilities operating expense, purchased power	$ 482	$ 535	$ 1,844	$ 1,716
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating Revenues, Utilities operating expense, purchased power	Operating Revenues, Utilities operating expense, purchased power	Operating Revenues, Utilities operating expense, purchased power	Operating Revenues, Utilities operating expense, purchased power
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating Revenues	$ 387	$ 293	$ 1,092	$ 821
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(25)	(7)	(6)	(2)
Renewables | Trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(19)	(4)	9	2
Renewables | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(5)		(6)
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	2	(16)	(13)	(15)
Renewables | Non-trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	14	(21)	57	(31)
Renewables | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	14		39
Renewables | Operating revenues | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (25)	$ (7)	$ (6)	$ (2)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating Revenues	Operating Revenues	Operating Revenues	Operating Revenues
Renewables | Operating revenues | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (1)	$ 1	$ (9)	$ 2
Renewables | Operating revenues | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net		(3)		(5)
Renewables | Operating revenues | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	(1)	0	(1)
Renewables | Operating revenues | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 23	$ (21)	96	(93)
Operating Revenues			$ 6,027	$ 5,765
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating Revenues	Operating Revenues	Operating Revenues	Operating Revenues
Renewables | Operating revenues | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (4)	$ 3	$ (5)	$ 3
Renewables | Operating revenues | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net		1		(40)
Renewables | Operating revenues | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(1)	(4)	5	(25)
Renewables | Purchased power, natural gas and fuel used | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 0	$ 0	$ 0	$ 0
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Utilities operating expense, purchased power	Utilities operating expense, purchased power	Utilities operating expense, purchased power	Utilities operating expense, purchased power
Renewables | Purchased power, natural gas and fuel used | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 0	$ 0	$ 0	$ 0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net		0		0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0	0	0
Renewables | Purchased power, natural gas and fuel used | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (21)	$ 5	(109)	78
Utilities operating expense, purchased power			$ 1,844	$ 1,716
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Utilities operating expense, purchased power	Utilities operating expense, purchased power	Utilities operating expense, purchased power	Utilities operating expense, purchased power
Renewables | Purchased power, natural gas and fuel used | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (23)	$ 12	$ (79)	$ 65
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net		1		0
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 2	$ (8)	$ (30)	$ 13

Derivative Instruments and H_10

Derivative Instruments and Hedging - Fair Value Hedging Instruments (Details) - Interest Rate Swap - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Recognized in Income Statement	$ 9	$ 3	$ 23	$ 1
Total per Income Statement	107	$ 76	301	$ 226
Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value of hedge	(32)		(32)		$ (29)
Non-current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Fair value of hedge	(88)		(88)		(86)
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	32		32		29
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	$ 88		$ 88		$ 86

Contingencies and Commitments (

Contingencies and Commitments (Details) $ in Millions

1 Months Ended

9 Months Ended

12 Months Ended

Oct. 02, 2023 USD ($)

Jul. 13, 2023 USD ($)

May 21, 2020

May 20, 2020

Nov. 21, 2019 complaint

Jan. 11, 2019 complaint

Mar. 22, 2016

Mar. 03, 2015

Oct. 16, 2014

Sep. 30, 2011

Apr. 30, 2018

Sep. 30, 2023 USD ($)

Dec. 31, 2021 USD ($)

Dec. 31, 2001 plaintiff

Dec. 31, 2022 USD ($)

May 04, 2021 USD ($)

Jan. 04, 2021 USD ($)

Apr. 12, 2016 USD ($)

Loss Contingencies [Line Items]

Refund period term

15 months

Public utilities, approved return on equity

9.88%

Regulatory liabilities

$ 2,838

$ 2,915

Number of claims | complaint

2

Requested existing base return on equity base percentage

10.02%

9.88%

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

3

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

801

Future payments committed

$ 90

NECEC commitment, payment during period

$ 9

Complaint II

Loss Contingencies [Line Items]

Regulatory liabilities

29

Complaint III

Loss Contingencies [Line Items]

Regulatory liabilities

8

Complaint II and III

Loss Contingencies [Line Items]

Reasonably possible loss, in additional reserve, pre tax

$ 17

California Energy Crisis Litigation

Loss Contingencies [Line Items]

