Avangrid (AGR) 10-Q 26 Apr 23 2023 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares	3 Months Ended
	Mar. 31, 2023	Apr. 25, 2023
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 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		386,640,918
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	Q1
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
	Mar. 31, 2023	Mar. 31, 2022
Income Statement [Abstract]
Operating Revenues	$ 2,466	$ 2,133
Operating Expenses
Purchased power, natural gas and fuel used	977	741
Operations and maintenance	761	651
Depreciation and amortization	280	261
Taxes other than income taxes	183	178
Total Operating Expenses	2,201	1,831
Operating Income	265	302
Other Income and (Expense)
Other income	25	11
Earnings from equity method investments	2	253
Interest expense, net of capitalization	(95)	(71)
Income Before Income Tax	197	495
Income tax (benefit) expense	(18)	68
Net Income	215	427
Net loss attributable to noncontrolling interests	30	18
Net Income Attributable to Avangrid, Inc.	$ 245	$ 445
Earnings Per Common Share, Basic (in dollars per share)	$ 0.63	$ 1.15
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.63	$ 1.15
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	386,744,996	386,698,132
Diluted (in shares)	387,077,213	387,114,285

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Statement of Comprehensive Income [Abstract]
Net Income	$ 215	$ 427
Other Comprehensive Income (Loss)
Gain for defined benefit plans, net of income taxes of $0 and $3, respectively	0	8
Amortization of pension cost, net of income taxes of $0 and $0, respectively	0	1
Unrealized (loss) gain from equity method investment, net of income taxes of $0 and $5, respectively	(1)	15
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(1) and $(15), respectively	(2)	(39)
Reclassification to net income of loss on cash flow hedges, net of income taxes $18 and $4, respectively	52	11
Other Comprehensive Income (Loss)	49	(4)
Comprehensive Income	264	423
Net loss attributable to noncontrolling interests	30	18
Comprehensive Income Attributable to Avangrid, Inc.	$ 294	$ 441

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, income tax expense (benefit)	$ 0	$ 3
Amortization of pension cost, income tax expense (benefit)	0	0
Unrealized gain from equity method investment, income taxes	0	5
Unrealized loss during the period on derivatives qualifying as cash flow hedges, income taxes	(1)	(15)
Reclassification to net income of loss on cash flow hedges, income taxes	$ 18	$ 4

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Current Assets
Cash and cash equivalents	$ 72	$ 69
Accounts receivable and unbilled revenues, net	1,669	1,737
Accounts receivable from affiliates	2	5
Notes receivable from affiliates	3	3
Derivative assets	65	60
Fuel and gas in storage	185	268
Materials and supplies	249	235
Prepayments and other current assets	406	386
Regulatory assets	489	447
Total Current Assets	3,140	3,210
Total Property, Plant and Equipment ($2,698 and $2,707 related to VIEs, respectively)	31,249	30,994
Operating lease right-of-use assets	199	159
Equity method investments	440	437
Other investments	43	49
Regulatory assets	2,473	2,321
Other Assets
Goodwill	3,119	3,119
Intangible assets	278	281
Derivative assets	104	140
Other	413	413
Total Other Assets	3,914	3,953
Total Assets	41,458	41,123
Current Liabilities
Current portion of debt	413	412
Notes payable	1,291	566
Notes payable to affiliates	2	2
Interest accrued	93	66
Accounts payable and accrued liabilities	1,562	2,007
Accounts payable to affiliates	16	39
Dividends payable	170	170
Taxes accrued	78	61
Operating lease liabilities	12	13
Derivative liabilities	98	133
Other current liabilities	483	593
Regulatory liabilities	352	354
Total Current Liabilities	4,570	4,416
Regulatory liabilities	2,884	2,915
Other Non-current Liabilities
Deferred income taxes	2,270	2,234
Deferred income	1,048	1,062
Pension and other postretirement	484	491
Operating lease liabilities	201	161
Derivative liabilities	135	164
Asset retirement obligations	277	273
Environmental remediation costs	277	279
Other	559	563
Total Other Non-current Liabilities	5,251	5,227
Non-current debt	8,235	8,215
Non-current debt to affiliate	8	8
Total Non-current Liabilities	16,378	16,365
Total Liabilities	20,948	20,781
Commitments and Contingencies
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,747,089 and 387,734,757 shares issued; 386,640,918 and 386,628,586 shares outstanding, respectively	3	3
Additional paid in capital	17,697	17,694
Treasury stock	(47)	(47)
Retained earnings	1,985	1,910
Accumulated other comprehensive loss	(131)	(180)
Total Stockholders’ Equity	19,507	19,380
Non-controlling interests	1,003	962
Total Equity	20,510	20,342
Total Liabilities and Equity	$ 41,458	$ 41,123

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Property, plant and equipment	$ 31,249	$ 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)	387,747,089	387,734,757
Common stock, outstanding (in shares)	386,640,918	386,628,586
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 2,698	$ 2,707

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Cash Flow from Operating Activities:
Net Income	$ 215	$ 427
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	280	261
Regulatory assets/liabilities amortization and carrying cost	(32)	2
Pension cost	(3)	8
Earnings from equity method investments	(2)	(253)
Distributions of earnings received from equity method investments	6	5
Unrealized loss on marked-to-market derivative contracts	4	3
Deferred taxes	(1)	51
Other non-cash items	(5)	0
Changes in operating assets and liabilities:
Current assets	82	(183)
Noncurrent assets	(96)	(127)
Current liabilities	(242)	196
Noncurrent liabilities	(2)	(2)
Net Cash Provided by Operating Activities	204	388
Cash Flow from Investing Activities:
Capital expenditures	(836)	(811)
Contributions in aid of construction	19	30
Proceeds from sale of assets	6	3
Proceeds from notes receivable from affiliates	1	0
Distributions received from equity method investments	2	2
Other investments and equity method investments, net	(11)	(172)
Net Cash Used in Investing Activities	(819)	(948)
Cash Flow from Financing Activities:
Non-current debt issuances	0	149
Repayments of non-current debt	(4)	(89)
Receipts (Repayments) of other short-term debt, net	722	(161)
Repayments of financing leases	(1)	(6)
Issuance of common stock	0	(1)
Distributions to noncontrolling interests	(3)	(1)
Contributions from noncontrolling interests	74	13
Dividends paid	(170)	(170)
Net Cash Provided by (Used in) Financing Activities	618	(266)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	3	(826)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	72	1,477
Cash, Cash Equivalents and Restricted Cash, End of Period	75	651
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	56	55
Cash (refunded) paid for income taxes	$ (1)	$ 5

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)		427	445					445		(18)
Other comprehensive income (loss), net of tax		(4)	(4)						(4)
Comprehensive income		423
Dividends declared		(340)	(340)					(340)
Issuances of common stock (in shares)	[1]			56,127
Issuance of common stock		(1)	(1)			(1)
Stock-based compensation		5	5			5
Distributions to noncontrolling interests		(1)								(1)
Contributions from noncontrolling interests		13								13
Balance, end of period (in shares) at Mar. 31, 2022	[1]			386,624,231
Balance, end of period at Mar. 31, 2022		$ 20,060	19,181	$ 3		17,683	(47)	1,819	(277)	879
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)		215	245					245		(30)
Other comprehensive income (loss), net of tax		49	49						49
Comprehensive income		264
Dividends declared		(170)	(170)					(170)
Issuances of common stock (in shares)	[1]			12,332
Stock-based compensation		3	3			3
Distributions to noncontrolling interests		(3)								(3)
Contributions from noncontrolling interests		$ 74								74
Balance, end of period (in shares) at Mar. 31, 2023		386,640,918		386,640,918	[1]
Balance, end of period at Mar. 31, 2023		$ 20,510	$ 19,507	$ 3		$ 17,697	$ (47)	$ 1,985	$ (131)	$ 1,003
[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
	Mar. 31, 2023	Mar. 31, 2022
Statement of Stockholders' Equity [Abstract]
Other comprehensive loss, tax	$ 17	$ (3)
Dividends declared (in dollars per share)	$ 0.44	$ 0.44
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01

Background and Nature of Operat

Background and Nature of Operations	3 Months Ended
	Mar. 31, 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 was expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID (Merger). Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (PNMR common stock) (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash (Merger Consideration). Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976 (HSR)), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, 2021, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR's subsidiary, Public Service Company of New Mexico (PNM), AVANGRID and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNM filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. The Statement of Issues was filed on February 2, 2022 and the Brief in Chief was filed on April 7, 2022. On June 14, 2022, the NMPRC filed its Answer Brief. On June 13, 2022, New Energy Economy, an intervener in the Merger proceeding, filed its Answer Brief. AVANGRID's Reply Brief was filed on August 5, 2022. On March 8, 2023, AVANGRID, PNM and the NMPRC filed a motion to dismiss the appeal and remand the proceeding back to the NMPRC for further proceedings. The motion states that, once granted, AVANGRID and PNM intend to file a motion for rehearing and/or reconsideration at the NMPRC. One party opposed the motion and certain other parties have sought clarification regarding the process that the NMPRC would implement on remand. 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 at 11:50 pm on March 10, 2023, providing HSR clearance for another year. On September 21, 2022, New Energy Economy filed a motion to show cause with the NMPRC alleging that AVANGRID and PNM have engaged in a misleading joint advertising and sponsorship strategy and requesting an investigation. AVANGRID and PNM filed a reply to the motion to show cause on October 11, 2022. On December 14, 2022, the NMPRC issued an order denying the motion. In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the 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. As amended by the Second Amendment, the Merger Agreement may be terminated by each of AVANGRID and PNMR under certain circumstances, including if the Merger is not consummated by July 20, 2023. 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 July 20, 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 (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). The Side Letter Agreement provides that any drawing in the form of indebtedness made by the Corporation pursuant to the Funding Commitment Letter shall bear interest at an interest rate equal to 3-month LIBOR plus 0.75% per annum calculated on the basis of a 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, we shall pay Iberdrola a facility fee equal to 0.12% per annum on the undrawn portion of the funding commitment set forth in the Funding Commitment Letter. On May 18, 2021, we issued 77,821,012 shares of common stock in two private placements. Iberdrola purchased 63,424,125 shares and Hyde Member LLC, a Delaware limited liability company and a wholly owned subsidiary of Qatar Investment Authority, purchased 14,396,887 shares of our common stock, par value $0.01 per share, at the purchase price of $51.40 per share, which was the closing price of the shares of our common stock on the NYSE as of May 11, 2021. Proceeds of the private placements were $4,000 million. $3,000 million of the proceeds were used to repay the Iberdrola Loan. After the effect of the private placements, Iberdrola retained its 81.6% ownership interest in AVANGRID.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The accompanying condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 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 months ended March 31, 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	3 Months Ended
	Mar. 31, 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

