10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

☒ QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended March 31, 2024

Or

☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from                   to                  i

Commission File No. 001-37660

Avangrid, Inc.

(Exact Name of Registrant as Specified in its Charter)

New York		14-1798693
(State or other jurisdiction of incorporation or organization)		(I.R.S. Employer Identification No.)
180 Marsh Hill Road
Orange,	Connecticut	06477
(Address of principal executive offices)		(Zip Code)

Registrant’s telephone number, including area code: (207) 629-1190

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of exchange on which registered
Common Stock, par value $0.01 per share	AGR	New York Stock Exchange

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days.    Yes  ☒    No  ☐

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ☒    No  ☐

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, smaller reporting company, or an emerging growth company. See the definitions of “large accelerated filer,” “accelerated filer,” “smaller reporting company,” and “emerging growth company” in Rule 12b-2 of the Exchange Act.  

Large Accelerated Filer	☒	Accelerated Filer	☐
Non-accelerated Filer	☐	Smaller Reporting Company	☐
Emerging Growth Company	☐

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes  ☐    No  ☒

As of April 23, 2024, the registrant had 386,906,260 shares of common stock, par value $0.01, outstanding.

Avangrid, Inc.

REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2024

INDEX

GLOSSARY OF TERMS AND ABBREVIATIONS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	44
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	58
Item 4.	Controls and Procedures	58
PART II. OTHER INFORMATION		59
Item 1.	Legal Proceedings	59
Item 1A.	Risk Factors	59
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	59
Item 3.	Defaults Upon Senior Securities	59
Item 4.	Mine Safety Disclosures	59
Item 5.	Other Information	59
Item 6.	Exhibits	60
SIGNATURES		61

2

GLOSSARY OF TERMS AND ABBREVIATIONS

Unless the context indicates otherwise, the terms “we,” “our” and the “Company” are used to refer to Avangrid, Inc. and its subsidiaries.

2023 Joint Proposal	Joint proposal of NYSEG and RG&E and certain other signatory parties approved by the NYPSC on October 12, 2023, for a three-year rate plan for electric and gas service with effective date November 1, 2023.
AOCI	Accumulated other comprehensive income
ARHI	Avangrid Renewables Holdings, Inc.
ARP	Alternative Revenue Programs
ASC	Accounting Standards Codification
Avangrid	Avangrid, Inc.
BGC	The Berkshire Gas Company
PBR	Performance-Based Regulation
CAIDI	Customer Average Interruption Duration Index
CfDs	Contracts for Differences
CBP	U.S. Customs and Border Protection
CFIUS	Committee on Foreign Investment in the United States
CL&P	The Connecticut Light and Power Company
CMP	Central Maine Power Company
CNG	Connecticut Natural Gas Corporation
DEEP	Connecticut Department of Energy and Environmental Protection
DIMP	Distribution Integrity Management Program
DOC	Department of Commerce
DPA	Deferred Payment Arrangements
DPU	Massachusetts Department of Public Utilities
EBITDA	Earnings before interest, taxes, depreciation and amortization
ESM	Earnings sharing mechanism
English Station	The former generation site on the Mill River in New Haven, Connecticut
Exchange Act	The Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
FirstEnergy	FirstEnergy Corp.
Form 10-K	Avangrid, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2023, filed with the Securities and Exchange Commission on February 22, 2024.
HLBV	Hypothetical Liquidation at Book Value
HSR	Hart-Scott-Rodino Antitrust Improvements Act of 1976
IRA	Inflation Reduction Act
Iberdrola	Iberdrola, S.A.
Iberdrola Group	The group of companies controlled by Iberdrola, S.A.
Installed capacity	The production capacity of a power plant or wind farm based either on its rated (nameplate) capacity or actual capacity.
ISO	Independent system operator
Klamath Plant	Klamath gas-fired cogeneration facility located in the city of Klamath, Oregon.
KW	Kilowatts
MNG	Maine Natural Gas Corporation
MPUC	Maine Public Utility Commission
MtM	Mark-to-market
MW	Megawatts
MWh	Megawatt-hours
NECEC	New England Clean Energy Connect
Networks	Avangrid Networks, Inc.
Non-GAAP	Financial measures that are not prepared in accordance with U.S. GAAP, including adjusted net income, adjusted earnings per share, adjusted EBITDA and adjusted EBITDA with tax credits.
NRC	Nuclear Regulatory Commission
NYPSC	New York State Public Service Commission
NYSE	New York Stock Exchange
NYSEG	New York State Electric & Gas Corporation
NYSERDA	New York State Energy Research and Development Authority
OCI	Other comprehensive income
PJM	PJM Interconnection, L.L.C.
PURA	Connecticut Public Utilities Regulatory Authority
Renewables	Avangrid Renewables, LLC
RDM	Revenue Decoupling Mechanism
RG&E	Rochester Gas and Electric Corporation
ROE	Return on equity
SAIFI	System Average Interruption Frequency Index
SCG	The Southern Connecticut Gas Company
SEC	United States Securities and Exchange Commission
SOFR	Secured Overnight Financing Rate
Tax Act	Tax Cuts and Jobs Act of 2017 enacted by the U.S. federal government on December 22, 2017
TEF	Tax equity financing arrangements
UFLPA	Uyghur Forced Labor Prevention Act
UI	The United Illuminating Company
UIL	UIL Holdings Corporation
U.S. GAAP	Generally accepted accounting principles for financial reporting in the United States.
VIEs	Variable interest entities

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PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(unaudited)

	Three Months Ended March 31,
	2024		2023
(Millions, except for number of shares and per share data)
Operating Revenues	$	2,417	$	2,466
Operating Expenses
Purchased power, natural gas and fuel used	724		977
Operations and maintenance	792		761
Depreciation and amortization	298		280
Taxes other than income taxes	196		183
Total Operating Expenses	2,010		2,201
Operating Income	407		265
Other Income and (Expense)
Other income	54		25
Earnings from equity method investments	6		2
Interest expense, net of capitalization	(125)		(95)
Income Before Income Tax	342		197
Income tax expense (benefit)	20		(18)
Net Income	322		215
Net loss attributable to noncontrolling interests	29		30
Net Income Attributable to Avangrid, Inc.	$	351	$	245
Earnings Per Common Share, Basic	$	0.91	$	0.63
Earnings Per Common Share, Diluted	$	0.91	$	0.63
Weighted-average Number of Common Shares Outstanding:
Basic	386,916,234		386,744,996
Diluted	387,239,544		387,077,213

The accompanying notes are an integral part of our condensed consolidated financial statements.

4

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three Months Ended March 31,
	2024		2023
(Millions)
Net Income	$	322	$	215
Other Comprehensive Income
Unrealized loss from equity method investment, net of income taxes of $0 and $0, respectively	—		(1)
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $15 and $(1), respectively	39		(2)
Reclassification to net income of loss on cash flow hedges, net of income taxes $2 and $18, respectively	7		52
Other Comprehensive Income	46		49
Comprehensive Income	368		264
Net loss attributable to noncontrolling interests	29		30
Comprehensive Income Attributable to Avangrid, Inc.	$	397	$	294

The accompanying notes are an integral part of our condensed consolidated financial statements.

5

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	March 31,		December 31,
As of	2024		2023
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	152	$	91
Accounts receivable and unbilled revenues, net	1,640		1,588
Accounts receivable from affiliates	5		11
Notes receivable from affiliates	4		4
Derivative assets	87		68
Fuel and gas in storage	169		185
Materials and supplies	321		310
Prepayments and other current assets	496		429
Regulatory assets	745		718
Total Current Assets	3,619		3,404
Total Property, Plant and Equipment ($2,621 and $2,643 related to VIEs, respectively)	33,323		32,857
Operating lease right-of-use assets	204		195
Equity method investments	836		718
Other investments	49		46
Regulatory assets	3,061		2,811
Other Assets
Goodwill	3,119		3,119
Intangible assets	280		284
Derivative assets	185		162
Other	386		393
Total Other Assets	3,970		3,958
Total Assets	$	45,062	$	43,989

The accompanying notes are an integral part of our condensed consolidated financial statements.

6

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	March 31,		December 31,
As of	2024		2023
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	729	$	612
Notes payable	1,862		1,347
Notes payable to affiliates	515		13
Interest accrued	116		104
Accounts payable and accrued liabilities	1,769		1,924
Accounts payable to affiliates	18		—
Dividends payable	171		170
Taxes accrued	88		66
Operating lease liabilities	15		16
Derivative liabilities	66		64
Other current liabilities	584		662
Regulatory liabilities	275		261
Total Current Liabilities	6,208		5,239
Regulatory liabilities	2,676		2,694
Other Non-current Liabilities
Deferred income taxes	2,501		2,451
Deferred income	979		996
Pension and other postretirement	546		554
Operating lease liabilities	208		199
Derivative liabilities	116		111
Asset retirement obligations	310		306
Environmental remediation costs	243		254
Other	527		525
Total Other Non-current Liabilities	5,430		5,396
Non-current debt	9,059		9,184
Non-current debt to affiliate	800		800
Total Non-current Liabilities	17,965		18,074
Total Liabilities	24,173		23,313
Commitments and Contingencies	—		—
Equity
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 388,008,132 and 387,872,787 shares issued; 386,906,260 and 386,770,915 shares outstanding, respectively	4		4
Additional paid in capital	17,702		17,701
Treasury stock	(47)		(47)
Retained earnings	2,196		2,015
Accumulated other comprehensive income (loss)	21		(25)
Total Stockholders’ Equity	19,876		19,648
Non-controlling interests	1,013		1,028
Total Equity	20,889		20,676
Total Liabilities and Equity	$	45,062	$	43,989

The accompanying notes are an integral part of our condensed consolidated financial statements.