Number of plaintiffs | plaintiff

2

Price of the power purchase agreements

$ 259

Requested renewables delay from preliminary proposed ruling period

2 years

Customer Service Invoice Dispute

Loss Contingencies [Line Items]

Litigation settlement, adjustment amount requested

$ 31

Commonwealth Wind and Park City PPAs

Loss Contingencies [Line Items]

Termination payment

$ 48

Commonwealth Wind and Park City PPAs | Subsequent Event

Loss Contingencies [Line Items]

Termination payment

$ 16

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Public utilities, approved return on equity

10.57%

Number of claims | complaint

4

Unfavorable Regulatory Action | Complaint I | Max.

Loss Contingencies [Line Items]

Public utilities, approved return on equity

11.74%

11.74%

Unfavorable Regulatory Action | Complaint II

Loss Contingencies [Line Items]

Public utilities, approved return on equity

9.59%

Refund period

15 months

Unfavorable Regulatory Action | Complaint II | Max.

Loss Contingencies [Line Items]

Public utilities, approved return on equity

10.42%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Public utilities, approved return on equity

10.90%

Refund period

15 months

Unfavorable Regulatory Action | Complaint III | Max.

Loss Contingencies [Line Items]

Public utilities, approved return on equity

12.19%

Before Amendment

Loss Contingencies [Line Items]

Public utilities, requested return on equity, percentage

11.14%

Environmental Liabilities (Deta

Environmental Liabilities (Details)		9 Months Ended	12 Months Ended		86 Months Ended
	Apr. 18, 2023	Sep. 30, 2023 USD ($) site	Dec. 31, 2011 site	Dec. 31, 2008 site	Sep. 30, 2023 USD ($)	Dec. 31, 2022 USD ($)	Aug. 04, 2016 USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		24
Number of additional sites with liability recorded		10
Number of sites where gas was manufactured in the past		53
Number of sites for which we have entered into consent orders to investigate and remediate		41
Accrual related to investigation and remediation | $		$ 257,000,000			$ 257,000,000	$ 289,000,000
Accrual related to investigation and remediation, amount recorded to date | $					35,000,000
FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute			16
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		$ 20,000,000			20,000,000	19,000,000	$ 30,000,000
Environmental loss contingencies, period requiring response to provide alternative remediation proposals	30 days
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		16
Number of sites where gas was manufactured in the past		6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		2
Number of sites where gas was manufactured in the past		0
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		0
Number of sites with liability recorded		6
Number of sites where gas was manufactured in the past		2
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations		5
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $		$ 6,000,000			6,000,000
New York Voluntary Cleanup Program
Environmental Exit Cost [Line Items]
Number of sits note expected to incur additional liabilities		18
Number of sites where gas was manufactured in the past		39
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $		$ 10,000,000			10,000,000
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 | $		$ 23,000,000			23,000,000
Sites With Individual NYSDEC Orders Of Consent
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past		2
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past		2
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		$ 112,000,000			112,000,000	$ 112,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		129,000,000			129,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		225,000,000			225,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		0			0
MGP Sites | FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute				2
NYSEG | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		8,000,000			8,000,000
RG&E | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $		$ 6,000,000			$ 6,000,000

Post-Retirement and Similar O_3

Post-Retirement and Similar Obligations - Narrative (Details) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2023 USD ($)	Sep. 30, 2023 USD ($)
Retirement Benefits [Abstract]
Defined benefit, pension contributions	$ 15	$ 15
Employer contributions for remainder of fiscal year	$ 0	$ 0

Post-Retirement and Similar O_4

Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 1	$ 6	$ 4	$ 21
Interest cost	30	10	91	27
Expected return on plan assets	(36)	(20)	(109)	(71)
Amortization of prior service costs	0	0	1	1
Amortization of actuarial loss	1	11	2	40
Curtailment Charge	0	(1)		(24)
Net Periodic Benefit Cost	(4)	6	(11)	(6)
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	1	1	2
Interest cost	3	3	10	8
Expected return on plan assets	(1)	(1)	(4)	(4)
Amortization of prior service costs	0	(1)	0	(1)
Amortization of actuarial loss	(3)	(1)	(9)	(3)
Net Periodic Benefit Cost	$ (1)	$ 1	$ (2)	$ 2