Revenue

Revenue	3 Months Ended
	Mar. 31, 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 November 2023 upon commercial operation. Contract assets totaled $9 million at both March 31, 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 $16 million and $33 million at March 31, 2023 and December 31, 2022, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $17 million and $8 million as revenue during the three months ended March 31, 2023 and 2022, respectively. Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2023 and 2022 are as follows: Three Months Ended March 31, 2023 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,308 $ — $ — $ 1,308 Regulated operations – natural gas 722 — — 722 Nonregulated operations – wind — 216 — 216 Nonregulated operations – solar — 4 — 4 Nonregulated operations – thermal — 55 — 55 Other(a) (3) (13) — (16) Revenue from contracts with customers 2,027 262 — 2,289 Leasing revenue 2 — — 2 Derivative gains — 122 — 122 Alternative revenue programs 37 — — 37 Other revenue 10 6 — 16 Total operating revenues $ 2,076 $ 390 $ — $ 2,466 Three Months Ended March 31, 2022 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,170 $ — $ — $ 1,170 Regulated operations – natural gas 721 — — 721 Nonregulated operations – wind — 220 — 220 Nonregulated operations – solar — 7 — 7 Nonregulated operations – thermal — 13 — 13 Other(a) 22 16 — 38 Revenue from contracts with customers 1,913 256 — 2,169 Leasing revenue 3 — — 3 Derivative losses — (63) — (63) Alternative revenue programs 12 — — 12 Other revenue 7 5 — 12 Total operating revenues $ 1,935 $ 198 $ — $ 2,133 (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 March 31, 2023 and December 31, 2022, accounts receivable balances related to contracts with customers were approximately $1,603 million and $1,622 million, respectively, including unbilled revenues of $410 million and $541 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets. As of March 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of March 31, 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 85 12 10 7 5 60 179 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 53 23 5 3 1 2 87 Total operating revenues $ 139 $ 35 $ 15 $ 10 $ 6 $ 62 $ 267 As of March 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2023 was $109 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	3 Months Ended
	Mar. 31, 2023
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize as regulatory assets incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. As of March 31, 2023, the total net amount of these items is approximately $1,012 million. CMP Distribution Rate Case In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. Commencing on March 1, 2020, the MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order. The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. In an order dated February 7, 2023, the MPUC closed this investigation after consolidating its records with CMP’s pending rate case. In accordance with Chapter 120 of MPUC Rules, on May 26, 2022, CMP filed a nonbinding notice of intent to file a distribution rate case on or after sixty days from the issuance of the letter. In the notice, CMP signaled its intent to propose a three-year rate plan, which includes a multi-year capital investment plan to fund investments needed to improve reliability and resiliency, as well as to continue to improve the customer experience and cost-effectively advance clean energy transformation. CMP’s notice estimated a revenue change in the range of $45 to $50 million in the first year of the rate plan followed by increases in the range of $25 to $30 million in the second year and $20 to $25 million in the third year. We cannot predict the outcome of this matter. On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. In its filing, CMP has set the three rate years as May 10, 2023 to May 9, 2024 (“Rate Year 1”); May 10, 2024 to May 9, 2025 (“Rate Year 2”); and May 10, 2025 to May 9, 2026 (“Rate Year 3”). The requested Rate Year revenue requirement increases for the rate years are $48 million, $28 million and $23 million, respectively. The revenue requirement adjustments are based on a test year ending December 31, 2021. The requested revenue changes for each rate year of the proposal are subject to four adjustment mechanisms: (1) a yearly review of plant additions with potential downward reconciliation in the event of an underspend, (2) a capital adjustment mechanism for certain incremental pole replacements, broadband work, electric vehicle work, energy storage projects, and metering system upgrades, (3) a symmetrical inflation reconciliation adjustment, and (4) reconciliation of the benefits associated with the tax basis repair deduction. Other parties filed direct testimony in this proceeding on December 2, 2022 and CMP filed rebuttal testimony on February 7, 2023. Settlement discussions are on-going and technical conferences are scheduled for mid-May 2023. New rates are expected to take effect on or around August 2023. We cannot predict the outcome of this matter. NYSEG and RG&E Rate Plans On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50.00%. The below table provides a summary of the approved delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses. Rate years two and three commence on May 1, 2021 and 2022, respectively: Year 1 Year 2 Year 3 Rate Increase Delivery Rate % Rate Increase Delivery Rate % Rate Increase Delivery Rate % Utility (Millions) Increase (Millions) Increase (Millions) Increase NYSEG Electric $ 34 4.6 % $ 46 5.9 % $ 36 4.2 % NYSEG Gas $ — — % $ 2 0.8 % $ 3 1.6 % RG&E Electric $ 17 3.8 % $ 14 3.2 % $ 16 3.3 % RG&E Gas $ — — % $ — — % $ 2 1.3 % On May 26, 2022, NYSEG and RG&E filed for a new rate plan with the NYPSC. The rate filings are based on test year 2021 financial results adjusted to the rate year May 1, 2023 – April 30, 2024. Since these rate filings were submitted on May 26, 2022, the effective date of new rates, assuming an approximately 11-month approval period, will be May 1, 2023. NYSEG and RG&E filed for a one-year rate plan but expressed interest in exploring a multi-year plan during the pendency of the case (as is the custom in New York). On August 12, 2022, NYSEG and RG&E filed an update to its rate plan filing called for in the litigation schedule. In their filings, the following revenue changes were requested: Requested Revenue Change May 26, 2022 August 12, 2022 Difference Utility (Millions) (Millions) (Millions) NYSEG Electric $ 274 $ 274 $ — NYSEG Gas $ 43 $ 30 $ (13) RG&E Electric $ 94 $ 93 $ (1) RG&E Gas $ 38 $ 32 $ (6) On September 16, 2022, the NYPSC suspended new tariffs and rates through April 21, 2023. On October 19, 2022, consistent with the Administrative Law Judge’s’ July 1, 2022 Ruling on Schedule and Party Status, NYSEG and RG&E voluntarily agreed to 60-day extension of maximum suspension period through June 20, 2023, subject to a make-whole provision. On December 21, 2022, NYSEG and RG&E voluntarily agreed to further 60-day extension of maximum suspension period to postpone through August 19, 2023, subject to a make-whole provision. On February 16, 2023, NYSEG and RG&E voluntarily agreed to a further 30-day extension of the suspension period through September 18, 2023, subject to a make-whole provision. On April 11, 2023, the NYSEG and RG&E requested a further 30-day suspension through October 18, 2023, subject to a make-whole provision. During this time, the parties have conducted multi-party rate case settlement negotiations. We cannot predict the outcome of this proceeding. UI, CNG, SCG and BGC Rate Plans In 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017 and, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% equity ratio, continued UI’s existing earnings sharing mechanism (ESM) pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. On September 9, 2022, UI filed a distribution revenue requirement case. UI’s filing proposes a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing is based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (“UI Rate Year 1”), September 1, 2024 (“UI Rate Year 2”), and September 1, 2025 (“UI Rate Year 3”). UI is requesting that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $102 million in UI Rate Year 1, an incremental approximately $17 million in UI Rate Year 2, and an incremental approximately $17 million in UI Rate Year 3, compared to total revenues that would otherwise be recovered under UI’s current rate schedules. UI’s Rate Plan also includes several measures to moderate the impact of the proposed rate update for all customers, including, without limitation a rate levelization proposal to spread the proposed total rate increase over the three rate years, which would result in a change in revenue in UI Rate Year 1 of approximately $54 million. Other parties filed direct testimony on December 13, 2022 and UI filed its rebuttal testimony on January 6, 2023. Rate case hearings started on February 16, 2023 and concluded on March 22, 2023 with initial briefs due April 27, 2023. Litigation of the case is expected to take approximately one year with new rates expected to go into effect on or around September 2023. We cannot predict the outcome of this matter. In 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with annual rate increases. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and an equity ratio of approximately 52.00%. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. In 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (CNG) effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021. 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. The Company is reviewing the requirements of this program and evaluating next steps. PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation On August 6, 2020, 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. 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 March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Pension and other post-retirement benefits cost deferrals $ 363 $ 365 Pension and other post-retirement benefits 70 93 Storm costs 766 671 Rate adjustment mechanism 55 41 Revenue decoupling mechanism 66 52 Transmission revenue reconciliation mechanism 7 11 Contracts for differences 52 56 Hardship programs 31 33 Plant decommissioning 1 1 Deferred purchased gas 9 56 Environmental remediation costs 247 248 Debt premium 62 64 Unamortized losses on reacquired debt 20 19 Unfunded future income taxes 504 492 Federal tax depreciation normalization adjustment 135 137 Asset retirement obligation 20 20 Deferred meter replacement costs 57 55 COVID-19 cost recovery and late payment surcharge 14 17 Low income arrears forgiveness 68 31 Excess generation service charge 77 24 System Expansion 16 21 Non-bypassable charge 46 14 Hedges losses 50 13 Other 226 234 Total regulatory assets 2,962 2,768 Less: current portion 489 447 Total non-current regulatory assets $ 2,473 $ 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 incurred. “System expansion” represents expenses not covered by system expansion rates related to expanding the natural gas system and converting customers to natural gas. “Non-bypassable charges” represent non-bypassable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “Hedge losses” represents the deferred fair value losses on electric and gas hedge contracts. “Other” includes post-term amortization deferrals and various items subject to reconciliation including debt rate reconciliation and deferred property tax. Regulatory liabilities as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Energy efficiency portfolio standard $ 25 $ 30 Gas supply charge and deferred natural gas cost 28 15 Pension and other post-retirement benefits cost deferrals 112 117 Carrying costs on deferred income tax bonus depreciation 5 9 Carrying costs on deferred income tax - Mixed Services 263(a) 2 3 2017 Tax Act 1,218 1,232 Rate Change Levelization 13 25 Revenue decoupling mechanism 8 13 Accrued removal obligations 1,167 1,178 Economic development 17 20 Positive benefit adjustment 14 16 Theoretical reserve flow thru impact 3 3 Deferred property tax 17 17 Net plant reconciliation 9 11 Debt rate reconciliation 27 32 Rate refund – FERC ROE proceeding 36 36 Transmission congestion contracts 32 31 Merger-related rate credits 9 10 Accumulated deferred investment tax credits 22 22 Asset retirement obligation 17 18 Earning sharing provisions 8 13 Middletown/Norwalk local transmission network service collections 16 17 Low income programs 19 18 Non-firm margin sharing credits 24 27 New York 2018 winter storm settlement 1 1 Non by-passable charges 63 76 Transmission revenue reconciliation mechanism 73 75 Other 251 204 Total regulatory liabilities 3,236 3,269 Less: current portion 352 354 Total non-current regulatory liabilities $ 2,884 $ 2,915 “Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. “Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/returned to customers beginning the next calendar year. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. "Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. “2017 Tax Act” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions. “Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020. “Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Economic development” represents the economic development program, which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020. “Positive benefit adjustment” resu