7

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Three Months Ended March 31,
	2024		2023
(Millions)
Cash Flow from Operating Activities:
Net income	$	322	$	215
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	298		280
Regulatory assets/liabilities amortization and carrying cost	15		(32)
Pension cost	(3)		(3)
Earnings from equity method investments	(6)		(2)
Distributions of earnings received from equity method investments	3		6
Unrealized (gain) loss on marked-to-market derivative contracts	(17)		4
Deferred taxes	4		(1)
Other non-cash items	(22)		(5)
Changes in operating assets and liabilities:
Current assets	(141)		82
Noncurrent assets	(255)		(96)
Current liabilities	(32)		(242)
Noncurrent liabilities	(13)		(2)
Net Cash Provided by Operating Activities	153		204
Cash Flow from Investing Activities:
Capital expenditures	(872)		(836)
Contributions in aid of construction	40		19
Proceeds from sale of assets	2		6
Proceeds from notes receivable from affiliates	—		1
Distributions received from equity method investments	2		2
Other investments and equity method investments, net	(116)		(11)
Net Cash Used in Investing Activities	(944)		(819)
Cash Flow from Financing Activities:
Repayments of non-current debt	(3)		(4)
Receipts of other short-term debt, net	514		722
Receipts of other short-term debt with affiliates	500		—
Repayments of financing leases	(1)		(1)
Issuance of common stock	(2)		—
Distributions to noncontrolling interests	(39)		(3)
Contributions from noncontrolling interests	53		74
Dividends paid	(170)		(170)
Net Cash Provided by Financing Activities	852		618
Net Increase in Cash, Cash Equivalents and Restricted Cash	61		3
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	94		72
Cash, Cash Equivalents and Restricted Cash, End of Period	$	155	$	75
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	103	$	56
Cash paid (refunded) for income taxes	$	3	$	(1)

The accompanying notes are an integral part of our condensed consolidated financial statements.

8

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Changes in Equity

(unaudited)

	Avangrid, Inc. Stockholders
(Millions, except for number of shares )	Number of shares (*)	Common Stock		Additional paid-in capital		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Loss		Total Stockholders’ Equity		Noncontrolling Interests		Total
As of December 31, 2022	386,628,586	$	3	$	17,694	$	(47)	$	1,910	$	(180)	$	19,380	$	962	$	20,342
Net income (loss)	—	—		—		—		245		—		245		(30)		215
Other comprehensive loss, net of tax of $17	—	—		—		—		—		49		49		—		49
Comprehensive income																264
Dividends declared, $0.44/share	—	—		—		—		(170)		—		(170)		—		(170)
Issuance of common stock	12,332	—		—		—		—		—		—		—		—
Stock-based compensation	—	—		3		—		—		—		3		—		3
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3)		(3)
Contributions from noncontrolling interests	—	—		—		—				—		—		74		74
As of March 31, 2023	386,640,918	$	3	$	17,697	$	(47)	$	1,985	$	(131)	$	19,507	$	1,003	$	20,510
As of December 31, 2023	386,770,915	$	4	$	17,701	$	(47)	$	2,015	$	(25)	$	19,648	$	1,028	$	20,676
Net income (loss)	—	—		—		—		351		—		351		(29)		322
Other comprehensive income, net of tax of $17	—	—		—		—		—		46		46		—		46
Comprehensive income																368
Dividends declared, $0.44/share	—	—		—		—		(170)		—		(170)		—		(170)
Issuance of common stock	135,345	—		(2)		—		—		—		(2)		—		(2)
Stock-based compensation	—	—		3		—		—		—		3		—		3
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(39)		(39)
Contributions from noncontrolling interests	—	—		—		—				—		—		53		53
As of March 31, 2024	386,906,260	$	4	$	17,702	$	(47)	$	2,196	$	21	$	19,876	$	1,013	$	20,889

(*) Par value of share amounts is $0.01

The accompanying notes are an integral part of our condensed consolidated financial statements.

9

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Note 1. 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).

Non-binding proposal from Iberdrola

On March 6, 2024, the Unaffiliated Committee (Committee) of the Board of Directors of Avangrid received a non-binding proposal from Iberdrola to acquire all of the issued and outstanding shares of common stock not owned by Iberdrola or its affiliates for $34.25 in cash per share. The Committee will review, evaluate, negotiate, and approve or disapprove the proposal, advised by independent legal and financial advisers, as well as any other alternative proposals or other strategic alternatives that may be available to Avangrid. No decision has yet been made with respect to Avangrid’s response to the proposal or any alternatives thereto and there can be no assurance that any definitive offer will be made, that any agreement will be executed or that the transaction proposed in the proposal or any other transaction will be approved or completed. The consummation of the proposed transaction is conditioned upon the approval of the proposed transaction by the Committee and by the shareholders of Avangrid that hold in the aggregate a majority of the outstanding shares of common stock that are not held by Iberdrola and its affiliates.

Note 2. 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, 2023.

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, 2024, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2024.

Note 3. Significant Accounting Policies and New Accounting Pronouncements

The new accounting pronouncements we have adopted as of January 1, 2024, 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, 2023, 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) Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued guidance requiring incremental disclosures for reportable segments. These incremental requirements include disclosing significant expenses that are regularly provided to the chief operating decision maker (CODM) and other segment items, including a description of its composition. The other segment items category is the difference between segment revenue less the significant segment expenses, and each reported measure of segment profit or loss. The guidance clarifies that if the CODM reviews multiple measures of a segments total profit or loss, that the entity may under certain conditions report multiple measures in the segment footnote; however, if only one measure is reported, it should be the one that

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best conforms with U.S. GAAP. The guidance requires disclosure of the title and position of the individual or the name of the group identified as the CODM. Finally, all annual disclosures are required in interim reporting starting in the first quarter of 2025. As the guidance impacts disclosures only, it will not have an impact to the consolidated financial results. These changes in disclosures will initially be reflected in the annual financial statement footnotes for the year ended December 31, 2024.

Accounting Pronouncements Issued but Not Yet Adopted

The following are new significant accounting pronouncements not yet adopted, including those issued since December 31, 2023, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Improvements to Income Tax Disclosures

In December 2023, the FASB issued guidance to enhance income tax disclosures. The standard is required to be adopted by public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. The two primary enhancements relate to disaggregation of the annual effective tax rate reconciliation and income taxes paid disclosures. For the rate reconciliation, it requires additional disaggregation of information in a tabular format using both percentages and amounts broken out into specific categories (e.g., state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, and changes in unrecognized tax benefits). For income taxes paid, it requires disaggregation by jurisdiction (e.g., federal, state and foreign). We do not expect the new guidance to have a material impact on our consolidated results of operations, financial position and cash flows.

Note 4. 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 the FASB issued ASC Topic 606, Revenue from Contracts with Customers (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

11

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 significant financing elements in any of the arrangements. 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.

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 Assets and Liabilities

We have contract assets for costs from development success fees and construction delays, which were paid during solar farm assets development period. The contract assets are amortized ratably into expense over the 16 - 21 year life of the respective power purchase agreements (PPAs). Contract assets totaled $19 million and $9 million at  March 31, 2024 and December 31, 2023, respectively, and are presented in "Other non-current assets" on our condensed consolidated balance sheets.

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We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $9 million and $18 million at March 31, 2024 and December 31, 2023, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $9 million and $17 million as revenue related to contract liabilities for the three months ended March 31, 2024 and 2023, respectively.

We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2024 and 2023 are as follows:

	Three Months Ended March 31, 2024
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,350	$	—	$	—	$	1,350
Regulated operations – natural gas	592		—		—		592
Nonregulated operations – wind	—		224		—		224
Nonregulated operations – solar	—		7		—		7
Nonregulated operations – thermal	—		91		—		91
Other(a)	20		(13)		(1)		6
Revenue from contracts with customers	1,962		309		(1)		2,270
Leasing revenue	2		—		—		2
Derivative gains	—		87		—		87
Alternative revenue programs	43		—		—		43
Other revenue	11		4		—		15
Total operating revenues	$	2,018	$	400	$	(1)	$	2,417

	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

(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, 2024 and December 31, 2023, accounts receivable balances related to contracts with customers were approximately $1,529 million and $1,441 million, respectively, including $426 million of unbilled revenues as of both March 31, 2024 and December 31, 2023, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

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As of March 31, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of March 31, 2024	2025		2026		2027		2028		2029		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	30		10		7		5		5		49		106
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	72		48		26		3		1		1		151
Total operating revenues	$	102	$	58	$	33	$	8	$	6	$	50	$	257

As of March 31, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2024 was $116 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).

Note 5. 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, 2024, the total net amount of these items is approximately $1,157 million.

CMP Distribution Rate Case

On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. On June 6, 2023, the MPUC approved a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 100 basis points of CMP’s allowed ROE. The Stipulation also provides for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. An increase occurred on January 1, 2023. The next two increases will occur on July 1, 2024, and January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecast by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets.

NYSEG and RG&E Rate Plans

On June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the 2023 JP, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs was November 1, 2023 with a make-whole provision back to May 1, 2023.

The 2023 JP, as approved, includes levelization across the three years of the rate plan for delivery rates for NYSEG's and RG&E’s Electric and Gas businesses with an allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas of 9.20%. The common equity ratio for each business is 48.00%.

The 2023 JP also includes Earnings Sharing Mechanism (ESM) applicable to each business varies based on the earned ROE with 100% of the customers’ portion of earnings above the sharing threshold that would otherwise be deferred for the benefit of customers will be used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition,

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50% of NYSEG's and RG&E’s portion will be used to reduce their respective outstanding storm-related regulatory asset deferral balances to the extent such balances exist.

The 2023 JP further enhances distribution vegetation management, maintains gas safety performance measures, establishes threshold performance levels for designated aspects of customer service quality, and includes three Electric Reliability Performance Measures (SAIFI, CAIDI, and Distribution Line Inspection Program Metric for Level II Deficiencies) with a negative revenue adjustment (NRA) beginning with calendar year 2023, if NYSEG fails to meet its annual SAIFI performance metric.