Equity - Narrative (Details)

Equity - Narrative (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Class of Stock [Line Items]
Common stock, held in trust (in shares)	103,889		103,889		108,188
Release of common stock held in trust (in shares)	0	0	4,299	0
Treasury shares (in shares)	997,983		997,983
Repurchases of common stock	$ 47		$ 47		$ 47
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent	81.50%		81.50%
Convertible Preferred Stock
Class of Stock [Line Items]
Convertible preferred stock, shares outstanding (in shares)	0		0		0

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Loss (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	$ 20,443	$ 20,386	$ 20,342	$ 19,961
Other comprehensive income (loss), net of tax	69	9	175	46
Balance, end of period	20,375	20,334	20,375	20,334
Gain for defined benefit plans, income tax expense	0	0	0	3
Amortization of pension cost, income tax expense	0	0	1	0
Unrealized (loss) gain from equity method investment, income tax expense (benefit)	0	(5)	1	(1)
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, income tax expense	11	1	22	1
Reclassification to net income of losses on cash flow hedges, taxes	15	7	39	13
Gain on defined benefit plans, net of income tax expense of $0 and $0 for 2023 and 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income (loss), net of tax	0	0	0	8
Amortization of pension cost, net of income tax expense of $0 and $0 for 2023 and 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income (loss), net of tax	0	0	2	1
Net gain (loss) on pension plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(18)	(29)	(20)	(38)
Other comprehensive income (loss), net of tax	0	0	2	9
Balance, end of period	(18)	(29)	(18)	(29)
Unrealized (loss) gain from equity method investment, net of income tax expense (benefit) of $0 for 2023 and $(5) for 2022 (a)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	18	2	13	(9)
Other comprehensive income (loss), net of tax	(1)	(13)	4	(2)
Balance, end of period	17	(11)	17	(11)
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $11 for 2023 and $1 for 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(163)	(194)	(195)	(194)
Other comprehensive income (loss), net of tax	30	3	62	3
Balance, end of period	(133)	(191)	(133)	(191)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $15 for 2023 and $7 for 2022 (b)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	89	(15)	22	(32)
Other comprehensive income (loss), net of tax	40	19	107	36
Balance, end of period	129	4	129	4
(Loss) Gain on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(74)	(209)	(173)	(226)
Other comprehensive income (loss), net of tax	70	22	169	39
Balance, end of period	(4)	(187)	(4)	(187)
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(74)	(236)	(180)	(273)
Other comprehensive income (loss), net of tax	69	9	175	46
Balance, end of period	$ (5)	$ (227)	$ (5)	$ (227)

Earnings Per Share - Calculatio

Earnings Per Share - Calculations of Basic and Diluted Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Numerator:
Net income attributable to Avangrid, Basic	$ 59	$ 105	$ 389	$ 734
Net income attributable to Avangrid, Diluted	$ 59	$ 105	$ 389	$ 734
Denominator:
Weighted average number of shares outstanding - basic (in shares)	386,869,341	386,736,774	386,788,279	386,724,035
Weighted average number of shares outstanding - diluted (in shares)	387,322,281	387,280,621	387,122,498	387,200,882
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic (in dollars per share)	$ 0.15	$ 0.27	$ 1	$ 1.90
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.15	$ 0.27	$ 1	$ 1.90