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	3 Months Ended
	Mar. 31, 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. • NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3. • UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as 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 the London Interbank Offered Rate (LIBOR) the Secured Overnight Financing Rate (SOFR), forward interest rate curves or other relevant benchmark. We include the fair value measurement for these contracts in Level 2 (See Note 12 for further discussion of interest rate contracts). We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value. Restricted cash was $3 million as of both March 31, 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 March 31, 2023 and December 31, 2022, respectively, consisted of: As of March 31, 2023 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 29 $ 13 $ — $ — $ 42 Derivative assets Derivative financial instruments - power $ 15 $ 58 $ 134 $ (137) $ 70 Derivative financial instruments - gas — 26 4 (22) 8 Contracts for differences — — 1 — 1 Derivative financial instruments – Other — 90 — — 90 Total $ 15 $ 174 $ 139 $ (159) $ 169 Derivative liabilities Derivative financial instruments - power $ (55) $ (245) $ (72) $ 288 $ (84) Derivative financial instruments - gas (10) (20) — 29 (1) Contracts for differences — — (53) — (53) Derivative financial instruments – Other — (95) — — (95) Total $ (65) $ (360) $ (125) $ 317 $ (233) 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 months ended March 31, 2023 and 2022, respectively, is as follows: Three Months Ended March 31, (Millions) 2023 2022 Fair Value Beginning of Period, $ 16 $ (69) Gains recognized in operating revenues — 38 (Losses) recognized in operating revenues (3) (40) Total losses recognized in operating revenues (3) (2) Gains recognized in OCI 11 2 (Losses) recognized in OCI (3) (63) Total gains (losses) recognized in OCI 8 (61) Net change recognized in regulatory assets and liabilities 4 4 Purchases 9 (1) Settlements (20) 5 Fair Value as of March 31, $ 14 $ (124) 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 $ (3) $ (2) 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 March 31, 2023 Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.53 $ 9.86 $ 1.99 AECO ($/MMBtu) $ 3.20 $ 10.80 $ 1.23 Ameren ($/MWh) $ 54.23 $ 225.62 $ 22.08 COB ($/MWh) $ 80.39 $ 400.10 $ 10.85 ComEd ($/MWh) $ 49.88 $ 222.49 $ 18.78 ERCOT S hub ($/MWh) $ 49.97 $ 320.63 $ 16.85 Mid C ($/MWh) $ 77.60 $ 400.10 $ 7.85 AEP-DAYTON hub ($/MWh) $ 55.26 $ 229.75 $ 24.44 PJM W hub ($/MWh) $ 58.12 $ 227.60 $ 24.76 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 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 March 31, 2023 Risk of non-performance 0.76% Discount rate 3.60% - 3.81% Forward pricing ($ per KW-month) $2.00 - $3.80 Fair Value of Debt As of March 31, 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 $8,168 million and $7,991 million as of March 31, 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	3 Months Ended
	Mar. 31, 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 March 31, 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 March 31, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 13 $ 4 $ 12 $ 3 Derivative liabilities (12) (3) (71) (47) 1 1 (59) (44) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 1 1 (59) (44) Cash collateral receivable — — 41 8 Total derivatives as presented in the balance sheet $ 1 $ 1 $ (18) $ (36) 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 March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.7 Natural gas purchase contracts (Dth) 7.9 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 March 31, 2023 and December 31, 2022 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 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 March 31, March 31, 2023 Electricity Natural Gas 2023 Electricity Natural Gas Regulatory assets $ 40 $ 10 Purchased power, natural gas and fuel used $ 49 $ 6 December 31, 2022 2022 Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (45) $ (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 March 31, 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 $52 million, a gross derivative liability of $53 million ($52 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 months ended March 31, 2023 and 2022, respectively, were as follows: Three Months Ended March 31, 2023 2022 (Millions) Derivative liabilities $ 4 $ 4 Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 1 $ 95 Commodity contracts — Purchased power, natural gas and fuel used — 977 Total $ — $ 1 2022 Interest rate contracts $ — Interest expense $ 1 $ 71 Commodity contracts 2 Purchased power, natural gas and fuel used (1) 741 Total $ 2 $ — (a) Changes in accumulated OCI are reported on a pre-tax basis. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $42 million and $43 million as of March 31, 2023 and December 31, 2022, respectively. For both the three months ended March 31, 2023 and 2022, Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million. Networks will amortize approximately $3 million of discontinued cash flow hedges for the remainder of 2023. (b) Renewables activities Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (MWh/Dth in millions) Wholesale electricity purchase contracts 2 2 Wholesale electricity sales contracts 7 7 Natural gas and other fuel purchase contracts 20 15 Financial power contracts 6 6 Basis swaps – purchases 26 22 Basis swaps – sales 2 — The fair values of derivative contracts associated with Renewables' activities as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts $ 110 $ 149 Wholesale electricity sales contracts (134) (200) Natural gas and other fuel purchase contracts 8 2 Financial power contracts 9 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 March 31, 2023 and December 31, 2022, the fair value of the interest rate swap was $90 million and $116 million, respectively, as a 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 March 31, 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 March 31, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 106 $ 49 $ 53 $ 5 Derivative liabilities (42) (36) (77) (6) 64 13 (24) (1) Designated as hedging instruments Derivative assets — 90 4 4 Derivative liabilities — — (102) (74) — 90 (98) (70) Total derivatives before offset of cash collateral 64 103 (122) (71) Cash collateral receivable — — 70 39 Total derivatives as presented in the balance sheet $ 64 $ 103 $ (52) $ (32) 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 months ended March 31, 2023 and 2022, consisted of: Three Months Ended March 31, 2023 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (4) $ 1 Wholesale electricity sales contracts 7 24 Financial power contracts 2 15 Financial and natural gas contracts — 10 Total gain included in operating revenues $ 5 $ 50 $ 2,466 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (35) Financial power contracts — — Financial and natural gas contracts — (21) Total loss included in purchased power, natural gas and fuel used $ — $ (56) $ 977 Total Gain (Loss) $ 5 $ (6) Three Months Ended March 31, 2022 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 9 $ 3 Wholesale electricity sales contracts (1) (40) Financial power contracts (2) (21) Financial and natural gas contracts (1) (25) Total gain (loss) included in operating revenues $ 5 $ (83) $ 2,133 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 37 Financial power contracts — 1 Financial and natural gas contracts — 37 Total gain included in purchased power, natural gas and fuel used $ — $ 75 $ 741 Total Gain (Loss) $ 5 $ (8) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 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 $ 90 Interest Expense $ — $ 95 Commodity contracts 23 Operating revenues 66 $ 2,466 Total $ 113 $ 66 2022 Interest rate contracts $ (56) Interest Expense $ — $ 71 Commodity contracts (112) Operating revenues 11 $ 2,133 Total $ (168) $ 11 (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 $99 million of losses included in accumulated OCI at March 31, 2023, are expected to be reclassified into earnings within the next twelve months. We did not record any net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2023 and 2022. (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 March 31, 2023 and December 31, 2022, the net loss in accumulated OCI related to previously settled interest rate contracts was $36 million and $38 million, respectively. For both the three months ended March 31, 2023 and 2022, we amortized into income $2 million of the loss related to settled interest rate contracts. We will amortize approximately $7 million of the net loss on the interest rate contracts for the remainder of 2023. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 2 $ 95 2022 Interest rate contracts $ — Interest expense $ 2 $ 71 (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 months ended March 31, 2023 and 2022 are as follows: Fair value of hedge Location of Loss Recognized in Income Statement Loss Recognized in Income Statement Year to date total per Income Statement (Millions) As of March 31, 2023 Three Months Ended March 31, 2023 Current Liabilities $ (28) Interest Expense $ 7 $ 95 Non-current liabilities $ (67) Cumulative effect on hedged debt Current debt $ 28 Non-current debt $ 67 Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2022 Three Months Ended March 31, 2022 Current Liabilities $ (29) Interest Expense $ (2) $ 71 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 March 31, 2023, UI would have had to post an aggregate of approximately $40 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 March 31, 2023 and December 31, 2022, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $96 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 March 31, 2023 was $50 million, for which we have posted collateral.

Contingencies and Commitments

Contingencies and Commitments	3 Months Ended
	Mar. 31, 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 NETOs claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $28 million and $8 million, respectively, as of March 31, 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, a buyer under a virtual PPA with a subsidiary of Renewables provided notice that the buyer disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations. The buyer has requested an adjustment to the invoices that would increase the amount payable by approximately $29 million. Renewables has responded in writing stating that the invoice was properly calculated in accordance with the provisions of the PPA. The parties participated in a mediation in March 2023. We cannot predict the outcome of this matter. Guarantee Commitments to Third Parties As of March 31, 2023, we had approximately $693 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 March 31, 2023, neither we nor our subsidiaries have any liabilities recorded for these instruments. NECEC Commitments On January 4, 2021, CMP transferred the New England Clean Energy Connect, or NECEC, project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately

Environmental Liabilities

Environmental Liabilities	3 Months Ended
	Mar. 31, 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; four sites are included in Maine’s Uncontrolled Sites Program; zero site is included in the Brownfield Cleanup Program and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, six of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and several for certain sites. We have recorded an estimated liability of $7 million related to seven of the twenty-four sites. We have paid remediation costs related to the remaining seventeen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of March 31, 2023, our estimate for costs to remediate these sites ranges from $14 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry; 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; one site under a Brownfield Cleanup Program and three sites are included in Maine Department of Environmental Protection programs (one each 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 March 31, 2023, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $154 million to $255 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 March 31, 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 March 31, 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 March 31, 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 $282 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 2092. 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 March 31, 2023, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $9 million and $7 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable. English Station 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. As of March 31, 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.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	3 Months Ended
	Mar. 31, 2023
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar ObligationsWe made no pension contributions for the three months ended March 31, 2023. We do not expect to make any additional contributions in 2023. The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions) Service cost $ 2 $ 8 Interest cost 30 24 Expected return on plan assets (36) (45) Amortization of: Prior service costs — 1 Actuarial loss 1 18 Curtailments and settlements — 2 Net Periodic Benefit Cost $ (3) $ 8 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions) Service cost $ — $ 1 Interest cost 3 3 Expected return on plan assets (1) (2) Amortization of: Prior service costs — — Actuarial loss (3) (1) Net Periodic Benefit Cost $ (1) $ 1

Equity

Equity	3 Months Ended
	Mar. 31, 2023
Equity [Abstract]
Equity	Equity As of both March 31, 2023 and December 31, 2022, we had 108,188 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2023 and 2022, we issued 12,332 and 56,127 shares of common stock, respectively, each having a par value of $0.01, and 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 March 31, 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 March 31, 2023. Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss for the three months ended March 31, 2023 and 2022, respectively, consisted of: As of December 31, Three Months Ended March 31, As of March 31, As of December 31, Three Months Ended March 31, As of March 31, 2022 2023 2023 2021 2022 2022 (Millions) Gain for defined benefit plans, net of income tax expense of $0 for 2023 and $3 for 2022 $ — $ 8 Amortization of pension cost, net of income tax expense of $0 for 2023 and $0 for 2022 — 1 Net (loss) gain on pension plans (20) — (20) (38) 9 (29) Unrealized (loss) gain from equity method investment, net of income tax expense of $0 for 2023 and $5 for 2022 (a) 13 (1) 12 (9) 15 6 Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(1) for 2023 and $(15) for 2022 (195) (2) (197) (194) (39) (233) Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $18 for 2023 and $4 for 2022 (b) 22 52 74 (32) 11 (21) Loss (gain) on derivatives qualifying as cash flow hedges (173) 50 (123) (226) (28) (254) Accumulated Other Comprehensive Loss $ (180) $ 49 $ (131) $ (273) $ (4) $ (277) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three months ended March 31, 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. The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 245 $ 445 Denominator: Weighted average number of shares outstanding - basic 386,744,996 386,698,132 Weighted average number of shares outstanding - diluted 387,077,213 387,114,285 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.63 $ 1.15 Earnings Per Common Share, Diluted $ 0.63 $ 1.15

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2023
Segment Reporting [Abstract]
Segment Information	Segment InformationOur 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 and costs incurred in connection with the COVID-19 pandemic. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our 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 months ended March 31, 2023, consisted of: Three Months Ended March 31, 2023 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,076 $ 390 $ — $ 2,466 Depreciation and amortization 174 105 1 280 Operating income (loss) 277 (10) (2) 265 Earnings (losses) from equity method investments 4 (2) — 2 Interest expense, net of capitalization 70 6 19 95 Income tax expense (benefit) 44 (34) (28) (18) Adjusted net income 195 51 1 248 Capital expenditures 609 227 — 836 As of March 31, 2023 Property, plant and equipment 20,291 10,942 16 31,249 Equity method investments 181 259 — 440 Total assets $ 28,591 $ 13,164 $ (297) $ 41,458 (a) Includes Corporate and intersegment eliminations. Segment information for the three months ended March 31, 2022 and as of December 31, 2022, consisted of: Three Months Ended March 31, 2022 Networks Renewables Other (a) AVANGRID (Millions) Revenue - external $ 1,935 $ 198 $ — $ 2,133 Depreciation and amortization 161 100 — 261 Operating income (loss) 319 (18) 1 302 Earnings from equity method investments 3 250 — 253 Interest expense, net of capitalization 50 3 18 71 Income tax expense (benefit) 31 41 (4) 68 Adjusted net income (loss) 254 211 (15) 450 Capital expenditures 355 454 2 811 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 months ended March 31, 2023 and 2022, respectively, is as follows: Three Months Ended March 31, 2023 2022 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 248 $ 450 Adjustments: Mark-to-market earnings - Renewables (1) (4) (3) Impact of COVID-19 (2) — (2) Income tax impact of adjustments 1 2 Net Income Attributable to Avangrid, Inc. $ 245 $ 445 (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.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 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 months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (11) $ — $ (12) Iberdrola Renovables Energía, S.L. $ — $ (2) $ — $ (2) Iberdrola Financiación, S.A. $ — $ (4) $ — $ (3) Vineyard Wind $ 2 $ — $ 2 $ — Other $ — $ — $ — $ (1) Related party balances as of March 31, 2023 and December 31, 2022, respectively, consisted of: As of March 31, 2023 December 31, 2022 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ — $ (11) $ 1 $ (29) Iberdrola Financiación, S.A. $ — $ (2) $ — $ (9) Vineyard Wind $ 2 $ (8) $ 3 $ (8) Iberdrola Solutions $ — $ (2) $ — $ (2) Other $ 3 $ (3) $ 4 $ (1) Transactions with Iberdrola relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balance of $2 million as both March 31, 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 March 31, 2023 and December 31, 2022, was $0. AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of March 31, 2023 and December 31, 2022, there was no outstanding amount under this credit facility. See Note 19 - Equity Method Investments for more information on Vineyard Wind, LLC (Vineyard Wind).