NYSEG and RG&E will continue a RAM to return or collect the remaining Customer Bill Credits established in the prior rate plan and will continue an Electric Revenue Decoupling Mechanism on a total revenue per class basis.

The 2023 JP reflects the recovery of deferred NYSEG Electric and RG&E Electric Major Storm costs of approximately $371 million and $54.6 million, respectively. NYSEG’s remaining super storm regulatory asset of $52.3 million and the non-super storm regulatory asset of $96.6 million from the 2020 Joint Proposal are being amortized over seven years. RG&E’s remaining non-super storm regulatory asset of $19.6 million established prior to the 2020 Joint Proposal is being amortized over two years. All other deferred storm costs at both NYSEG and RG&E are being amortized over 10 years. The 2023 JP gradually increases NYSEG’s and RG&E’s Major Storm rate allowances over the term of the 2023 JP to better align NYSEG’s and RG&E’s actual Major Storm costs with such rate allowances and to support NYSEG’s and RG&E’s credit metrics.

The 2023 JP contains provisions consistent with, supportive of, and in furtherance of the objectives of the Climate Leadership and Community Protection Act (CLCPA) including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan.

New York CLCPA

On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act as part of the CLCPA Phase 2. The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.2 billion, including participation with other upstate utilities on certain projects. On October 17, 2023, NYSEG and RG&E filed a petition requesting approval from the NYPSC to seek authorization from the Federal Energy Regulatory Commission (FERC), to utilize 100 percent construction work in progress (CWIP), in rate base for the local transmission upgrades under the CLCPA Phase 2. On April 18, 2024, the NYPSC approved the petition to allow NYSEG and RG&E to seek FERC approval along with adding other related reporting requirements.

UI, CNG, SCG and BGC Rate Plans

Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills.

UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2024 and 50% of the second half of 2024. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first quarter of 2024.

On September 9, 2022, UI filed a distribution revenue requirement case proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (UI Rate Year 1), September 1, 2024 (UI Rate Year 2), and September 1, 2025 (UI Rate Year 3). On August 25, 2023, PURA issued its Final Decision provided for a one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels. On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because of factual and legal errors related to the treatment of deferred assets, plant in service, and operating expenses. We cannot predict the outcome of this matter.

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In 2017, PURA approved new tariffs for 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 approximately 52.00% equity ratio. Any dollars due to customers from the ESM are be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.

In 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021.

On November 3, 2023, CNG and SCG filed a distribution revenue requirement case proposing a one-year rate plan commencing November 1, 2024 through October 31, 2025, for each company respectively. CNG requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $19.8 million, and SCG requested approval of new distribution rates to recover an increase in revenue requirements of approximately $40.6 million. CNG’s and SCG’s rate plans also included several measures to moderate the impact of the proposed rate update for all customers, including, the adoption of a low-income discount rate and seeks to maintain its current revenue decoupling and earning sharing mechanisms. Evidentiary hearings commenced on April 22, 2024. We cannot predict the outcome of this matter.

On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval negotiated between BGC and the AGO in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allowed 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. It provided 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, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. On June 29, 2023 the Governor of Connecticut signed SB7 into law, which included language that Level 1 storm events were exempt from the waiver. We will continue to review the requirements of the program for the next legislative session.

PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation

On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.

On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of approximately $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. Following oral arguments in October 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI

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filed a notice of appeal to Connecticut's Appellate court on November 7, 2022. This matter has been briefed and oral argument was held December 11, 2023. We cannot predict the outcome of this proceeding.

Regulatory Assets and Liabilities

The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.

Regulatory assets as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Pension and other post-retirement benefits	$	439	$	445
Pension and other post-retirement benefits cost deferrals	57		58
Storm costs	1,052		868
Rate adjustment mechanism	42		24
Revenue decoupling mechanism	101		86
Contracts for differences	33		38
Hardship programs	25		23
Deferred purchased gas	6		16
Environmental remediation costs	244		240
Debt premium	57		58
Unamortized losses on reacquired debt	17		17
Unfunded future income taxes	601		578
Federal tax depreciation normalization adjustment	129		130
Asset retirement obligation	20		19
Deferred meter replacement costs	60		59
COVID-19 cost recovery and late payment surcharge	11		12
Low income arrears forgiveness	49		55
Excess generation service charge	86		52
System Expansion	19		22
Non-bypassable charge	124		103
Hedges losses	13		34
Rate change levelization	83		60
Value of distributed energy resources	44		49
Uncollectible reserve	114		104
New York make-whole provision	84		96
Other	296		283
Total regulatory assets	3,806		3,529
Less: current portion	745		718
Total non-current regulatory assets	$	3,061	$	2,811

“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

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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.

“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability.

“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.

“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.

“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.

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“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 started 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.

“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.

“Value of distributed energy resources” represents the mechanism to compensate for energy created by distributed energy resources, such as solar.

“Uncollectible reserve” includes the anticipated future rate recovery of costs that are recorded as uncollectible since those will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future uncollectible expense, it does not accrue carrying costs and is not included within rate base. It also includes the variance between actual uncollectible expense and uncollectible expense included in rates that is eligible for future recovery in customer rates. The amortization period will be established in future proceedings.

“New York make-whole provision” represents the regulatory asset to recover revenues that would have been received by NYSEG/RGE had Rate Year 1 rates approved in the 22-E-0317 et al. joint proposal gone into effect on the effective date of May 1, 2023. The balance is being recovered through a separately stated make-whole rate, effective November 1, 2022, over 6-30 months.

“Other” includes various items subject to reconciliation including vegetation management and systems benefit charge.

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Regulatory liabilities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Energy efficiency portfolio standard	$	24	$	15
Gas supply charge and deferred natural gas cost	10		8
Pension and other post-retirement benefits cost deferrals	88		89
Carrying costs on deferred income tax bonus depreciation	2		3
Carrying costs on deferred income tax - Mixed Services 263(a)	1		2
2017 Tax Act	1,187		1,190
Accrued removal obligations	1,135		1,139
Positive benefit adjustment	7		9
Deferred property tax	21		21
Net plant reconciliation	23		23
Debt rate reconciliation	16		18
Rate refund – FERC ROE proceeding	40		39
Transmission congestion contracts	24		26
Merger-related rate credits	7		8
Accumulated deferred investment tax credits	20		21
Asset retirement obligation	19		19
Middletown/Norwalk local transmission network service collections	16		16
Non-firm margin sharing credits	39		34
Non by-passable charges	6		9
Transmission revenue reconciliation mechanism	32		57
Other	234		209
Total regulatory liabilities	2,951		2,955
Less: current portion	275		261
Total non-current regulatory liabilities	$	2,676	$	2,694

“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.

“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.

"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.

“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

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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 of regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions.

“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.

“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Avangrid (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Net plant reconciliation” represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Debt rate reconciliation” represents the over/under collection of costs related to debt instruments identified in the rate case. Costs would include interest, commissions and fees versus amounts included in rates.

“Rate refund - FERC ROE proceeding” represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details.

“Transmission congestion contracts” represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During the three months ended March 31, 2024 and 2023, $1 million and $1 million of rate credits were applied against customer bills.

“Asset retirement obligation” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.

“Middletown/Norwalk local transmission network service collections” represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project.

“Non-firm margin sharing credits” represents the portion of interruptible and off-system sales revenue set aside to fund gas expansion projects.

“Other” includes various items subject to reconciliation or being returned through rates, such as service quality metrics.

Note 6. 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

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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 their 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 New York Mercantile Exchange (NYMEX). We include the fair value measurements in Level 1 because we use prices quoted in an active market.

•NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3.

•UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs).

We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include modeled volumes on unit-contingent contracts, extrapolated power curves through May 2032 and scheduling assumptions on California power exports to cover Nevada physical power sales. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.

We determine the fair value of our interest rate derivative instruments based on a model whose inputs are observable, such as SOFR, forward interest rate curves or other relevant benchmark. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate contracts).

We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2.

The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value.

Restricted cash was $3 million as of both March 31, 2024 and December 31, 2023, respectively and is included in "Other Assets" on our condensed consolidated balance sheets.

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The financial instruments measured at fair value as of March 31, 2024 and December 31, 2023, respectively, consisted of:

As of March 31, 2024	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	30	$	18	$	—	$	—	$	48
Derivative assets
Derivative financial instruments - power	$	23	$	71	$	95	$	(80)	$	109
Derivative financial instruments - gas	—		19		—		(15)		4
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		158		—		—		158
Total	$	23	$	248	$	96	$	(95)	$	272
Derivative liabilities
Derivative financial instruments - power	$	(33)	$	(71)	$	(44)	$	101	$	(47)
Derivative financial instruments - gas	(3)		(22)		—		25		—
Contracts for differences	—		—		(34)		—		(34)
Derivative financial instruments – Other	—		(101)		—		—		(101)
Total	$	(36)	$	(194)	$	(78)	$	126	$	(182)

As of December 31, 2023	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	29	$	16	$	—	$	—	$	45
Derivative assets
Derivative financial instruments - power	$	15	$	42	$	114	$	(69)	$	102
Derivative financial instruments - gas	—		17		—		(12)		5
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		122		—		—		122
Total	$	15	$	181	$	115	$	(81)	$	230
Derivative liabilities
Derivative financial instruments - power	$	(37)	$	(101)	$	(40)	$	135	$	(43)
Derivative financial instruments - gas	(12)		(26)		—		37		(1)
Contracts for differences	—		—		(39)		—		(39)
Derivative financial instruments - Other	—		(92)		—		—		(92)
Total	$	(49)	$	(219)	$	(79)	$	172	$	(175)