Segment Information - Narrative

Segment Information - Narrative (Details)	9 Months Ended
	Sep. 30, 2023 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	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Dec. 31, 2022
Segment Reporting Information [Line Items]
Revenues	$ 1,974	$ 1,838	$ 6,027	$ 5,765
Depreciation and amortization	303	279	868	811
Operating income (loss)	89	112	480	635
Earnings (losses) from equity method investments	(1)	2	5	261
Interest expense, net of capitalization	107	76	301	226
Income tax expense (benefit)	(8)	(50)	(17)	14
Adjusted net income (loss)	105	122	434	749
Capital expenditures			2,078	1,940
Property, plant and equipment	32,068		32,068		$ 30,994
Equity method investments	514		514		437
Total assets	42,386		42,386		41,123
Other
Segment Reporting Information [Line Items]
Revenues	0	(1)	0	0
Depreciation and amortization	5	0	6	1
Operating income (loss)	0	(2)	(5)	(8)
Earnings (losses) from equity method investments	0	0	0	0
Interest expense, net of capitalization	25	14	70	47
Income tax expense (benefit)	7	(7)	0	(16)
Adjusted net income (loss)	(42)	(13)	(100)	(44)
Capital expenditures			22	8
Property, plant and equipment	12		12		17
Equity method investments	0		0		0
Total assets	(701)		(701)		(499)
Revenue - intersegment
Segment Reporting Information [Line Items]
Revenues	0	0	(1)	(1)
Networks
Segment Reporting Information [Line Items]
Revenues	1,587	1,546	4,935	4,944
Networks | Revenue - intersegment
Segment Reporting Information [Line Items]
Revenues	0	0	1	1
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenues	1,587	1,546	4,936	4,945
Depreciation and amortization	175	166	524	491
Operating income (loss)	134	141	531	660
Earnings (losses) from equity method investments	3	3	11	8
Interest expense, net of capitalization	76	60	215	171
Income tax expense (benefit)	12	13	70	65
Adjusted net income (loss)	92	89	364	471
Capital expenditures			1,551	1,315
Property, plant and equipment	21,017		21,017		20,027
Equity method investments	187		187		171
Total assets	29,161		29,161		28,069
Renewables
Segment Reporting Information [Line Items]
Revenues	387	293	1,092	821
Renewables | Revenue - intersegment
Segment Reporting Information [Line Items]
Revenues	0	0	0	0
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenues	387	293	1,092	821
Depreciation and amortization	123	113	338	319
Operating income (loss)	(45)	(27)	(46)	(17)
Earnings (losses) from equity method investments	(4)	(1)	(6)	253
Interest expense, net of capitalization	6	2	16	8
Income tax expense (benefit)	(27)	(56)	(87)	(35)
Adjusted net income (loss)	55	$ 45	170	322
Capital expenditures			505	$ 617
Property, plant and equipment	11,039		11,039		10,950
Equity method investments	327		327		266
Total assets	$ 13,926		$ 13,926		$ 13,553

Segment Information - Reconcili

Segment Information - Reconciliation of Adjusted Net Income to Net Income (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 105	$ 122	$ 434	$ 749
Adjustments:
Mark-to-market earnings - Renewables	(23)	(22)	(19)	(17)
Impact of COVED -19	0	0	0	(2)
Merger costs	(1)	(1)	(2)	(3)
Offshore contract provisions	(40)	0	(40)	0
Income tax impact of adjustments	17	6	16	6
Net Income Attributable to Avangrid, Inc.	$ 59	$ 105	$ 389	$ 734

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Iberdrola, S.A. | Sales To
Related Party Transaction [Line Items]
Related party transaction, amount	$ 0	$ 0	$ 0	$ 0
Iberdrola, S.A. | Purchases From
Related Party Transaction [Line Items]
Related party transaction, amount	(8)	(12)	(34)	(34)
Iberdrola Renovables Energía, S.L. | Sales To
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	0	0
Iberdrola Renovables Energía, S.L. | Purchases From
Related Party Transaction [Line Items]
Related party transaction, amount	(2)	(2)	(5)	(7)
Iberdrola Financiación, S.A.U. | Sales To
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	0	0
Iberdrola Financiación, S.A.U. | Purchases From
Related Party Transaction [Line Items]
Related party transaction, amount	(12)	(3)	(20)	(8)
Vineyard Wind | Sales To
Related Party Transaction [Line Items]
Related party transaction, amount	2	2	6	5
Vineyard Wind | Purchases From
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	0	0
Other | Sales To
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	0	0
Other | Purchases From
Related Party Transaction [Line Items]
Related party transaction, amount	$ (1)	$ (1)	$ (1)	$ (2)

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - Related Party - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Related Party Transaction [Line Items]
Owed By	$ 5	$ 5
Owed To	(47)	(39)
Iberdrola
Related Party Transaction [Line Items]
Owed By	0	1
Owed To	(34)	(29)
Iberdrola Financiación, S.A.U.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(807)	(9)
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	4	3
Owed To	(8)	(8)
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(6)	(2)
Other
Related Party Transaction [Line Items]
Owed By	4	4
Owed To	$ (6)	$ (1)