Other Financial Statement Items

Other Financial Statement Items	3 Months Ended
	Mar. 31, 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 March 31, 2023 and December 31, 2022 consisted of: As of March 31, 2023 December 31, 2022 (Millions) Trade receivables and unbilled revenues $ 1,817 $ 1,892 Allowance for credit losses (148) (155) Accounts receivable and unbilled revenues, net $ 1,669 $ 1,737 The change in the allowance for credit losses for the three months ended March 31, 2023 and 2022 consisted of: Three Months Ended March 31, (Millions) 2023 2022 As of Beginning of Period, $ 155 $ 151 Current period provision 17 20 Write-off as uncollectible (24) (18) As of March 31, $ 148 $ 153 The Deferred Payment Arrangements (DPA) receivable balance was $102 million at both March 31, 2023 and December 31, 2022. The allowance for credit losses for DPAs at March 31, 2023 and December 31, 2022 was $40 million and $42 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2023 and 2022, was $(2) million and $3 million, respectively. Prepayments and other current assets Included in prepayments and other current assets are $194 million and $136 million of prepaid other taxes as of March 31, 2023 and December 31, 2022, respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of March 31, 2023 and December 31, 2022, respectively, were as follows: March 31, December 31, As of 2023 2022 (Millions) Property, plant and equipment Accumulated depreciation $ 11,789 $ 11,542 Intangible assets Accumulated amortization $ 335 $ 331 As of March 31, 2023 and 2022, accrued liabilities for property, plant and equipment additions were $239 million and $122 million, respectively. Debt Commercial Paper As of March 31, 2023 and December 31, 2022, there was $1,090 million and $397 million of commercial paper outstanding, respectively. As of March 31, 2023 and December 31, 2022, the weighted-average interest rate on commercial paper was 5.33% and 4.66%, respectively. AVANGRID Credit facility As of March 31, 2023 and December 31, 2022, there was $200 million and $0 of short-term borrowings outstanding under the AVANGRID credit facility, respectively. As of March 31, 2023 the weighted-average interest rate on short-term borrowings under the AVANGRID credit facility was 6.05% Supplier Financing Arrangements We operate a supplier financing arrangement. We arranged for the extension of payment terms with some suppliers (limited to 360 days or less), 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 March 31, 2023 and December 31, 2022, the amount of notes payable under supplier financing arrangements was $4 million and $171 million, respectively. As of March 31, 2023 and December 31, 2022, the weighted average interest rate on the balance was 6.12% and 5.48%, respectively. Other current liabilities Included in other current liabilities are $268 million and $271 million of advances received as of March 31, 2023 and December 31, 2022, respectively.

Income Tax Expense

Income Tax Expense	3 Months Ended
	Mar. 31, 2023
Income Tax Disclosure [Abstract]
Income Tax Expense	Income Tax ExpenseThe effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2023, was (9.1)%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act and the equity component of allowance for funds used during construction.The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2022, was 13.7%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act and the equity component of allowance for funds used during construction, partially offset by the tax on gain from the offshore joint venture restructuring transaction (see Note 19 for further details on the transaction), which was reflected in total in the first quarter as a discrete adjustment.

Stock-Based Compensation Expens

Stock-Based Compensation Expense	3 Months Ended
	Mar. 31, 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. On April 12, 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 1st installment of this RSU grant was settled in January 2023, net of applicable taxes, by issuing 8,690 shares of common stock. Phantom Share Units In February 2022, 9,000 Phantom Shares were granted to certain AVANGRID executives and employees. These awards vest in three equal installments in 2022 - 2024 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of AVANGRID’s common stock at each reporting date until the date of settlement. In February 2023, $0.1 million was paid to settle the second installment 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 - 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 March 31, 2023 and December 31, 2022, the total liability was $1 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 months ended March 31, 2023 and 2022, was $4 million and $5 million, respectively.

Variable Interest Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 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 $2,806 million and $388 million, respectively, at March 31, 2023. As of December 31, 2022, the assets and liabilities of VIEs totaled approximately $2,853 million and $424 million, respectively. At March 31, 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 March 31, 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	3 Months Ended
	Mar. 31, 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. As of March 31, 2023 and December 31, 2022, the carrying amount of Renewables' investments in Vineyard Wind LLC and Vineyard Wind 1 Pledgor LLC was $7 million and $9 million, respectively.

Subsequent Event

Subsequent Event	3 Months Ended
	Mar. 31, 2023
Subsequent Events [Abstract]
Subsequent Event	Subsequent EventOn April 12, 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 July 3, 2023 to shareholders of record at the close of business on June 1, 2023.

Significant Accounting Polici_2

Significant Accounting Policies and New Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 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 November 2023 upon commercial operation. Contract assets totaled $9 million at both March 31, 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 $16 million and $33 million at March 31, 2023 and December 31, 2022, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $17 million and $8 million as revenue during the three months ended March 31, 2023 and 2022, respectively.

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 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 months ended March 31, 2023 and 2022 are as follows: Three Months Ended March 31, 2023 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,308 $ — $ — $ 1,308 Regulated operations – natural gas 722 — — 722 Nonregulated operations – wind — 216 — 216 Nonregulated operations – solar — 4 — 4 Nonregulated operations – thermal — 55 — 55 Other(a) (3) (13) — (16) Revenue from contracts with customers 2,027 262 — 2,289 Leasing revenue 2 — — 2 Derivative gains — 122 — 122 Alternative revenue programs 37 — — 37 Other revenue 10 6 — 16 Total operating revenues $ 2,076 $ 390 $ — $ 2,466 Three Months Ended March 31, 2022 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,170 $ — $ — $ 1,170 Regulated operations – natural gas 721 — — 721 Nonregulated operations – wind — 220 — 220 Nonregulated operations – solar — 7 — 7 Nonregulated operations – thermal — 13 — 13 Other(a) 22 16 — 38 Revenue from contracts with customers 1,913 256 — 2,169 Leasing revenue 3 — — 3 Derivative losses — (63) — (63) Alternative revenue programs 12 — — 12 Other revenue 7 5 — 12 Total operating revenues $ 1,935 $ 198 $ — $ 2,133 (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 March 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of March 31, 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 85 12 10 7 5 60 179 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 53 23 5 3 1 2 87 Total operating revenues $ 139 $ 35 $ 15 $ 10 $ 6 $ 62 $ 267

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2023
Regulated Operations [Abstract]
Schedule of Delivery Rate Increases	The below table provides a summary of the approved delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses. Rate years two and three commence on May 1, 2021 and 2022, respectively: Year 1 Year 2 Year 3 Rate Increase Delivery Rate % Rate Increase Delivery Rate % Rate Increase Delivery Rate % Utility (Millions) Increase (Millions) Increase (Millions) Increase NYSEG Electric $ 34 4.6 % $ 46 5.9 % $ 36 4.2 % NYSEG Gas $ — — % $ 2 0.8 % $ 3 1.6 % RG&E Electric $ 17 3.8 % $ 14 3.2 % $ 16 3.3 % RG&E Gas $ — — % $ — — % $ 2 1.3 % Requested Revenue Change May 26, 2022 August 12, 2022 Difference Utility (Millions) (Millions) (Millions) NYSEG Electric $ 274 $ 274 $ — NYSEG Gas $ 43 $ 30 $ (13) RG&E Electric $ 94 $ 93 $ (1) RG&E Gas $ 38 $ 32 $ (6)
Schedule of Current and Non-Current Regulatory Assets	Regulatory assets as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Pension and other post-retirement benefits cost deferrals $ 363 $ 365 Pension and other post-retirement benefits 70 93 Storm costs 766 671 Rate adjustment mechanism 55 41 Revenue decoupling mechanism 66 52 Transmission revenue reconciliation mechanism 7 11 Contracts for differences 52 56 Hardship programs 31 33 Plant decommissioning 1 1 Deferred purchased gas 9 56 Environmental remediation costs 247 248 Debt premium 62 64 Unamortized losses on reacquired debt 20 19 Unfunded future income taxes 504 492 Federal tax depreciation normalization adjustment 135 137 Asset retirement obligation 20 20 Deferred meter replacement costs 57 55 COVID-19 cost recovery and late payment surcharge 14 17 Low income arrears forgiveness 68 31 Excess generation service charge 77 24 System Expansion 16 21 Non-bypassable charge 46 14 Hedges losses 50 13 Other 226 234 Total regulatory assets 2,962 2,768 Less: current portion 489 447 Total non-current regulatory assets $ 2,473 $ 2,321
Schedule of Current and Non-Current Regulatory Liabilities	Regulatory liabilities as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Energy efficiency portfolio standard $ 25 $ 30 Gas supply charge and deferred natural gas cost 28 15 Pension and other post-retirement benefits cost deferrals 112 117 Carrying costs on deferred income tax bonus depreciation 5 9 Carrying costs on deferred income tax - Mixed Services 263(a) 2 3 2017 Tax Act 1,218 1,232 Rate Change Levelization 13 25 Revenue decoupling mechanism 8 13 Accrued removal obligations 1,167 1,178 Economic development 17 20 Positive benefit adjustment 14 16 Theoretical reserve flow thru impact 3 3 Deferred property tax 17 17 Net plant reconciliation 9 11 Debt rate reconciliation 27 32 Rate refund – FERC ROE proceeding 36 36 Transmission congestion contracts 32 31 Merger-related rate credits 9 10 Accumulated deferred investment tax credits 22 22 Asset retirement obligation 17 18 Earning sharing provisions 8 13 Middletown/Norwalk local transmission network service collections 16 17 Low income programs 19 18 Non-firm margin sharing credits 24 27 New York 2018 winter storm settlement 1 1 Non by-passable charges 63 76 Transmission revenue reconciliation mechanism 73 75 Other 251 204 Total regulatory liabilities 3,236 3,269 Less: current portion 352 354 Total non-current regulatory liabilities $ 2,884 $ 2,915