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The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2024 and 2023, respectively, is as follows:

	Three Months Ended March 31,
(Millions)	2024		2023
Fair Value Beginning of Period,	$	36	$	16
Gains recognized in operating revenues	3		—
(Losses) recognized in operating revenues	(19)		(3)
Total losses recognized in operating revenues	(16)		(3)
Gains recognized in OCI	1		11
(Losses) recognized in OCI	(6)		(3)
Total (losses) gains recognized in OCI	(5)		8
Net change recognized in regulatory assets and liabilities	5		4
Purchases	1		9
Settlements	(3)		(20)
Fair Value as of March 31,	$	18	$	14
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	$	(16)	$	(3)

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, 2024
Index	Avg.		Max.		Min.
Ameren ($/MWh)	$	42.68	$	90.60	$	19.58
ComEd ($/MWh)	$	38.64	$	83.36	$	15.39
ERCOT S hub ($/MWh)	$	45.73	$	150.55	$	16.17
Mid C ($/MWh)	$	84.98	$	248.45	$	16.95
AEP-DAYTON hub ($/MWh)	$	42.79	$	94.32	$	20.58

Our Level 3 valuations primarily consist of a Hydro PPA 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 PPA is a long capacity/energy position in the Northwest that provides balancing services with increases in power prices resulting in unrealized gains and decreases in power prices resulting in unrealized losses. The gas swaps are economic hedges of fuel purchases for a combined cycle gas plant, with increases in gas prices resulting in unrealized gains and decreases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.

Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the modeled volumes on unit-contingent agreements. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products.

Transactions are valued in part on the basis of forward prices and estimated volumes. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction.

The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk

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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, 2024
Risk of non-performance	0.52% - 0.54%
Discount rate	3.84% - 4.01%
Forward pricing ($ per KW-month)	$2.00 - $2.61

Fair Value of Debt

As of March 31, 2024 and December 31, 2023, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $10,136 million and $10,266 million as of March 31, 2024 and December 31, 2023, 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. The fair value of debt is considered Level 2 within the fair value hierarchy.

Note 7. 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, 2024 and December 31, 2023, 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, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	20	$	5	$	19	$	5
Derivative liabilities	(19)		(5)		(42)		(29)
	1		—		(23)		(24)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		—		(23)		(24)
Cash collateral receivable	—		—		6		7
Total derivatives as presented in the balance sheet	$	1	$	—	$	(17)	$	(17)

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As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	13	$	3	$	12	$	3
Derivative liabilities	(12)		(3)		(57)		(32)
	1		—		(45)		(29)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		—		(45)		(29)
Cash collateral receivable	—		—		27		7
Total derivatives as presented in the balance sheet	$	1	$	—	$	(18)	$	(22)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,	December 31,
As of	2024	2023
(Millions)
Wholesale electricity purchase contracts (MWh)	6.0	5.6
Natural gas purchase contracts (Dth)	9.3	10.7

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, 2024 and December 31, 2023 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2024 and 2023 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, 2024	Electricity		Natural Gas		2024	Electricity		Natural Gas
Regulatory assets	$	10	$	3	Purchased power, natural gas and fuel used	$	20	$	11
December 31, 2023					2023
Regulatory assets	$	22	$	12	Purchased power, natural gas and fuel used	$	49	$	6

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

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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, 2024, 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 $33 million, a gross derivative liability of $34 million ($33 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, 2023, 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 $38 million, a gross derivative liability of $39 million ($38 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, 2024 and 2023, respectively, were as follows:

	Three Months Ended March 31,
	2024		2023
(Millions)
Derivative liabilities	$	5	$	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, 2024 and 2023, 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)
2024
Interest rate contracts	$	—	Interest expense	$	1	$	125
Commodity contracts	—		Purchased power, natural gas and fuel used	—		724
Total	$	—		$	1
2023
Interest rate contracts	$	—	Interest expense	$	1	$	95
Commodity contracts	—		Purchased power, natural gas and fuel used	—		977
Total	$	—		$	1

(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 $38 million and $39 million as of March 31, 2024 and December 31, 2023, respectively. For the three months ended March 31, 2024 and 2023, we recorded net derivative losses related to discontinued cash flow hedges of $1 million and $1 million, respectively. We will amortize approximately $4 million of discontinued cash flow hedges within the next twelve months.

(b) Renewables activities

Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities.

Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.

Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price

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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, 2024 and December 31, 2023, respectively, consisted of:

	March 31,	December 31,
As of	2024	2023
(MWh/Dth in millions)
Wholesale electricity purchase contracts	1	1
Wholesale electricity sales contracts	6	6
Natural gas and other fuel purchase contracts	14	21
Financial power contracts	4	4
Basis swaps – purchases	21	24
Basis swaps – sales	1	1

The fair values of derivative contracts associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Wholesale electricity purchase contracts	$	8	$	29
Wholesale electricity sales contracts	46		14
Natural gas and other fuel purchase contracts	3		4
Financial power contracts	10		17
Total	$	67	$	64

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, 2024 and December 31, 2023, the fair value of the interest rate swap was $158 million and $122 million, respectively, as non-current assets. 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.

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The tables below present Renewables' derivative positions as of March 31, 2024 and December 31, 2023, 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, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	64	$	48	$	43	$	5
Derivative liabilities	(3)		(1)		(53)		(7)
	61		47		(10)		(2)
Designated as hedging instruments
Derivative assets	30		138		14		1
Derivative liabilities	(1)		—		(37)		(35)
	29		138		(23)		(34)
Total derivatives before offset of cash collateral	90		185		(33)		(36)
Cash collateral (payable) receivable	(4)		—		14		8
Total derivatives as presented in the balance sheet	$	86	$	185	$	(19)	$	(28)

As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	53	$	52	$	53	$	1
Derivative liabilities	—		(3)		(73)		(4)
	53		49		(20)		(3)
Designated as hedging instruments
Derivative assets	15		113		7		1
Derivative liabilities	(1)		—		(47)		(37)
	14		113		(40)		(36)
Total derivatives before offset of cash collateral	67		162		(60)		(39)
Cash collateral receivable	—		—		43		13
Total derivatives as presented in the balance sheet	$	67	$	162	$	(17)	$	(26)

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, 2024 and 2023, consisted of:

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	Three Months Ended March 31, 2024
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(3)	$	—
Wholesale electricity sales contracts	11		22
Financial power contracts	(2)		2
Financial and natural gas contracts	—		(2)
Total gain included in operating revenues	$	6	$	22	$	2,417
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(17)
Financial power contracts	—		—
Financial and natural gas contracts	—		8
Total loss included in purchased power, natural gas and fuel used	$	—	$	(9)	$	724
Total Gain	$	6	$	13

	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 gain included in purchased power, natural gas and fuel used	$	—	$	(56)	$	977
Total Gain (Loss)	$	5	$	(6)

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, 2024 and 2023, respectively, consisted of:

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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)
2024
Interest rate contracts	$	36	Interest Expense	$	—	$	125
Commodity contracts	20		Operating revenues	5		$	2,417
Total	$	56		$	5
2023
Interest rate contracts	$	90	Interest Expense	$	—	$	95
Commodity contracts	23		Operating revenues	66		$	2,466
Total	$	113		$	66

(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 $20 million of losses included in accumulated OCI at March 31, 2024, are expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2024 and 2023.

(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, 2024 and December 31, 2023, the net loss in accumulated OCI related to previously settled interest rate contracts was $27 million and $29 million, respectively. For both the three months ended March 31, 2024 and 2023, we amortized into income $2 million of the loss related to settled interest rate contracts. We will amortize approximately $9 million of the net loss on the interest rate contracts within the next twelve months.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2024 and 2023, 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)
2024
Interest rate contracts	$	—	Interest expense	$	2	$	125
2023
Interest rate contracts	$	—	Interest expense	$	2	$	95

(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."

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The effects on our consolidated financial statements as of and for the three months ended March 31, 2024 and 2023 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, 2024			Three Months Ended March 31, 2024
Current Liabilities	$	(29)	Interest Expense	$	11	$	125
Non-current liabilities	$	(71)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	100

	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, 2023			Three Months Ended March 31, 2023
Current Liabilities	$	(26)	Interest Expense	$	7	$	95
Non-current liabilities	$	(63)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	89

(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, 2024, UI would have had to post an aggregate of approximately $27 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 both March 31, 2024 and December 31, 2023, the amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $63 million. 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, 2024 was $13 million, for which we have posted collateral.

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Note 8. 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 of 9.2%. CMP and UI are NETOs with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.

On December 26, 2012, a second related complaint for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On July 31, 2014, a third related complaint was filed for a subsequent rate period requesting the ROE be reduced to 8.84%. On April 29, 2016, a fourth complaint was filed for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%.

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 FERC. We cannot predict the final outcome of the proceedings.

Customer Invoice Dispute

On May 4, 2021, Nike USA, Inc. (Nike), the buyer under a virtual PPA with a subsidiary of Renewables, provided notice that it disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations, most notably during Winter Storm Uri in February of 2021. Nike has requested an adjustment to the invoices that would increase the amount payable by approximately $31 million. Renewables has responded that the invoices have been properly calculated in accordance with the provisions of the PPA, and that Nike is not entitled to any further payments. On June 16, 2023, Nike filed suit against the Company and certain subsidiaries of Renewables alleging breach of contract, and seeking more than $31 million in invoice adjustments, fees, and interest. The Company filed a motion to dismiss the complaint, which the Circuit Court of the State of Oregon for the County of Multnomah denied on October 25, 2023 following oral arguments. The case is currently proceeding with an expected trial beginning on October 14, 2024. We cannot predict the outcome of this matter.