Related Party Transactions - Na

Related Party Transactions - Narrative (Details) - Related Party - USD ($)	9 Months Ended
	Sep. 30, 2023	Jul. 19, 2023	Jul. 03, 2023	Jun. 18, 2023	Dec. 31, 2022
Related Party Transaction [Line Items]
Notes payable	$ 6,000,000				$ 2,000,000
Deposit balance	0				0
Iberdrola Solutions, LLC
Related Party Transaction [Line Items]
Notes payable	$ 6,000,000				2,000,000
Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity		$ 750,000,000		$ 500,000,000
Credit facility, commitment fee percentage	0.225%
Credit facility outstanding amount	$ 0				$ 0
Iberdrola Financiación, S.A.U. | Term Loan Maturing July 13, 2033
Related Party Transaction [Line Items]
Debt aggregate principal amount		$ 800,000,000
Fixed interest rate		5.45%
Iberdrola Financiación, S.A.U. | Deposit Agreement
Related Party Transaction [Line Items]
Debt aggregate principal amount			$ 250,000,000
Fixed interest rate			5.50%

Other Financial Statement Ite_3

Other Financial Statement Items - Accounts Receivable and Unbilled Revenue, Net (Details) - Nonrelated Party - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Supplemental Balance Sheet Information [Line Items]
Trade receivables and unbilled revenues	$ 1,580	$ 1,892
Allowance for credit losses	(163)	(155)
Accounts receivable and unbilled revenues, net	$ 1,417	$ 1,737

Other Financial Statement Ite_4

Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 163	$ 143	$ 163	$ 143
Current period provision	45	45	95	68
Write-off as uncollectible	(37)	(44)	(87)	(76)
Ending balance	$ 155	$ 142	$ 155	$ 151

Other Financial Statement Ite_5

Other Financial Statement Items - Narrative (Details) - USD ($)	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022	Oct. 02, 2023	Aug. 03, 2023	Jul. 03, 2023	Jun. 30, 2023	Dec. 31, 2022	Jun. 30, 2022	Dec. 31, 2021
Supplemental Balance Sheet Information [Line Items]
Allowance for doubtful accounts, deferred payment arrangement	$ 163,000,000	$ 143,000,000	$ 163,000,000	$ 143,000,000				$ 155,000,000	$ 155,000,000	$ 142,000,000	$ 151,000,000
Provision (recovery) for credit loss, accounts receivable	45,000,000	45,000,000	95,000,000	68,000,000
Prepaid other taxes	190,000,000		190,000,000						136,000,000
Accrued liabilities for property, plant and equipment additions	469,000,000	200,000,000	469,000,000	200,000,000
Commercial paper	954,000,000		954,000,000						397,000,000
Advances received	$ 325,000,000		$ 325,000,000						$ 271,000,000
Commercial Paper
Supplemental Balance Sheet Information [Line Items]
Weighted-average interest rate	5.52%		5.52%						4.66%
Unsecured Notes Maturing In 2034 | Unsecured Debt
Supplemental Balance Sheet Information [Line Items]
Debt aggregate principal amount							$ 100,000,000
Fixed interest rate							4%
Unsecured Notes Maturing In 2028 | Unsecured Debt
Supplemental Balance Sheet Information [Line Items]
Debt aggregate principal amount						$ 350,000,000
Fixed interest rate						5.65%
Unsecured Notes Maturing In 2033 | Unsecured Debt
Supplemental Balance Sheet Information [Line Items]
Debt aggregate principal amount						$ 400,000,000
Fixed interest rate						5.85%
Unsecured Notes Maturing In 2033 | Unsecured Debt | Subsequent Event
Supplemental Balance Sheet Information [Line Items]
Debt aggregate principal amount					$ 65,000,000
Fixed interest rate					4.50%
Supplier Financing Arrangements
Supplemental Balance Sheet Information [Line Items]
Weighted-average interest rate									5.48%
Short-term debt	$ 0		$ 0						$ 171,000,000
Deferred Payment Arrangements
Supplemental Balance Sheet Information [Line Items]
Accounts receivable	124,000,000		124,000,000						102,000,000
Allowance for doubtful accounts, deferred payment arrangement	48,000,000		48,000,000						$ 42,000,000
Provision (recovery) for credit loss, accounts receivable	$ 1,000,000	$ (11,000,000)	$ 6,000,000	$ (5,000,000)