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of March 31, 2023 and December 31, 2022, respectively, consisted of: As of March 31, 2023 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 29 $ 13 $ — $ — $ 42 Derivative assets Derivative financial instruments - power $ 15 $ 58 $ 134 $ (137) $ 70 Derivative financial instruments - gas — 26 4 (22) 8 Contracts for differences — — 1 — 1 Derivative financial instruments – Other — 90 — — 90 Total $ 15 $ 174 $ 139 $ (159) $ 169 Derivative liabilities Derivative financial instruments - power $ (55) $ (245) $ (72) $ 288 $ (84) Derivative financial instruments - gas (10) (20) — 29 (1) Contracts for differences — — (53) — (53) Derivative financial instruments – Other — (95) — — (95) Total $ (65) $ (360) $ (125) $ 317 $ (233) 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)
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2023 and 2022, respectively, is as follows: Three Months Ended March 31, (Millions) 2023 2022 Fair Value Beginning of Period, $ 16 $ (69) Gains recognized in operating revenues — 38 (Losses) recognized in operating revenues (3) (40) Total losses recognized in operating revenues (3) (2) Gains recognized in OCI 11 2 (Losses) recognized in OCI (3) (63) Total gains (losses) recognized in OCI 8 (61) Net change recognized in regulatory assets and liabilities 4 4 Purchases 9 (1) Settlements (20) 5 Fair Value as of March 31, $ 14 $ (124) 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 $ (3) $ (2) Range at Unobservable Input March 31, 2023 Risk of non-performance 0.76% Discount rate 3.60% - 3.81% Forward pricing ($ per KW-month) $2.00 - $3.80
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. As of March 31, 2023 Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.53 $ 9.86 $ 1.99 AECO ($/MMBtu) $ 3.20 $ 10.80 $ 1.23 Ameren ($/MWh) $ 54.23 $ 225.62 $ 22.08 COB ($/MWh) $ 80.39 $ 400.10 $ 10.85 ComEd ($/MWh) $ 49.88 $ 222.49 $ 18.78 ERCOT S hub ($/MWh) $ 49.97 $ 320.63 $ 16.85 Mid C ($/MWh) $ 77.60 $ 400.10 $ 7.85 AEP-DAYTON hub ($/MWh) $ 55.26 $ 229.75 $ 24.44 PJM W hub ($/MWh) $ 58.12 $ 227.60 $ 24.76

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	3 Months Ended
	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts	The tables below present Networks' derivative positions as of March 31, 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 March 31, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 13 $ 4 $ 12 $ 3 Derivative liabilities (12) (3) (71) (47) 1 1 (59) (44) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 1 1 (59) (44) Cash collateral receivable — — 41 8 Total derivatives as presented in the balance sheet $ 1 $ 1 $ (18) $ (36) 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 March 31, 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 March 31, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 106 $ 49 $ 53 $ 5 Derivative liabilities (42) (36) (77) (6) 64 13 (24) (1) Designated as hedging instruments Derivative assets — 90 4 4 Derivative liabilities — — (102) (74) — 90 (98) (70) Total derivatives before offset of cash collateral 64 103 (122) (71) Cash collateral receivable — — 70 39 Total derivatives as presented in the balance sheet $ 64 $ 103 $ (52) $ (32) 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 Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.7 Natural gas purchase contracts (Dth) 7.9 9.6 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (MWh/Dth in millions) Wholesale electricity purchase contracts 2 2 Wholesale electricity sales contracts 7 7 Natural gas and other fuel purchase contracts 20 15 Financial power contracts 6 6 Basis swaps – purchases 26 22 Basis swaps – sales 2 —
Schedule of Unrealized Gains and Losses from Fair Value Adjustments	The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2023 and December 31, 2022 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 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 March 31, March 31, 2023 Electricity Natural Gas 2023 Electricity Natural Gas Regulatory assets $ 40 $ 10 Purchased power, natural gas and fuel used $ 49 $ 6 December 31, 2022 2022 Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (45) $ (9) The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2023 and 2022, respectively, were as follows: Three Months Ended March 31, 2023 2022 (Millions) Derivative liabilities $ 4 $ 4
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 1 $ 95 Commodity contracts — Purchased power, natural gas and fuel used — 977 Total $ — $ 1 2022 Interest rate contracts $ — Interest expense $ 1 $ 71 Commodity contracts 2 Purchased power, natural gas and fuel used (1) 741 Total $ 2 $ — (a) Changes in accumulated OCI are reported on a pre-tax basis. Three Months Ended March 31, 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 $ 90 Interest Expense $ — $ 95 Commodity contracts 23 Operating revenues 66 $ 2,466 Total $ 113 $ 66 2022 Interest rate contracts $ (56) Interest Expense $ — $ 71 Commodity contracts (112) Operating revenues 11 $ 2,133 Total $ (168) $ 11 (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 months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 2 $ 95 2022 Interest rate contracts $ — Interest expense $ 2 $ 71 (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 Hedging Instruments	The effects on our consolidated financial statements as of and for the three months ended March 31, 2023 and 2022 are as follows: Fair value of hedge Location of Loss Recognized in Income Statement Loss Recognized in Income Statement Year to date total per Income Statement (Millions) As of March 31, 2023 Three Months Ended March 31, 2023 Current Liabilities $ (28) Interest Expense $ 7 $ 95 Non-current liabilities $ (67) Cumulative effect on hedged debt Current debt $ 28 Non-current debt $ 67 Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2022 Three Months Ended March 31, 2022 Current Liabilities $ (29) Interest Expense $ (2) $ 71 Non-current liabilities $ (86) Cumulative effect on hedged debt Current debt $ 29 Non-current debt $ 86
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables' activities as of March 31, 2023 and December 31, 2022, respectively, consisted of: March 31, December 31, As of 2023 2022 (Millions) Wholesale electricity purchase contracts $ 110 $ 149 Wholesale electricity sales contracts (134) (200) Natural gas and other fuel purchase contracts 8 2 Financial power contracts 9 8 Total $ (7) $ (41)
Effect of Derivatives Associated with Renewables and Gas Activities	The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2023 and 2022, consisted of: Three Months Ended March 31, 2023 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (4) $ 1 Wholesale electricity sales contracts 7 24 Financial power contracts 2 15 Financial and natural gas contracts — 10 Total gain included in operating revenues $ 5 $ 50 $ 2,466 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (35) Financial power contracts — — Financial and natural gas contracts — (21) Total loss included in purchased power, natural gas and fuel used $ — $ (56) $ 977 Total Gain (Loss) $ 5 $ (6) Three Months Ended March 31, 2022 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 9 $ 3 Wholesale electricity sales contracts (1) (40) Financial power contracts (2) (21) Financial and natural gas contracts (1) (25) Total gain (loss) included in operating revenues $ 5 $ (83) $ 2,133 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 37 Financial power contracts — 1 Financial and natural gas contracts — 37 Total gain included in purchased power, natural gas and fuel used $ — $ 75 $ 741 Total Gain (Loss) $ 5 $ (8)

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	3 Months Ended
	Mar. 31, 2023
Retirement Benefits [Abstract]
Components of Net Periodic Pension and Postretirement Benefits	The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions) Service cost $ 2 $ 8 Interest cost 30 24 Expected return on plan assets (36) (45) Amortization of: Prior service costs — 1 Actuarial loss 1 18 Curtailments and settlements — 2 Net Periodic Benefit Cost $ (3) $ 8 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions) Service cost $ — $ 1 Interest cost 3 3 Expected return on plan assets (1) (2) Amortization of: Prior service costs — — Actuarial loss (3) (1) Net Periodic Benefit Cost $ (1) $ 1

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2023
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Loss	Accumulated Other Comprehensive Loss for the three months ended March 31, 2023 and 2022, respectively, consisted of: As of December 31, Three Months Ended March 31, As of March 31, As of December 31, Three Months Ended March 31, As of March 31, 2022 2023 2023 2021 2022 2022 (Millions) Gain for defined benefit plans, net of income tax expense of $0 for 2023 and $3 for 2022 $ — $ 8 Amortization of pension cost, net of income tax expense of $0 for 2023 and $0 for 2022 — 1 Net (loss) gain on pension plans (20) — (20) (38) 9 (29) Unrealized (loss) gain from equity method investment, net of income tax expense of $0 for 2023 and $5 for 2022 (a) 13 (1) 12 (9) 15 6 Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(1) for 2023 and $(15) for 2022 (195) (2) (197) (194) (39) (233) Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $18 for 2023 and $4 for 2022 (b) 22 52 74 (32) 11 (21) Loss (gain) on derivatives qualifying as cash flow hedges (173) 50 (123) (226) (28) (254) Accumulated Other Comprehensive Loss $ (180) $ 49 $ (131) $ (273) $ (4) $ (277) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2023
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 245 $ 445 Denominator: Weighted average number of shares outstanding - basic 386,744,996 386,698,132 Weighted average number of shares outstanding - diluted 387,077,213 387,114,285 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.63 $ 1.15 Earnings Per Common Share, Diluted $ 0.63 $ 1.15

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2023
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the three months ended March 31, 2023, consisted of: Three Months Ended March 31, 2023 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,076 $ 390 $ — $ 2,466 Depreciation and amortization 174 105 1 280 Operating income (loss) 277 (10) (2) 265 Earnings (losses) from equity method investments 4 (2) — 2 Interest expense, net of capitalization 70 6 19 95 Income tax expense (benefit) 44 (34) (28) (18) Adjusted net income 195 51 1 248 Capital expenditures 609 227 — 836 As of March 31, 2023 Property, plant and equipment 20,291 10,942 16 31,249 Equity method investments 181 259 — 440 Total assets $ 28,591 $ 13,164 $ (297) $ 41,458 (a) Includes Corporate and intersegment eliminations. Segment information for the three months ended March 31, 2022 and as of December 31, 2022, consisted of: Three Months Ended March 31, 2022 Networks Renewables Other (a) AVANGRID (Millions) Revenue - external $ 1,935 $ 198 $ — $ 2,133 Depreciation and amortization 161 100 — 261 Operating income (loss) 319 (18) 1 302 Earnings from equity method investments 3 250 — 253 Interest expense, net of capitalization 50 3 18 71 Income tax expense (benefit) 31 41 (4) 68 Adjusted net income (loss) 254 211 (15) 450 Capital expenditures 355 454 2 811 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 months ended March 31, 2023 and 2022, respectively, is as follows: Three Months Ended March 31, 2023 2022 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 248 $ 450 Adjustments: Mark-to-market earnings - Renewables (1) (4) (3) Impact of COVID-19 (2) — (2) Income tax impact of adjustments 1 2 Net Income Attributable to Avangrid, Inc. $ 245 $ 445 (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.