Solar Contractor Dispute

Renewables, through certain subsidiaries, has Engineering, Procurement and Construction (EPC) contracts with Sterling and Wilson Solar Solutions, Inc. (SWSS) for the construction of two Solar farms–Lund Hill in Klickitat, WA (Lund Hill), and Pachwáywit Fields in Gillam County, OR (Montague). Renewables believes that SWSS is in default of a number of its obligations under the respective EPC contracts, including construction flaws and failing to pay certain subcontractors. As a result, Renewables drew on Letters of Credit for both Montague and Lund Hill. In response, SWSS filed liens on both projects totaling approximately $105 million claiming that this amount is due under EPC contracts. Renewables has bonded over the liens on both properties. On October 27, 2023, SWSS commenced foreclosure actions in Oregon on the lien at Montague, and added claims for breach of contract and quantum meruit, seeking up to $111.8 million. SWSS has also commenced foreclosure procedures in Washington State against Lund Hill seeking to close on its lien of $59.9 million. On February 26, 2024, SWSS filed a lawsuit against Lund Hill and Renewables in New York State court alleging breach of contract, quantum meruit and violation of the Prompt Payment Act, all based on the same facts as the previously filed foreclosure matter seeking $59.9 million in damages. We cannot predict the outcome of these disputes.

Guarantee Commitments to Third Parties

As of March 31, 2024, we had approximately $918 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 and an indemnification of Vineyard Wind tax equity investors as described in Note 19, which are 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

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with these instruments will be incurred and, accordingly, as of March 31, 2024, neither we nor our subsidiaries have any liabilities recorded for these instruments.

NECEC Commitments

On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately $11 million was paid through the three months ended March 31, 2024.

Note 9. Environmental Liabilities

Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies.

Waste sites

The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; two sites are included in Maine’s Uncontrolled Sites Program; and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, five of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and several for certain sites.

We have recorded an estimated liability of $6 million related to six of the twenty-four sites. We have paid remediation costs related to the remaining eighteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $10 million related to another ten sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of March 31, 2024, our estimate for costs to remediate these sites ranges from $15 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs.

Manufactured Gas Plants

We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry, thirty-nine sites are included in the New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order of Consent; two sites with individual NYSDEC Orders of Consent; two sites under a Brownfield Cleanup Program and two sites are included in Maine Department of Environmental Protection programs (none in the Voluntary Response Action Program, Brownfield Cleanup Program and Uncontrolled Sites Program). The remaining sites are not included in a formal program. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.

As of March 31, 2024, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $117 million to $213 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 of 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, 2024, 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

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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, 2024 and December 31, 2023, 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, 2024 and December 31, 2023, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $245 million and $250 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 2058.

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, 2024, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $8 million and $5 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 August 4, 2016, DEEP issued a partial consent order (the consent order), that requires UI to investigate and remediate certain environmental conditions within the perimeter of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000. 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. UI must comply with the terms of the consent order, but may seek to recover costs above $30 million in consultation with the state. UI continues its activities to investigate and remediate the environmental conditions at the site. In 2023 and 2024, DEEP sent UI a series of letters requesting details on remediation plans and security, which UI has responded to.

On January 25, 2024, DEEP issued a notice of declaratory ruling to determine the “high occupancy standard” necessary “to abate on-site pollution and impacts for industrial/commercial use of the Site…inside the buildings” as referenced in section (B)(1)(e)(4) of the Partial Consent Order. On February 26, 2024, UI was granted intervenor status and it subsequently submitted its written comments objecting to the proceedings on March 11, 2024. On January 29, 2024, DEEP served UI with a Summons and Complaint seeking injunctive relief and enforcement of the consent order from the Connecticut Superior Court. On April 9, 2024, the application to transfer the proceedings to the Complex Litigation Docket of the Connecticut Superior Court was granted. The court also granted UI’s Motion to Stay the proceeding until the April 30, 2024 court conference.

As of both March 31, 2024 and December 31, 2023, the amount reserved related to English Station was $19 million. Since its inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of these proceedings.

Eagle Takings Inquiry

In April 2023, Avangrid Renewables received a letter from the U.S. Fish and Wildlife Service regarding certain bald and golden eagle fatalities that allegedly occurred at certain Avangrid Renewables facilities that are not covered by an eagle take permit. Avangrid Renewables has responded to the U.S. Fish and Wildlife Service providing information about the relevant eagle taking permit applications and relevant mitigation activity at each facility. On February 12, 2024, the U.S. Fish and Wildlife Service published a new Eagle Rule, superseding the 2016 Eagle Rule. Avangrid Renewables subsequently communicated to the U.S. Fish and Wildlife Service that it would be applying for the General Permit option under the new Eagle Rule and is waiting for the permit application form to become available in the preferred electronic permit platform, ePermits. The U.S. Fish and Wildlife Service acknowledged receipt of this communication. We cannot predict the outcome of these applications.

Note 10. Post-retirement and Similar Obligations

We made $1 million of pension contributions for the three months ended March 31, 2024. We expect to make additional contributions of $27 million for the remainder of 2024.

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The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of:

	Three Months Ended March 31,
	2024		2023
(Millions)
Service cost	$	2	$	2
Interest cost	28		30
Expected return on plan assets	(40)		(36)
Amortization of:
Prior service costs	—		—
Actuarial loss	7		1
Net Periodic Benefit Cost	$	(3)	$	(3)

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of: 

	Three Months Ended March 31,
	2024		2023
(Millions)
Service cost	$	—	$	—
Interest cost	3		3
Expected return on plan assets	(1)		(1)
Amortization of:
Prior service costs	—		—
Actuarial loss	(1)		(3)
Net Periodic Benefit Cost (Credit)	$	1	$	(1)

Note 11. Equity

As of both March 31, 2024 and December 31, 2023, we had 103,889 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2024 and 2023, we issued 135,345 and 12,332 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, 2024, 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, 2024.

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Accumulated Other Comprehensive Income (Loss) 

Accumulated Other Comprehensive Loss for the three months ended March 31, 2024 and 2023, 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,
	2023		2024		2024		2022		2023		2023
(Millions)
Net loss on pension plans	(21)		—		(21)		(20)		—		(20)
Unrealized (loss) gain from equity method investment, net of income tax expense of $0 for 2024 and $0 for 2023 (a)	18		—		18		13		(1)		12
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $15 for 2024 and $(1) for 2023	(178)		39		(139)		(195)		(2)		(197)
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $2 for 2024 and $18 for 2023 (b)	156		7		163		22		52		74
Loss (gain) on derivatives qualifying as cash flow hedges	(22)		46		24		(173)		50		(123)
Accumulated Other Comprehensive Income (Loss)	$	(25)	$	46	$	21	$	(180)	$	49	$	(131)

(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.

Note 12. 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, 2024 and 2023, 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, 2024 and 2023, respectively, consisted of:

	Three Months Ended March 31,
	2024		2023
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to Avangrid	$	351	$	245
Denominator:
Weighted average number of shares outstanding - basic	386,916,234		386,744,996
Weighted average number of shares outstanding - diluted	387,239,544		387,077,213
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic	$	0.91	$	0.63
Earnings Per Common Share, Diluted	$	0.91	$	0.63

Note 13. Segment Information

Our segment reporting structure uses our management reporting structure as its foundation to reflect how Avangrid manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments:

•Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of

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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 accelerated depreciation from the repowering of wind farms.

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, 2024, consisted of:

Three Months Ended March 31, 2024	Networks		Renewables		Other (a)		Avangrid Consolidated
(Millions)
Revenue - external	$	2,017	$	400	$	—	$	2,417
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	178		118		2		298
Operating income (loss)	353		60		(6)		407
Earnings from equity method investments	4		2		—		6
Interest expense, net of capitalization	89		4		32		125
Income tax expense (benefit)	57		(6)		(31)		20
Adjusted net income (loss)	268		84		(11)		341
Capital expenditures	691		179		2		872
As of March 31, 2024
Property, plant and equipment	22,068		11,243		12		33,323
Equity method investments	188		648		—		836
Total assets	$	31,238	$	14,114	$	(290)	$	45,062

(a) Includes Corporate and intersegment eliminations.

Segment information for the three months ended March 31, 2023 and as of December 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 (loss)	195		51		1		248
Capital expenditures	609		227		—		836
As of December 31, 2023
Property, plant and equipment	21,692		11,153		12		32,857
Equity method investments	186		532		—		718
Total assets	$	30,413	$	14,538	$	(962)	$	43,989

(a) Includes Corporate and intersegment eliminations.

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Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the three months ended March 31, 2024 and 2023, respectively, is as follows:

	Three Months Ended March 31,
	2024		2023
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	341	$	248
Adjustments:
Mark-to-market adjustments - Renewables (1)	17		(4)
Accelerated depreciation from repowering (2)	(3)		—
Income tax impact of adjustments	(4)		1
Net Income Attributable to Avangrid, Inc.	$	351	$	245

(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(2)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

Note 14. 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, 2024 and 2023, respectively, consisted of:

Three Months Ended March 31,	2024				2023
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(12)	$	—	$	(11)
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(16)	$	—	$	(4)
Vineyard Wind	$	3	$	—	$	2	$	—

Related party balances as of March 31, 2024 and December 31, 2023, respectively, consisted of:

As of	March 31, 2024				December 31, 2023
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	1	$	(12)	$	1	$	—
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	4	$	—
Iberdrola Financiación, S.A.	$	—	$	(1,304)	$	—	$	(799)
Vineyard Wind	$	4	$	(8)	$	6	$	(8)
Iberdrola Solutions	$	—	$	(6)	$	—	$	(6)
Other	$	4	$	(1)	$	4	$	—

Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of Avangrid, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 15 for a discussion of the Iberdrola Intragroup Green Loan.

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, 2024 and December 31, 2023, was $0.

On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and a

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maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of March 31, 2024 and December 31, 2023, there was $500 million and $0 outstanding amount under this credit facility, respectively.