Other Financial Statement Ite_6

Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Sep. 30, 2023	Dec. 31, 2022
Property, plant and equipment
Accumulated depreciation	$ 12,278	$ 11,542
Intangible assets
Accumulated amortization	$ 347	$ 331

Income Tax Expense (Details)

Income Tax Expense (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Income Tax Disclosure [Abstract]
Effective tax rate	(34.80%)	(89.30%)	(6.10%)	2%
Production tax credits transfer agreement, cash received			$ 62

Stock-Based Compensation Expe_2

Stock-Based Compensation Expense (Details) $ / shares in Units, $ in Millions			1 Months Ended								3 Months Ended		9 Months Ended
	Jul. 20, 2023 installment shares	Apr. 12, 2023 installment shares	Aug. 31, 2023 USD ($)	Jul. 31, 2023 shares	Mar. 31, 2023 installment shares	Feb. 28, 2023 USD ($) installment shares	Jan. 31, 2023 shares	Jun. 30, 2022 installment $ / shares shares	Feb. 28, 2022 installment shares	Mar. 31, 2021 installment $ / shares shares	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Sep. 30, 2023 USD ($)	Sep. 30, 2022 USD ($)	Dec. 31, 2022 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $											$ 4	$ 2	$ 11	$ 10
Performance Shares Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	487,000	487,000			677,752
Number of vesting installments | installment	3	3			3
Number of shares issued (in shares)				125,657
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		5,000
Number of vesting installments | installment								2		1
Number of shares issued (in shares)					3,642		8,690
Grant date fair value (in dollars per share) | $ / shares								$ 47.64		$ 48.83
Phantom Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)						81,000			9,000
Number of vesting installments | installment						3			3
Cash used to settle award | $			$ 0.2			$ 0.2
Share based compensation liability | $											$ 2		$ 2		$ 0

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions		1 Months Ended
	Apr. 29, 2022	Mar. 31, 2023	Sep. 30, 2023	Dec. 31, 2022
Variable Interest Entity [Line Items]
TEF agreement, investment amount received from tax equity investor	$ 14
Assets of variable interest entities (VIEs)			$ 42,386	$ 41,123
Liabilities of variable interest entities (VIEs)			22,011	20,781
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)			2,768	2,853
Liabilities of variable interest entities (VIEs)			$ 179	$ 424
Solis I
Variable Interest Entity [Line Items]
TEF agreement, investment amount received from tax equity investor		$ 61

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Millions	3 Months Ended	12 Months Ended
	Sep. 30, 2023 USD ($)	Dec. 31, 2022 USD ($)	Oct. 24, 2023 USD ($)	Jan. 10, 2022 USD ($)	Dec. 31, 2021 USD ($) a easement	Sep. 15, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 514	$ 437
Vineyard Wind 1, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage	50%			50%
Equity method investment, capital contribution	$ 78
Vineyard Wind 1, LLC | Subsequent Event
Schedule of Equity Method Investments [Line Items]
TEF agreement, amount expected from tax equity investors in installments			$ 1,200
Vineyard Wind Limited Liability Company
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage					50%
Number of easements acquired | easement					2
Equity method investments	$ 87	9
Vineyard Wind Limited Liability Company | Lease Area 501
Schedule of Equity Method Investments [Line Items]
Area of land (in acres) | a					166,886
Vineyard Wind Limited Liability Company | Lease Area 522
Schedule of Equity Method Investments [Line Items]
Area of land (in acres) | 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]
Line of 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

Subsequent Event (Details)

Subsequent Event (Details) - $ / shares		3 Months Ended		9 Months Ended
	Oct. 18, 2023	Sep. 30, 2023	Sep. 30, 2022	Sep. 30, 2023	Sep. 30, 2022
Subsequent Event [Line Items]
Dividends declared (in dollars per share)		$ 0.44	$ 0.44	$ 1.32	$ 1.32
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share)	$ 0.44