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2023
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three months ended March 31, 2023 and 2022, respectively, consisted of: Three Months Ended March 31, 2023 2022 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ — $ (11) $ — $ (12) Iberdrola Renovables Energía, S.L. $ — $ (2) $ — $ (2) Iberdrola Financiación, S.A. $ — $ (4) $ — $ (3) Vineyard Wind $ 2 $ — $ 2 $ — Other $ — $ — $ — $ (1) Related party balances as of March 31, 2023 and December 31, 2022, respectively, consisted of: As of March 31, 2023 December 31, 2022 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ — $ (11) $ 1 $ (29) Iberdrola Financiación, S.A. $ — $ (2) $ — $ (9) Vineyard Wind $ 2 $ (8) $ 3 $ (8) Iberdrola Solutions $ — $ (2) $ — $ (2) Other $ 3 $ (3) $ 4 $ (1)

Other Financial Statement Ite_2

Other Financial Statement Items (Tables)	3 Months Ended
	Mar. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable	Accounts receivable and unbilled revenues, net as of March 31, 2023 and December 31, 2022 consisted of: As of March 31, 2023 December 31, 2022 (Millions) Trade receivables and unbilled revenues $ 1,817 $ 1,892 Allowance for credit losses (148) (155) Accounts receivable and unbilled revenues, net $ 1,669 $ 1,737 The change in the allowance for credit losses for the three months ended March 31, 2023 and 2022 consisted of: Three Months Ended March 31, (Millions) 2023 2022 As of Beginning of Period, $ 155 $ 151 Current period provision 17 20 Write-off as uncollectible (24) (18) As of March 31, $ 148 $ 153
Schedule of Accumulated Depreciation and Amortization	The accumulated depreciation and amortization as of March 31, 2023 and December 31, 2022, respectively, were as follows: March 31, December 31, As of 2023 2022 (Millions) Property, plant and equipment Accumulated depreciation $ 11,789 $ 11,542 Intangible assets Accumulated amortization $ 335 $ 331

Background and Nature Of Oper_2

Background and Nature Of Operations (Details) $ / shares in Units, $ in Millions	May 18, 2021 USD ($) placement $ / shares shares	Apr. 15, 2021	Mar. 31, 2023 $ / shares	Dec. 31, 2022 $ / shares	Mar. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares	Oct. 20, 2020 USD ($) $ / 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
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	3,000
NM Green Holdings, Inc.
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
Iberdrola S.A.
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
Avangrid | Various Shareholders
Nature Of Business [Line Items]
Ownership percentage by noncontrolling owners			14.70%
Avangrid | Iberdrola S.A.
Nature Of Business [Line Items]
Parent company, ownership percentage			81.60%

Revenue - Narrative (Details)

Revenue - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Disaggregation of Revenue [Line Items]
Contract assets	$ 9		$ 9
TCC contract liabilities	16		33
Revenue recognized	17	$ 8
Accounts receivable related to contracts with customers	1,603		1,622
Unbilled contracts receivable	410		$ 541
Revenue, remaining performance obligation, amount	$ 267
Transmission congestion contracts | Minimum
Disaggregation of Revenue [Line Items]
Auction period	6 months
Transmission congestion contracts | Maximum
Disaggregation of Revenue [Line Items]
Auction period	2 years
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term	15 years
Networks
Disaggregation of Revenue [Line Items]
Period between the delivery of promised goods or service and customer payment (or less)	1 year

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 2,289	$ 2,169
Leasing revenue	2	3
Derivative gains (losses)	122	(63)
Alternative revenue programs	37	12
Other revenue	16	12
Total operating revenues	2,466	2,133
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,308	1,170
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	722	721
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	216	220
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4	7
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	55	13
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(16)	38
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Leasing revenue	0	0
Derivative gains (losses)	0	0
Alternative revenue programs	0	0
Other revenue	0	0
Total operating revenues	0	0
Other | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers	2,027	1,913
Leasing revenue	2	3
Derivative gains (losses)	0	0
Alternative revenue programs	37	12
Other revenue	10	7
Total operating revenues	2,076	1,935
Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,308	1,170
Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	722	721
Networks | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(3)	22
Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers	262	256
Leasing revenue	0	0
Derivative gains (losses)	122	(63)
Alternative revenue programs	0	0
Other revenue	6	5
Total operating revenues	390	198
Renewables | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Renewables | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Renewables | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	216	220
Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4	7
Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	55	13
Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ (13)	$ 16

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Mar. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 267
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	179
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	87
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 109
Remaining performance obligation, period	9 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	$ 139
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	$ 85
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	$ 53
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	$ 35
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 23
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 15
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear 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	$ 5
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	$ 10
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	$ 3
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	$ 6
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	$ 1
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	$ 62
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	$ 60
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)

1 Months Ended

3 Months Ended

Apr. 11, 2023

Feb. 16, 2023

Dec. 21, 2022

Oct. 19, 2022

Sep. 09, 2022 USD ($)

Jun. 24, 2022 USD ($)

May 26, 2022 USD ($)

Jul. 14, 2021 USD ($)

Jun. 23, 2021 USD ($)

May 06, 2021 USD ($)

Apr. 15, 2021

Nov. 19, 2020

Mar. 01, 2020

Feb. 19, 2020 USD ($)

Jan. 01, 2019

Jan. 01, 2018

Jan. 01, 2017

Sep. 30, 2021

Mar. 31, 2023 USD ($)

Mar. 31, 2022 USD ($)

Aug. 11, 2022 USD ($)

Jun. 30, 2021 USD ($) hour

Regulatory Assets And Liabilities [Line Items]

Unrecorded regulatory assets

$ 1,012,000,000

Period from letter issuance to file distribution rate case

60 days

Energy legislation settlement agreement, contribution amount

$ 5,000,000

Energy legislation settlement agreement, customers rate credits provided

50,000,000

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

$ 52,000,000

Energy legislation settlement agreement, customers rate credits provided, period

22 months

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

96

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

$ 25

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

$ 250

Civil penalty amount

$ 1,000,000

$ 2,000,000

Unfunded future income tax expense collection period

46 years

UIL Holdings

Regulatory Assets And Liabilities [Line Items]

Business combination merger related rate credits

$ 1,000,000

$ 1,000,000

Rate Change Levelization

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Energy efficiency portfolio standard

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Carrying costs on deferred income tax bonus depreciation

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

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

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Positive benefit adjustment

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Deferred property tax

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Net plant reconciliation

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Transmission congestion contracts

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

New York 2018 winter storm settlement

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Year 1 | PURA

Regulatory Assets And Liabilities [Line Items]

Distribution revenue requirement

$ 102,000,000

Year 2 | PURA

Regulatory Assets And Liabilities [Line Items]

Distribution revenue requirement

17,000,000

Year 3 | PURA

Regulatory Assets And Liabilities [Line Items]

Distribution revenue requirement

17,000,000

Minimum | Theoretical reserve flow thru impact

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

Maximum | Theoretical reserve flow thru impact

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

5 years

Central Maine Power

Regulatory Assets And Liabilities [Line Items]

Distribution revenue requirement

$ 17,000,000

Annual distribution tariff increase percentage

7%

Distribution tariff rate increased based on ROE

9.25%

Distribution tariff rate increased based on equity capital

50%

ROE reduction

1%

Proposed distribution tariff rate decrease based on return on equity

8.25%

Service quality measures for a period

18 months

Deferred income tax recovery period

32 years 6 months

Central Maine Power | Year 1

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

$ 48,000,000

Central Maine Power | Year 2

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

28,000,000

Central Maine Power | Year 3

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

$ 23,000,000

Central Maine Power | Minimum | Year 1

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

$ 45,000,000

Central Maine Power | Minimum | Year 2

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

25,000,000

Central Maine Power | Minimum | Year 3

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

20,000,000

Central Maine Power | Maximum | Year 1

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

50,000,000

Central Maine Power | Maximum | Year 2

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

30,000,000

Central Maine Power | Maximum | Year 3

Regulatory Assets And Liabilities [Line Items]

Estimated revenue change amount

$ 25,000,000

NYSEG and RG&E

Regulatory Assets And Liabilities [Line Items]

Percentage of return on equity

8.80%

Equity ratio for earnings sharing

48%

Equity ratio

50%

Suspension period

11 months

Public utilities, extension of suspension period

30 days

60 days

60 days

NYSEG and RG&E | Subsequent Event

Regulatory Assets And Liabilities [Line Items]

Public utilities, extension of suspension period

30 days

NYSEG and RG&E | Economic development

Regulatory Assets And Liabilities [Line Items]

Regulatory liability, amortization period

3 years

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]

Percentage of return on equity

9.10%

Equity ratio

50%

New distribution rate schedule, period

3 years

Public utilities regulatory authority distribution rate

50%

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

Regulatory Assets And Liabilities [Line Items]

Distribution revenue requirement

$ 54,000,000

SCG | PURA

Regulatory Assets And Liabilities [Line Items]

Percentage of 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]

Percentage of return on equity

9.70%

Equity ratio for earnings sharing

54%

Requested revenue increase amount

$ 5,600,000

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Rate Increases and Delivery Rate Percentages (Details) $ in Millions	Nov. 19, 2020 USD ($)
NYSEG Electric | Year 1
Regulatory Liabilities [Line Items]
Rate Increase	$ 34
Delivery Rate Increase	4.60%
NYSEG Electric | Year 2
Regulatory Liabilities [Line Items]
Rate Increase	$ 46
Delivery Rate Increase	5.90%
NYSEG Electric | Year 3
Regulatory Liabilities [Line Items]
Rate Increase	$ 36
Delivery Rate Increase	4.20%
NYSEG Gas | Year 1
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0%
NYSEG Gas | Year 2
Regulatory Liabilities [Line Items]
Rate Increase	$ 2
Delivery Rate Increase	0.80%
NYSEG Gas | Year 3
Regulatory Liabilities [Line Items]
Rate Increase	$ 3
Delivery Rate Increase	1.60%
RG&E Electric | Year 1
Regulatory Liabilities [Line Items]
Rate Increase	$ 17
Delivery Rate Increase	3.80%
RG&E Electric | Year 2
Regulatory Liabilities [Line Items]
Rate Increase	$ 14
Delivery Rate Increase	3.20%
RG&E Electric | Year 3
Regulatory Liabilities [Line Items]
Rate Increase	$ 16
Delivery Rate Increase	3.30%
RG&E Gas | Year 1
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0%
RG&E Gas | Year 2
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0%
RG&E Gas | Year 3
Regulatory Liabilities [Line Items]
Rate Increase	$ 2
Delivery Rate Increase	1.30%

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Requested Revenue Change (Details) - USD ($) $ in Millions	3 Months Ended
	Aug. 12, 2022	May 26, 2022
NYSEG Electric
Regulatory Liabilities [Line Items]
Requested revenue change	$ 274	$ 274
Requested revenue change, difference	0
NYSEG Gas
Regulatory Liabilities [Line Items]
Requested revenue change	30	43
Requested revenue change, difference	(13)
RG&E Electric
Regulatory Liabilities [Line Items]
Requested revenue change	93	94
Requested revenue change, difference	(1)
RG&E Gas
Regulatory Liabilities [Line Items]
Requested revenue change	32	$ 38
Requested revenue change, difference	$ (6)

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,962	$ 2,768
Less: current portion	489	447
Total non-current regulatory assets	2,473	2,321
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	363	365
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	70	93
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	766	671
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	55	41
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	66	52
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	7	11
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	52	56
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	31	33
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	1	1
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	9	56
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	247	248
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	62	64
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	20	19
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	504	492
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	135	137
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	20
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	57	55
COVID-19 cost recovery and late payment surcharge
Regulatory Assets [Line Items]
Total regulatory assets	14	17
Low income arrears forgiveness
Regulatory Assets [Line Items]
Total regulatory assets	68	31
Excess generation service charge
Regulatory Assets [Line Items]
Total regulatory assets	77	24
System Expansion
Regulatory Assets [Line Items]
Total regulatory assets	16	21
Non-bypassable charge
Regulatory Assets [Line Items]
Total regulatory assets	46	14
Hedges losses
Regulatory Assets [Line Items]
Total regulatory assets	50	13
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 226	$ 234

Regulatory Assets and Liabili_7

Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,236	$ 3,269
Less: current portion	352	354
Total non-current regulatory liabilities	2,884	2,915
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	25	30
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	15
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	112	117
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	5	9
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	3
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,218	1,232
Rate Change Levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	25
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	8	13
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,167	1,178
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	20
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	16
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3	3
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	17
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	11
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	27	32
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	36	36
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	31
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	10
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	22
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	18
Earning sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	8	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	19	18
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	27
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1	1
Non by-passable charges
Regulatory Liabilities [Line Items]
Total regulatory liabilities	63	76
Transmission revenue reconciliation mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	73	75
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 251	$ 204