We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balances of $6 million and as of both March 31, 2024 and December 31, 2023.

See Note 19 - Equity Method Investments for more information on transactions with our equity method investees.

Note 15. Other Financial Statement Items

Accounts receivable and unbilled revenue, net

Accounts receivable and unbilled revenues, net as of March 31, 2024 and December 31, 2023 consisted of:

As of	March 31, 2024		December 31, 2023
(Millions)
Trade receivables and unbilled revenues	$	1,809	$	1,749
Allowance for credit losses	(169)		(161)
Accounts receivable and unbilled revenues, net	$	1,640	$	1,588

The change in the allowance for credit losses for the three months ended March 31, 2024 and 2023 consisted of:

	Three Months Ended March 31,
(Millions)	2024		2023
As of Beginning of Period,	$	161	$	155
Current period provision	46		17
Write-off as uncollectible	(38)		(24)
As of March 31,	$	169	$	148

The Deferred Payment Arrangements (DPA) receivable balance was $116 million and $110 million as of March 31, 2024 and December 31, 2023, respectively. The allowance for credit losses for DPAs at March 31, 2024 and December 31, 2023 was $46 million and $44 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2024 and 2023, was $2 million and $(2) million, respectively.

Prepayments and other current assets

Included in prepayments and other current assets are $164 million and $142 million of prepaid other taxes as of March 31, 2024 and December 31, 2023, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of March 31, 2024 and December 31, 2023, respectively, were as follows:

	March 31,		December 31,
As of	2024		2023
(Millions)
Property, plant and equipment
Accumulated depreciation	$	12,732	$	12,479
Intangible assets
Accumulated amortization	$	357	$	351

As of March 31, 2024 and 2023, accrued liabilities for property, plant and equipment additions were $553 million and $239 million, respectively.

Debt

Commercial Paper

As of March 31, 2024 and December 31, 2023, there was $1,864 million and $1,332 million of commercial paper outstanding, respectively. As of March 31, 2024 and December 31, 2023, the weighted-average interest rate on commercial paper was 5.55% and 5.65%, respectively.

Intragroup Green Loan

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On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan).

Other current liabilities

Included in other current liabilities are $224 million and $236 million of advances received as of March 31, 2024 and December 31, 2023, respectively.

Note 16. Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2024 was 5.8% which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items, partially offset by tax equity financing impacts and state taxes.

The 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.

Note 17. Stock-Based Compensation Expense

The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares).

Performance Stock Units

In March 2023, a total number of 677,752 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and are payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The remaining unvested PSUs were forfeited. The second installment was paid in March 2024, and 126,311 shares of common stock were issued to settle this installment payment.

During 2023 and 2024, 1,067,500 and 15,296 PSUs, respectively, 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 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 second and final installment of this RSU grant was settled in January 2024, net of applicable taxes, by issuing 9,034 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 four 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 2024, $0.1 million was paid to settle the fourth and final 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, 2025 and 2026 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In February 2024, $1.0 million was paid to settle the first installment under this plan.

As of March 31, 2024 and December 31, 2023, the total liability was $1 million and $2 million, respectively, which is included in other current and non-current liabilities.

The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2024 and 2023, was $3 million and $4 million, respectively.

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Note 18. Variable Interest Entities

We participate in certain partnership arrangements that qualify as VIEs. These arrangements 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.

The assets and liabilities of the VIEs totaled approximately $2,740 million and $196 million, respectively, at March 31, 2024. As of December 31, 2023, the assets and liabilities of VIEs totaled approximately $2,741 million and $174 million, respectively. At March 31, 2024 and December 31, 2023, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.

Wind and solar power generation are 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 and solar farms. Under these structures, we contribute certain wind / solar assets, relating both to existing wind farms and wind farms / solar facilities 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 targeted 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, 2024, 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.

Note 19. 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 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 in 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,

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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.

On October 24, 2023, Vineyard Wind 1 closed on a TEF agreement, pursuant to which Vineyard Wind 1 is expected to receive approximately $1.2 billion from tax equity investors in installments based on the number of turbines reaching or about to reach mechanical completion each month until the entire project reaches commercial operation date. Vineyard Wind 1 received the initial funding of $85 million from tax equity investors in 2023. The remaining $1.1 billion is expected to be received in 2024. In conjunction with the equity installments received since the closing of the TEF agreement, we have issued an indemnification of our joint share of the investor contributions. As of both March 31, 2024 and December 31, 2023, our total indemnified amount was $43 million.

Vineyard Wind 1 is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. During 2024, Renewables made a capital contribution of $116 million to Vineyard Wind 1. As of March 31, 2024 and December 31, 2023, the carrying amount of Renewables' investments in Vineyard Wind LLC and Vineyard Wind 1 Pledgor LLC was $419 million and $297 million, respectively.

Note 20. Subsequent Event

On April 11, 2024, 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 1, 2024 to shareholders of record at the close of business on June 3, 2024.

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Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the condensed consolidated financial statements and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q and with our audited consolidated financial statements as of December 31, 2023 and 2022, and for the three years ended December 31, 2023, included in our Annual Report on Form 10-K for the year ended December 31, 2023, filed with the Securities and Exchange Commission, or the SEC, on February 22, 2024, which we refer to as our “Form 10-K.” In addition to historical condensed consolidated financial information, the following discussion contains forward-looking statements that reflect our plans, estimates and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. The foregoing and other factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC.

Overview

Avangrid aspires to be the leading sustainable energy company in the United States. Our purpose is to work every day to deliver a more accessible clean energy model that promotes healthier, more sustainable communities. A commitment to sustainability is firmly entrenched in the values and principles that guide Avangrid, with environmental, social, governance and financial sustainability key priorities driving our business strategy.

Avangrid has approximately $45 billion in assets and operations in 24 states concentrated in our two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving approximately 3.3 million customers in New York and New England. Avangrid Renewables owns and operates 9.5 gigawatts of electricity capacity, primarily through wind and solar power, with a presence in 22 states across the United States. Avangrid supports the achievement of the Sustainable Development Goals approved by the member states of the United Nations, was named among the World’s Most Ethical companies in 2024 for the sixth consecutive year by the Ethisphere Institute and recognized by Just Capital as one of the 2024 Just 100, an annual ranking of the most just U.S. public companies for the fourth time. Avangrid employs approximately 8,000 people. Iberdrola S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.6% of the outstanding shares of Avangrid common stock. 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). Avangrid's primary businesses are described below.

Our direct, wholly-owned subsidiaries include Avangrid Networks, Inc., or Networks, and Avangrid Renewables Holdings, Inc., or ARHI. ARHI in turn holds subsidiaries including Avangrid Renewables, LLC, or Renewables. Networks owns and operates our regulated utility businesses through its subsidiaries, including electric transmission and distribution and natural gas distribution, transportation and sales. Renewables operates a portfolio of renewable energy generation facilities primarily using onshore wind power and also solar, biomass and thermal power.

Through Networks, we own electric distribution, transmission and generation companies and natural gas distribution, transportation and sales companies in New York, Maine, Connecticut and Massachusetts, delivering electricity to approximately 2.3 million electric utility customers and delivering natural gas to approximately 1.0 million natural gas utility customers as of March 31, 2024.

Networks, a Maine corporation, holds regulated utility businesses, including electric transmission and distribution and natural gas distribution, transportation and sales. Networks serves as a super-regional energy services and delivery company through the eight regulated utilities it owns directly:

•New York State Electric & Gas Corporation, or NYSEG, which serves electric and natural gas customers across more than 40% of the upstate New York geographic area;

•Rochester Gas and Electric Corporation, or RG&E, which serves electric and natural gas customers within a nine-county region in western New York, centered around Rochester;

•The United Illuminating Company, or UI, which serves electric customers in southwestern Connecticut;

•Central Maine Power Company, or CMP, which serves electric customers in central and southern Maine;

•The Southern Connecticut Gas Company, or SCG, which serves natural gas customers in Connecticut;

•Connecticut Natural Gas Corporation, or CNG, which serves natural gas customers in Connecticut;

•The Berkshire Gas Company, or BGC, which serves natural gas customers in western Massachusetts; and

•Maine Natural Gas Corporation, or MNG, which serves natural gas customers in several communities in central and southern Maine.

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Renewables has a combined wind, solar and thermal installed capacity of 9,478 megawatts, or MW, as of March 31, 2024, including Renewables’ share of joint projects, of which 8,045 MW was installed onshore wind capacity and 65 MW of offshore. Renewables targets to contract or hedge above 80% of its capacity under long-term PPAs and hedges to limit market volatility. As of March 31, 2024, approximately 78% of the capacity was contracted with PPAs for an average period of approximately 9 years and an additional 10% of production was hedged. Avangrid is one of the three largest wind operators in the United States based on installed capacity as of December 31, 2023, and strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables installed capacity includes 68 onshore wind farms and six solar facilities operational and one offshore wind facility in 21 states across the United States.

Non-binding proposal from Iberdrola

On March 6, 2024, the Unaffiliated Committee (Committee) of the Board of Directors of Avangrid received a non-binding proposal from Iberdrola to acquire all of the issued and outstanding shares of common stock not owned by Iberdrola or its affiliates for $34.25 in cash per share. The Committee will review, evaluate, negotiate, and approve or disapprove the proposal, advised by independent legal and financial advisers, as well as any other alternative proposals or other strategic alternatives that may be available to Avangrid. No decision has yet been made with respect to Avangrid’s response to the proposal or any alternatives thereto and there can be no assurance that any definitive offer will be made, that any agreement will be executed or that the transaction proposed in the proposal or any other transaction will be approved or completed. The consummation of the proposed transaction is conditioned upon the approval of the proposed transaction by the Committee and by the shareholders of Avangrid that hold in the aggregate a majority of the outstanding shares of common stock that are not held by Iberdrola and its affiliates.