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Fair value of debt	$ 8,168	$ 7,991
Restricted Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 3	$ 3
NYSEG and RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of electric load obligations hedged	70%
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	Mar. 31, 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	(159)	(222)
Derivative assets	169	200
Netting adjustment	317	394
Derivative liabilities	(233)	(297)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(137)	(177)
Derivative assets	70	80
Netting adjustment	288	364
Derivative liabilities	(84)	(125)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(22)	(45)
Derivative assets	8	3
Netting adjustment	29	30
Derivative liabilities	(1)	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	(53)	(57)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	90	116
Netting adjustment	0	0
Derivative liabilities	(95)	(115)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	29	35
Derivative assets, before netting	15	38
Derivative liabilities, before netting	(65)	(50)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	15	37
Derivative liabilities, before netting	(55)	(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	(10)	(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	13	13
Derivative assets, before netting	174	218
Derivative liabilities, before netting	(360)	(491)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	58	55
Derivative liabilities, before netting	(245)	(350)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	26	47
Derivative liabilities, before netting	(20)	(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	90	116
Derivative liabilities, before netting	(95)	(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	139	166
Derivative liabilities, before netting	(125)	(150)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	134	165
Derivative liabilities, before netting	(72)	(93)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	4	0
Derivative liabilities, before netting	0	0
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	1	1
Derivative liabilities, before netting	(53)	(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
	Mar. 31, 2023	Mar. 31, 2022
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value Beginning of Period,	$ 16	$ (69)
Gains recognized in operating revenues	0	38
(Losses) recognized in operating revenues	$ (3)	$ (40)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues
Total losses recognized in operating revenues	$ (3)	$ (2)
Gains recognized in OCI	11	2
(Losses) recognized in OCI	$ (3)	$ (63)
Fair Value, Recurring Basis Unobservable Input Reconciliation, Net Derivative Asset (Liability), Gain (Loss), Statement Of Other Comprehensive Income, Extensible List Not Disclosed Flag	Total gains (losses) recognized in OCI	Total gains (losses) recognized in OCI
Total gains or losses recognized in OCI	$ 8	$ (61)
Net change recognized in regulatory assets and liabilities	4	4
Purchases	9	(1)
Settlements	(20)	5
Fair Value as of March 31,	14	(124)
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$ (3)	$ (2)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price	Mar. 31, 2023 $ / MWh $ / MMBTU
NYMEX | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	4.53
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	3.20
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	1.23
Ameren | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	54.23
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	22.08
COB | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	80.39
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	49.88
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	18.78
ERCOT S hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	49.97
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	77.60
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	55.26
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	24.44
PJM W hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	58.12
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	24.76

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details) - Contracts for differences - Level 3	Mar. 31, 2023 $ / kilowatt-MonthOfEnergy
Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0076
Minimum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0360
Minimum | Measurement Input, Commodity Forward Price
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	2
Maximum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0381
Maximum | Measurement Input, Commodity Forward Price
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	3.80

Derivative Instruments and He_3

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 169	$ 200
Derivative Liability	(233)	(297)
Cash collateral receivable, Asset	(96)	(97)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	1	0
Cash collateral 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	13	30
Derivative liabilities	(12)	(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 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	(59)	(28)
Cash collateral receivable, Liability	41	11
Total derivatives as presented in the balance sheet, Liability	(18)	(17)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	12	30
Derivative liabilities	(71)	(58)
Derivative Liability	(59)	(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 Liability	0	0
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(44)	(43)
Cash collateral receivable, Liability	8	2
Total derivatives as presented in the balance sheet, Liability	(36)	(41)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	7
Derivative liabilities	(47)	(50)
Derivative Liability	(44)	(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 Liability	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	64	60
Cash collateral receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	64	60
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	106	121
Derivative liabilities	(42)	(61)
Derivative Asset	64	60
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	103	139
Cash collateral receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	103	139
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	49	63
Derivative liabilities	(36)	(40)
Derivative Asset	13	23
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	90	116
Derivative liabilities	0	0
Derivative Asset	90	116
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(122)	(192)
Cash collateral receivable, Liability	70	105
Total derivatives as presented in the balance sheet, Liability	(52)	(87)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	53	79
Derivative liabilities	(77)	(103)
Derivative Liability	(24)	(24)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	0
Derivative liabilities	(102)	(168)
Derivative Liability	(98)	(168)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(71)	(91)
Cash collateral receivable, Liability	39	54
Total derivatives as presented in the balance sheet, Liability	(32)	(37)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	4
Derivative liabilities	(6)	(7)
Derivative Liability	(1)	(3)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	1
Derivative liabilities	(74)	(89)
Derivative Liability	$ (70)	$ (88)

Derivative Instruments and He_4

Derivative Instruments and Hedging - Net Notional Volume (Details) MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2023 USD ($) MMBTU MWh	Dec. 31, 2022 USD ($) MWh MMBTU
Networks | Wholesale electricity purchase contracts (MWh) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	5.6	5.7
Networks | Natural gas purchase contracts (Dth) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	7.9	9.6
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value | $	$ (7)	$ (41)
Renewables | Wholesale electricity purchase contracts (MWh) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	2	2
Derivative assets (liabilities), fair value | $	$ 110	$ 149
Renewables | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	7	7
Derivative assets (liabilities), fair value | $	$ (134)	$ (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	20	15
Derivative assets (liabilities), fair value | $	$ 8	$ 2
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	6	6
Derivative assets (liabilities), fair value | $	$ 9	$ 8
Renewables | Basis swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	26	22
Renewables | Basis swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	2	0

Derivative Instruments and He_5

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Derivative liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 4	$ 4
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	40		$ 9
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	49	(45)
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	10		$ 4
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 6	$ (9)

Derivative Instruments and He_6

Derivative Instruments and Hedging - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2023 USD ($) instrument	Mar. 31, 2022 USD ($)	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	$ 2,962		$ 2,768
Regulatory liabilities	3,236		3,269
Derivative assets	104		140
Derivative liability	233		297
Aggregate fair value of additional collateral	40
Cash collateral pledged	96		97
Collateral already posted	$ 50
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative instruments | instrument	2
Derivative liability	$ 53		57
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	$ 0
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(2)	(2)
Cash Flow Hedging | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Expected amortization of discontinued cash flow hedges in 2022	7
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	36		38
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	2
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(1)	(1)
Expected amortization of discontinued cash flow hedges in 2022	3
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	42		43
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	113	(168)
Renewables | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	90	$ (56)
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	(99)
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount				$ 956		$ 935
Derivative assets	$ 90		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
Regulatory assets	52		56
Gross amounts of recognized liabilities	53		57
Regulatory liabilities	$ 0		0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	80%
Gross derivative asset	$ 0		0
Gross amounts of recognized liabilities	$ 52		$ 55

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest expense	$ 95	$ 71
Purchased power, natural gas and fuel used	977	741
Revenues	2,466	2,133
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	2
Loss (Gain) Reclassified from Accumulated OCI into Income	1	0
Revenues	2,076	1,935
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	113	(168)
Loss (Gain) Reclassified from Accumulated OCI into Income	66	11
Revenues	390	198
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0
Interest rate contracts | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	2	2
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	1	1
Interest rate contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	90	(56)
Loss (Gain) Reclassified from Accumulated OCI into Income	0	0
Interest expense	95	71
Commodity contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	0	2
Loss (Gain) Reclassified from Accumulated OCI into Income	0	(1)
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	23	(112)
Loss (Gain) Reclassified from Accumulated OCI into Income	66	11
Revenues	$ 2,466	$ 2,133

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Mar. 31, 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	9	8
Long | Wholesale electricity purchase contracts (MWh)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	110	149
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	8	2
Short | Wholesale electricity purchase contracts (MWh)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (134)	$ (200)

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 122	$ (63)
Operating revenues	2,466	2,133
Utilities operating expense, purchased power	$ 977	$ 741
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
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 122	$ (63)
Operating revenues	390	198
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	5	5
Renewables | Trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 5	$ 5
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
Renewables | Trading | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 0	$ 0
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
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Long | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (4)	$ 9
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Long | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	7	(1)
Renewables | Trading | Financial power contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	2	(2)
Renewables | Trading | Financial power contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0
Renewables | Trading | Financial and natural gas contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	(1)
Renewables | Trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(6)	(8)
Operating revenues	2,466	2,133
Utilities operating expense, purchased power	977	741
Renewables | Non-trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 50	$ (83)
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
Renewables | Non-trading | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (56)	$ 75
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
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Long | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 1	$ 3
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Long | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(35)	37
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	24	(40)
Renewables | Non-trading | Financial power contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	15	(21)
Renewables | Non-trading | Financial power contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	1
Renewables | Non-trading | Financial and natural gas contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	10	(25)
Renewables | Non-trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ (21)	$ 37

Derivative Instruments and H_10

Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) loss on fair value hedges recognized in Income Statement	$ 7	$ (2)
Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(28)		$ (29)
Non-current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(67)		(86)
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	28		29
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	67		$ 86
Fair Value Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Year to date total per Income Statement	$ 95	$ 71

Contingencies and Commitments (

Contingencies and Commitments (Details) $ in Millions

1 Months Ended

12 Months Ended

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

Dec. 31, 2021 USD ($)

Dec. 31, 2001 plaintiff

Mar. 31, 2023 USD ($)

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

Approved return on equity

9.88%

Regulatory liabilities

$ 2,884

$ 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

Number of plaintiffs | plaintiff

2

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

693

Future payments committed

$ 90

NECEC commitment, payment during period

$ 9

Complaint II

Loss Contingencies [Line Items]

Regulatory liabilities

28

Complaint III

Loss Contingencies [Line Items]

Regulatory liabilities

8

Complaint II and III

Loss Contingencies [Line Items]

Reasonably possible loss, in additional reserve, pre tax

$ 17

California Energy Crisis Litigation

Loss Contingencies [Line Items]

Price of the power purchase agreements

$ 259

Requested renewables delay from preliminary proposed ruling period

2 years

Customer Service Invoice Dispute

Loss Contingencies [Line Items]

Litigation settlement, adjustment amount requested

$ 29

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Approved return on equity

10.57%

Number of claims | complaint

4

Unfavorable Regulatory Action | Complaint I | Max.

Loss Contingencies [Line Items]

Approved return on equity

11.74%

11.74%

Unfavorable Regulatory Action | Complaint II

Loss Contingencies [Line Items]

Approved return on equity

9.59%

Refund period

15 months

Unfavorable Regulatory Action | Complaint II | Max.

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Refund period

15 months

Unfavorable Regulatory Action | Complaint III | Max.

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Before Amendment

Loss Contingencies [Line Items]

Requested return on equity base percentage

11.14%

Environmental Liabilities (Deta

Environmental Liabilities (Details)	3 Months Ended	12 Months Ended		80 Months Ended
	Mar. 31, 2023 USD ($) site	Dec. 31, 2011 site	Dec. 31, 2008 site	Mar. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Aug. 04, 2016 USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	24
Number of sites with liability recorded	7
Number of sits note expected to incur additional liabilities	17
Number of additional sites with liability recorded	12
Number of sites where gas was manufactured in the past	53
Number of sites for which we have entered into consent orders to investigate and remediate	41
Accrual related to investigation and remediation | $	$ 282,000,000			$ 282,000,000	$ 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
Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	14,000,000			14,000,000
Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 22,000,000			22,000,000
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	16
Number of sites where gas was manufactured in the past	6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	4
Number of sites where gas was manufactured in the past	1
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	0
Number of sites where gas was manufactured in the past	1
Massachusetts Non-Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	6
Hazardous Substances Waste Sites With Liability Recorded
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 7,000,000			7,000,000
Hazardous Substances Waste Sites Will Incur Remediation And / Or Monitoring Costs
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 9,000,000			9,000,000
New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order Of Consent
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past	39
Sites With Individual NYSDEC Orders Of Consent
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 | $	154,000,000			154,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	255,000,000			255,000,000
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 | $	9,000,000			9,000,000
RG&E | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 7,000,000			$ 7,000,000
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites for which we have entered into consent orders to investigate and remediate	3

Post-retirement and Similar O_3

Post-retirement and Similar Obligations - Additional Information (Details)	3 Months Ended
	Mar. 31, 2023 USD ($)
Retirement Benefits [Abstract]
Defined benefit, pension contributions	$ 0
Expected future employer contributions in current fiscal year	$ 0

Post-retirement and Similar O_4

Post-retirement and Similar Obligations - Periodic Benefit Costs Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 8
Interest cost	30	24
Expected return on plan assets	(36)	(45)
Prior service costs	0	1
Actuarial loss	1	18
Curtailments and settlements	0	2
Net Periodic Benefit Cost	(3)	8
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	1
Interest cost	3	3
Expected return on plan assets	(1)	(2)
Prior service costs	0	0
Actuarial loss	(3)	(1)
Net Periodic Benefit Cost	$ (1)	$ 1

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021	May 18, 2021
Class of Stock [Line Items]
Treasury stock, shares (in shares)	108,188		108,188
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Release of common stock held in trust (in shares)	0	0
Treasury shares (in shares)	997,983
Repurchases of common stock	$ 47		$ 47
Iberdrola Renewables Holding Inc
Class of Stock [Line Items]
Percentage of equity owned by parent	81.50%
Convertible Preferred Stock
Class of Stock [Line Items]
Convertible preferred stock, shares outstanding (in shares)	0		0
Common Stock
Class of Stock [Line Items]
Issuances of common stock (in shares)	12,332	56,127

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	$ 20,342	$ 19,961
Other comprehensive income (loss), net of tax	49	(4)
Balance, end of period	20,510	20,060
Gain for defined benefit plans, income tax expense	0	3
Amortization of pension cost, income tax expense	0	0
Unrealized (loss) gain from equity method investment, income tax expense	0	5
Unrealized loss during period on derivatives qualifying as cash flow hedges, income tax benefit	(1)	(15)
Reclassification to net income of loss on cash flow hedges, income taxes	18	4
Gain for defined benefit plans, net of income tax expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income (loss), net of tax	0	8
Amortization of pension cost, net of income tax expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Other comprehensive income (loss), net of tax	0	1
Net (loss) gain on pension plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(20)	(38)
Other comprehensive income (loss), net of tax	0	9
Balance, end of period	(20)	(29)
Unrealized (loss) gain from equity method investment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	13	(9)
Other comprehensive income (loss), net of tax	(1)	15
Balance, end of period	12	6
Unrealized loss during period on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(195)	(194)
Other comprehensive income (loss), net of tax	(2)	(39)
Balance, end of period	(197)	(233)
Reclassification to net income of losses on cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	22	(32)
Other comprehensive income (loss), net of tax	52	11
Balance, end of period	74	(21)
Loss (gain) on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(173)	(226)
Other comprehensive income (loss), net of tax	50	(28)
Balance, end of period	(123)	(254)
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(180)	(273)
Other comprehensive income (loss), net of tax	49	(4)
Balance, end of period	$ (131)	$ (277)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Numerator:
Net income attributable to AVANGRID, basic	$ 245	$ 445
Net income attributable to AVANGRID, diluted	$ 245	$ 445
Denominator:
Weighted average number of shares outstanding - basic (in shares)	386,744,996	386,698,132
Weighted average number of shares outstanding - diluted (in shares)	387,077,213	387,114,285
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)	$ 0.63	$ 1.15
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.63	$ 1.15

Segment Information - Additiona

Segment Information - Additional Information (Details)	3 Months Ended
	Mar. 31, 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
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022
Segment Reporting Information [Line Items]
Revenues	$ 2,466	$ 2,133
Depreciation and amortization	280	261
Operating income (loss)	265	302
Earnings (losses) from equity method investments	2	253
Interest expense, net of capitalization	95	71
Income tax expense (benefit)	(18)	68
Adjusted net income (loss)	248	450
Capital expenditures	836	811
Property, plant and equipment	31,249		$ 30,994
Equity method investments	440		437
Total assets	41,458		41,123
Other
Segment Reporting Information [Line Items]
Revenues	0	0
Depreciation and amortization	1	0
Operating income (loss)	(2)	1
Earnings (losses) from equity method investments	0	0
Interest expense, net of capitalization	19	18
Income tax expense (benefit)	(28)	(4)
Adjusted net income (loss)	1	(15)
Capital expenditures	0	2
Property, plant and equipment	16		17
Equity method investments	0		0
Total assets	(297)		(499)
Networks
Segment Reporting Information [Line Items]
Revenues	2,076	1,935
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenues	2,076	1,935
Depreciation and amortization	174	161
Operating income (loss)	277	319
Earnings (losses) from equity method investments	4	3
Interest expense, net of capitalization	70	50
Income tax expense (benefit)	44	31
Adjusted net income (loss)	195	254
Capital expenditures	609	355
Property, plant and equipment	20,291		20,027
Equity method investments	181		171
Total assets	28,591		28,069
Renewables
Segment Reporting Information [Line Items]
Revenues	390	198
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenues	390	198
Depreciation and amortization	105	100
Operating income (loss)	(10)	(18)
Earnings (losses) from equity method investments	(2)	250
Interest expense, net of capitalization	6	3
Income tax expense (benefit)	(34)	41
Adjusted net income (loss)	51	211
Capital expenditures	227	$ 454
Property, plant and equipment	10,942		10,950
Equity method investments	259		266
Total assets	$ 13,164		$ 13,553

Segment Information - Reconcili

Segment Information - Reconciliation of Adjusted Net Income to Net Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 248	$ 450
Adjustments:
Mark-to-market earnings - Renewables	(4)	(3)
Impact of COVED -19	0	(2)
Income tax impact of adjustments	1	2
Net Income Attributable to Avangrid, Inc.	$ 245	$ 445

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To	$ 0	$ 0
Purchases From	(11)	(12)
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Sales To	0	0
Purchases From	(2)	(2)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Sales To	0	0
Purchases From	(4)	(3)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	2	2
Purchases From	0	0
Other
Related Party Transaction [Line Items]
Sales To	0	0
Purchases From	$ 0	$ (1)

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	$ 0	$ 1
Owed To	(11)	(29)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(2)	(9)
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	2	3
Owed To	(8)	(8)
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(2)	(2)
Other
Related Party Transaction [Line Items]
Owed By	3	4
Owed To	$ (3)	$ (1)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2023	Dec. 31, 2022
Iberdrola Solutions
Related Party Transaction [Line Items]
Notes payable	$ 2,000,000	$ 2,000,000
Affiliated Entity
Related Party Transaction [Line Items]
Impairments	0
Iberdrola
Related Party Transaction [Line Items]
Deposit balance	0	0
Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Credit facility fees percentage	0.105%
Credit facility, amount outstanding	$ 0	$ 0

Other Financial Statement Ite_3

Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Trade receivables and unbilled revenues	$ 1,817	$ 1,892
Allowance for credit losses	(148)	(155)
Accounts receivable and unbilled revenues, net	$ 1,669	$ 1,737

Other Financial Statement Ite_4

Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 148	$ 153
Current period provision	17	20
Write-off as uncollectible	(24)	(18)
Ending balance	$ 155	$ 151

Other Financial Statement Ite_5

Other Financial Statement Items - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022	Dec. 31, 2022	Dec. 31, 2021
Supplemental Balance Sheet Information [Line Items]
Allowance for doubtful accounts, deferred payment arrangement	$ 148	$ 153	$ 155	$ 151
Provision for doubtful accounts, accounts receivable	17	20
Prepaid other taxes	194		136
Accrued liabilities for property, plant and equipment additions	239	122
Commercial paper	1,090		397
Advances received	268		271
AVANGRID Credit Facility
Supplemental Balance Sheet Information [Line Items]
Short-term debt	$ 200		$ 0
Weighted-average interest rate on outstanding short-term borrowings	6.05%
Commercial Paper
Supplemental Balance Sheet Information [Line Items]
Weighted-average interest rate	5.33%		4.66%
Supplier Financing Arrangements
Supplemental Balance Sheet Information [Line Items]
Weighted-average interest rate	6.12%		5.48%
Short-term debt	$ 4		$ 171
Deferred Payment Arrangements
Supplemental Balance Sheet Information [Line Items]
Accounts receivable	102		102
Allowance for doubtful accounts, deferred payment arrangement	40		$ 42
Provision for doubtful accounts, accounts receivable	$ (2)	$ 3

Other Financial Statement Ite_6

Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Mar. 31, 2023	Dec. 31, 2022
Property, plant and equipment
Accumulated depreciation	$ 11,789	$ 11,542
Intangible assets
Accumulated amortization	$ 335	$ 331

Income Tax Expense (Details)

Income Tax Expense (Details)	3 Months Ended
	Mar. 31, 2023	Mar. 31, 2022
Income Tax Disclosure [Abstract]
Effective income tax rate	(9.10%)	13.70%

Stock-Based Compensation Expe_2

Stock-Based Compensation Expense (Details) $ / shares in Units, $ in Millions		1 Months Ended						3 Months Ended
	Apr. 12, 2023 installment shares	Mar. 31, 2023 USD ($) installment shares	Feb. 28, 2023 USD ($) installment shares	Jan. 31, 2023 shares	Jun. 30, 2022 installment $ / shares shares	Feb. 28, 2022 installment shares	Mar. 31, 2021 installment $ / shares shares	Mar. 31, 2023 USD ($)	Mar. 31, 2022 USD ($)	Dec. 31, 2022 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $								$ 4	$ 5
Performance Shares Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)		677,752
Number of vesting installments | installment		3
Performance Shares Units (PSUs) | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	487,000
Number of vesting installments | installment	3
Restricted Stock Units (RSUs) | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)					25,000		5,000
Number of vesting installments | installment					2		1
Grant date fair value (in dollars per share) | $ / shares					$ 47.64		$ 48.83
Number of shares issued (in shares)		3,642		8,690
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 | $			$ 0.1
Share based compensation liability | $		$ 1						$ 1		$ 0

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions		1 Months Ended
	Apr. 29, 2022	Mar. 31, 2023	Dec. 31, 2022
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)		$ 41,458	$ 41,123
Liabilities of variable interest entities (VIEs)		20,948	20,781
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)		2,806	2,853
Liabilities of variable interest entities (VIEs)		388	$ 424
Solis I
Variable Interest Entity [Line Items]
TEF agreement, investment amount received from tax equity investor	$ 14	$ 61

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) a easement	Mar. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Jan. 10, 2022 USD ($)	Sep. 15, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 440	$ 437
Vineyard Wind 1, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50%		50%
Vineyard Wind, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		50%
Number of easements | easement		2
Equity method investments			$ 7	$ 9
Vineyard Wind, LLC | Lease Area 501
Schedule of Equity Method Investments [Line Items]
Area of land (in acres) | a		166,886
Vineyard Wind, LLC | 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
	Apr. 12, 2023	Mar. 31, 2023	Mar. 31, 2022
Subsequent Event [Line Items]
Dividends declared (in dollars per share)		$ 0.44	$ 0.44
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share)	$ 0.44