Business Environment

The impact of extraordinary external events such as global pandemics and geopolitical instability continue to cause global economic and supply chain disruption and volatility in financial markets and the United States economy. We continue to experience changes in inflation levels resulting from various supply chain disruptions, increased business and labor costs, increased financing costs from changes in the Federal Reserve's monetary policy and other disruptions caused by global economic conditions. We continue to take steps intended to mitigate the potential risks from continued conflict, including without limitation, communication with suppliers to ensure that the supply chains are free from sanctioned materials and efforts to diversify sourcing and capacity planning to help avoid supply chain disruptions. To date, there has been no material impact on our operations or financial performance as a result of ongoing extraordinary events including, without limitation, the conflicts in Eastern Europe and the Middle East; however, we cannot predict the extent of these effects, given the evolving nature of the geopolitical situation, on our business, results of operations or financial condition.

For more information, see the risk factor in Item 1A. Risk Factors in our Form 10-K for the year ended December 31, 2023.

Summary of Results of Operations

Our operating revenues decreased by $49 million from $2,466 million for the three months ended March 31, 2023 to $2,417 million for the three months ended March 31, 2024.

Networks business revenues decreased mainly due to a decrease in purchased power and purchased gas driven by lower average pricing in commodities in the period, offset by rate increases in New York effective October 12, 2023. Renewables revenues increased mainly due to favorable thermal and power trading driven by higher average prices in the period primarily due to cold weather.

Net income attributable to Avangrid increased by $106 million from $245 million for the three months ended March 31, 2023 to $351 million for the three months ended March 31, 2024, primarily driven by a rate increase in New York and thermal and power trading revenues in Renewables in the period.

Adjusted net income (a non-GAAP financial measure) increased by $93 million from $248 million for the three months ended March 31, 2023 to $341 million for the three months ended March 31, 2024. The increase is primarily due to a $73 million increase in Networks driven primarily by rate increases in New York effective October 12, 2023, a $33 million increase in Renewables primarily driven by favorable thermal and power trading due to higher average prices in the period primarily due to cold weather, offset by a $13 million decrease in Corporate mainly driven by higher interest expenses in the period.

For additional information and reconciliation of the non-GAAP adjusted net income to net income attributable to Avangrid, see “—Non-GAAP Financial Measures”.

See “—Results of Operations” for further analysis of our operating results for the quarter.

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Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the independent system operator, or ISO, markets in which we participate. Federal and state legislative and regulatory actions continue to change how our business is regulated. We actively participate in the regulatory process at the federal, regional, state and ISO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see our Form 10-K for the year ended December 31, 2023.

New England Clean Energy Connect

In 2018, the New England Clean Energy Connect, or NECEC, transmission project, proposed in a joint bid by CMP and Hydro-Québec, was selected by the Massachusetts electric distribution utilities, or EDCs, and the DOER in the Commonwealth of Massachusetts’s 83D clean energy Request for Proposal. The NECEC transmission project includes a 145-mile transmission line linking the electrical grids in Québec, Canada and New England. The project, which has estimated construction costs of approximately $1.5 billion in total, would add 1,200 MW of transmission capacity to supply Maine and the rest of New England with power from reliable hydroelectric generation.

On June 13, 2018, CMP entered into transmission service agreements, or TSAs, with the Massachusetts EDCs, and H.Q. Energy Services (U.S.) Inc., or HQUS, an affiliate of Hydro-Québec, which govern the terms of service and revenue recovery for the NECEC transmission project. Simultaneous with the execution of the TSAs with CMP, the EDCs executed certain PPAs with HQUS for sales of electricity and environmental attributes to the EDCs. On October 19, 2018, FERC issued an order accepting the TSAs for filing as CMP rate schedules effective as of October 20, 2018. On June 25, 2019, the Massachusetts DPU issued an Order approving the NECEC project long term PPAs and the cost recovery by the EDCs of the TSA charges. This Order was subsequently appealed by NextEra Energy Resources. On September 3, 2020, the Massachusetts Supreme Judicial Court denied NextEra Energy Resources’ appeal of the DPU Order.

The NECEC project requires a Certificate of Public Convenience and Necessity, or CPCN, from the MPUC. On May 3, 2019, the MPUC issued an Order granting the CPCN for the NECEC project. This Order was subsequently appealed by NextEra Energy Resources. On March 17, 2020, the Maine Law Court denied NextEra Energy Resources’ appeal of the CPCN.

On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks, pursuant to the terms of a transfer agreement dated November 3, 2020.

The NECEC project requires certain permits, including environmental, from multiple state and federal agencies and a presidential permit from the U.S. Department of Energy, or DOE, authorizing the construction, operation, maintenance and connection of facilities for the transmission of electric energy at the international border between the United States and Canada. On January 8, 2020, the Maine Land Use Planning Commission, or LUPC, granted the LUPC Certification for the NECEC. The Maine Department of Environmental Protection, or MDEP, granted Site Location of Development Act, Natural Resources Protection Act, and Water Quality Certification permits for the NECEC by an Order dated May 11, 2020. The MDEP Order was appealed by certain intervenors. Through an Order dated July 21, 2022, the Maine Board of Environmental Protection, or MBEP, denied the appeals of the MDEP Order, as well as the appeal of MDEP’s December 4, 2020 Order approving the partial transfer of the permits for the project to NECEC Transmission LLC. In August 2022, the intervenors that had appealed the MDEP Order appealed the MBEP Order, and these appeals have all been dismissed.

On November 6, 2020, the project received the required approvals from the U.S. Army Corps of Engineers, or Army Corps, pursuant to Section 10 of the Rivers and Harbor Act of 1899 and Section 404 of the Clean Water Act. A complaint for declaratory and injunctive relief asking the court to, among other things, vacate or remand the Section 404 Clean Water Act permit for the NECEC project filed by three environmental groups is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.

ISO-NE issued the final System Impact Study (SIS) for NECEC on May 13, 2020, determining the upgrades required to permit the interconnection of NECEC to the ISO-NE system. On July 9, 2020, the project received the formal I.3.9 approval associated with this interconnection request. CMP, NECEC Transmission LLC and ISO-NE executed an interconnection agreement. With respect to the upgrade required at the Seabrook Nuclear Generation Station, or Seabrook Station, on February 1, 2023, FERC issued an order granting in part Avangrid and NECEC Transmission LLC’s complaint against NextEra Energy Resources, LLC and NextEra Energy Seabrook, LLC, or Seabrook, denying in part Avangrid and NECEC Transmission LLC’s complaint, and dismissing Seabrook’s petition for declaratory order. Among other things, FERC directed Seabrook to replace the breaker at Seabrook Station pursuant to its obligations under Seabrook Station’s large generator interconnection agreement and good utility practice. Furthermore, FERC determined that Seabrook should not recover opportunity or legal costs in connection with the breaker replacement. NextEra sought reconsideration of FERC’s decision, which was denied in April 2023

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and by further FERC order in June 2023. NextEra has appealed that decision to the U.S. Court of Appeals for the D.C. Circuit, where it remains pending. We cannot predict the outcome of this proceeding.

On January 14, 2021, the DOE issued a Presidential Permit granting permission to NECEC Transmission LLC to construct, operate, maintain and connect electric transmission facilities at the international border of the United States and Canada. On March 26, 2021, the plaintiffs challenging the Army Corps permit filed a motion for leave before the District Court in Maine to supplement their complaint to add claims against DOE in connection with the Presidential Permit. On April 20, 2021, the District Court granted the plaintiffs motion to amend the complaint. On April 22, 2021, the plaintiffs filed their amended complaint asking the Court, among other things, to vacate, set aside, remand or stay the Presidential Permit. This challenge to the Presidential Permit is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.

On November 2, 2021, Maine voters approved, by virtue of a referendum, L.D. 1295 (I.B. 1) (130th Legis. 2021), “An Act To Require Legislative Approval of Certain Transmission Lines, Require Legislative Approval of Certain Transmission Lines and Facilities and Other Projects on Public Reserved Lands and Prohibit the Construction of Certain Transmission Lines in the Upper Kennebec Region” (the “Initiative”), which per its terms would retroactively apply to the NECEC project.

On November 3, 2021, Networks and NECEC Transmission LLC filed a lawsuit challenging the constitutionality of the Initiative and requesting injunctive relief preventing retroactive enforcement of the Initiative to the NECEC transmission project. Networks and NECEC Transmission LLC also requested a preliminary injunction preventing such retroactive enforcement during the pendency of the lawsuit, which was ultimately denied. The Initiative took effect on December 19, 2021.

On December 22, 2021, Networks and NECEC Transmission LLC moved that the Business & Consumer Court report its decision to the Maine Law Court for an interlocutory appeal under the applicable rule of appellate procedure. The Business & Consumer Court granted this motion, thereby sending its decision to the Law Court for review. On August 30, 2022, the Law Court ruled that certain Initiative provisions would infringe on NECEC’s constitutionally protected vested rights if NECEC Transmission LLC can demonstrate that it engaged in substantial construction of the NECEC project in good-faith reliance of the authority under the CPCN granted by the MPUC before Maine voters approved the Initiative. The Maine Law Court remanded the matter to the Business & Consumer Court for a trial to determine that question. The trial began on April 10, 2023 and concluded on April 20, 2023, when the jury reached a unanimous decision finding that NECEC had constructed substantial construction in good faith. The Court subsequently entered an Order that NECEC had obtained vested rights to continue work on the project, and that retroactively applying the Initiative to the NECEC project would violate the Maine Constitution. No party appealed that decision.

In connection with the lease granted by BPL over a small area of Maine public lands to house a 0.9-mile section of the NECEC, on November 29, 2022, the Law Court vacated the trial court’s prior decision to reverse BPL’s decision to grant the lease.

On August 3, 2023, NECEC resumed limited construction and is continuing to evaluate the construction schedule for the NECEC project, related commercial operation date, and total project cost, including potential impacts from increased construction costs, disputes with third party vendors regarding contracts and certain change orders, and a decrease in expected returns. As of March 31, 2024, we have capitalized approximately $920 million for the NECEC project, which includes capitalized interest costs and other additional payments related to the project along with construction costs.

At the municipal level, the project has obtained all approvals.

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.

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Following oral arguments in October 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. This matter has been briefed and oral argument was held December 11, 2023. We cannot predict the outcome of this proceeding.

Power Tax Audits

Previously, CMP, NYSEG and RG&E implemented Power Tax software to track and measure their respective deferred tax amounts. In connection with this change, we identified historical updates needed with deferred taxes recognized by CMP, NYSEG and RG&E and increased our deferred tax liabilities, with a corresponding increase to regulatory assets, to reflect the updated amounts calculated by the Power Tax software. Since 2015, the NYPSC and MPUC accepted certain adjustments to deferred taxes and associated regulatory assets for this item in recent distribution rate cases, resulting in regulatory asset balances of approximately $11 million and $12 million, respectively, for this item at March 31, 2024 and December 31, 2023.

CMP began recovering its regulatory asset in 2020. In 2017, the NYPSC commenced an audit of the power tax regulatory assets. On January 11, 2018, the NYPSC issued an order opening an operations audit of NYSEG and RG&E and certain other New York utilities regarding tax accounting. In September 2023, NYSEG and RG&E received the NYPSC final audit report and in October 2023 we responded with comments and a request for certain clarifications. The report includes recommendations that are primarily intended to enhance existing practices. The NYPSC audit process was completed and the final audit report issued by the Commission on November 21, 2023 with no impacts to the recorded regulatory assets.

SEC's Climate Disclosure Rule

On March 6, 2024, the SEC issued a final rule that requires registrants to provide climate-related disclosures in their annual reports and registration statements, beginning with annual reports for the year ending December 31, 2025, for calendar-year-end large accelerated filers. On April 4, 2024, the SEC announced to voluntarily delay the implementation of climate disclosure regulations while going through certain legal challenges filed to vacate the proposed rules.

The new rules include disclosures relating to climate-related risks and risk management as well as the board and management’s governance of such risks. In addition, the rules include requirements to disclose the financial effects of severe weather events and other natural conditions in the audited financial statements. Larger registrants will also be required to disclose information about greenhouse gas emissions, which will be subject to a phased-in assurance requirement. We are currently evaluating the new rules and their impact to our systems, processes, and controls for gathering and reporting of these incremental disclosures.

Anti-Circumvention Petition

We are monitoring the Department of Commerce's, or DOC, anti-circumvention petition alleging that solar panels and cells shipped from Vietnam, Thailand, Malaysia and Cambodia have circumvented tariffs imposed on Chinese solar panels and cells. The petition calls for anti-dumping and countervailing duties to be applied to solar panels. In June 2022, President Biden's Administration announced a 24-month tariff exemption on any potential tariff resulting from the anti-circumvention investigation. On August 18, 2023, DOC issued final rulings, concluding some manufacturers operating in the named countries circumvented the AD/CVD duties on a country-wide basis. Renewables is taking steps intended to mitigate potential risks to their solar project development portfolio. To date, there has been no material impact on Renewables' operations or financial performance as a result of this investigation. Despite the 24-month tariff exemption, there is uncertainty around related long-term effects to the solar panel supply chain and we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

Coast Guard Authorization Bill

In April 2023, the House Transportation and Infrastructure Committee included maritime crewing provisions within the Coast Guard Authorization bill which passed the committee. The bill was not included in the House National Defense Authorization Act - there is no clear path for passage at this point. If enacted, the Coast Guard authorization may only allow foreign vessels to operate on the Outer Continental Shelf if they have a U.S. crew or the crew of the nation of which the vessel is from. If passed, the legislation could affect expected timelines and returns on approved projects. To date, there has been no material impact on Renewables' operations or financial performance as a result of these bills; however, given the uncertainty of resolution of the final legislation and the related effects to our offshore projects, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

New York Climate Leadership and Community Protection Act

On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act as part of

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the Climate Leadership and Community Protection Act (CLCPA) Phase 2. The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.2 billion, including participation with other upstate utilities on certain projects. On October 17, 2023, NYSEG and RG&E filed a petition requesting approval from the NYPSC to seek authorization from the Federal Energy Regulatory Commission, or FERC, to utilize 100 percent construction work in progress, or CWIP, in rate base for the local transmission upgrades under the CLCPA Phase 2. On April 18, 2024, the NYPSC approved the petition to allow NYSEG and RG&E to seek FERC approval along with adding other related reporting requirements.

UI RAM Proceeding

On March 1, 2024, UI submitted its 2023 comprehensive rate adjustment mechanism, or RAM, filing detailing the UI’s calculated over- or under-recoveries for the RAM components for the period of January 1, 2023, through December 31, 2023 (RAM Application) to PURA. The RAM Application detailed the UI’s proposed weighted-average rate adjustments associated with such over- or under-recoveries of the RAM components.

PURA held a noticed public hearing on this matter on March 11, 2024, and on March 28, 2024, a proposed Interim Decision was issued in this proceeding to provide an opportunity for the parties and intervenors to file written exceptions and to present Oral Argument, which was heard on April 4, 2024. On April 17, 2024, PURA conditionally approved rates for UI's RAM components effective July 1, 2024, through April 30, 2025, subject to its final prudency review of UI's 2023 reported RAM costs.

Results of Operations

The following tables set forth financial information by segment for each of the periods indicated:

	Three Months Ended								Three Months Ended
	March 31, 2024								March 31, 2023
	Total		Networks		Renewables		Other(1)		Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	2,417	$	2,018	$	400	$	(1)	$	2,466	$	2,076	$	390	$	—
Operating Expenses
Purchased power, natural gas and fuel used	724		643		81		—		977		833		144		—
Operations and maintenance	792		676		118		(2)		761		631		130		—
Depreciation and amortization	298		178		118		2		280		174		105		1
Taxes other than income taxes	196		168		23		5		183		161		21		1
Total Operating Expenses	2,010		1,665		340		5		2,201		1,799		400		2
Operating Income	407		353		60		(6)		265		277		(10)		(2)
Other Income (Expense)
Other income (expense)	54		58		1		(5)		25		29		2		(6)
Earnings (losses) from equity method investments	6		4		2		—		2		4		(2)		—
Interest expense, net of capitalization	(125)		(89)		(4)		(32)		(95)		(70)		(6)		(19)
Income (Loss) Before Income Tax	342		326		59		(43)		197		240		(16)		(27)
Income tax expense (benefit)	20		57		(6)		(31)		(18)		44		(34)		(28)
Net Income (Loss)	322		269		65		(12)		215		196		18		1
Net loss (income) attributable to noncontrolling interests	29		(1)		30		—		30		(1)		31		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	351	$	268	$	95	$	(12)	$	245	$	195	$	49	$	1

(1)"Other" represents Corporate and intersegment eliminations.

Comparison of Period to Period Results of Operations

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

Operating Revenues

Our operating revenues decreased by $49 million from $2,466 million for the three months ended March 31, 2023 to $2,417 million for the three months ended March 31, 2024, as detailed by segment below:

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Networks

Operating revenues decreased by $58 million from $2,076 million for the three months ended March 31, 2023 to $2,018 million for the three months ended March 31, 2024. The decrease in operating revenues is primarily due to a decrease of $190 million in purchased power and purchased gas (offset in purchased power) driven by lower average pricing in commodities in the period, offset by an increase of $15 million in flow through amortizations (offset in operating expenses). Additionally, electricity and gas revenues increased by $84 million, primarily due to rate increases in New York effective October 12, 2023, and a $33 million favorable impact from deferrals mainly driven by new regulatory mechanisms established by the rate case in New York.

Renewables

Operating revenues increased by $10 million from $390 million for the three months ended March 31, 2023, to $400 million for the three months ended March 31, 2024. The increase in operating revenues was primarily due to an increase of $30 million in favorable thermal and power trading due to wider spark spreads in the period primarily driven by weather, $26 million increase in merchant prices driven by higher average prices in the current period, offset by unfavorable MtM changes of $26 million on energy derivative transactions entered for economic hedging purposes and a $20 million decrease from production in the current period.

Purchased Power, Natural Gas and Fuel Used

Purchased power, natural gas and fuel used increased by $253 million from $977 million for the three months ended March 31, 2023 to $724 million for the three months ended March 31, 2024, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used decreased by $190 million from $833 million for the three months ended March 31, 2023 to $643 million for the three months ended March 31, 2024. The decrease is primarily driven by a $190 million decrease in average commodity prices and an overall decrease in electricity and gas units procured due to lower degree days in the period.

Renewables

Purchased power, natural gas and fuel used decreased by $63 million from $144 million for the three months ended March 31, 2023 to $81 million for the three months ended March 31, 2024. The decrease is primarily due to favorable MtM changes on derivatives of $47 million driven by market price changes in the period and a decrease of $16 million in power and gas purchases due to lower average prices in the current period.

Operations and Maintenance

Operations and maintenance expenses increased by $31 million from $761 million for the three months ended March 31, 2023 to $792 million for the three months ended March 31, 2024, as detailed by segment below:

Networks

Operations and maintenance expenses increased by $45 million from $631 million for the three months ended March 31, 2023 to $676 million for the three months ended March 31, 2024. The increase is driven by a $20 million increase in personnel expenses primarily driven by higher headcount and $10 million increase in uncollectible expenses due to higher bad debt provision in the current period. In addition, there were increases of $15 million in flow-through amortizations (which is offset in revenue).

Renewables

Operations and maintenance expenses decreased by $12 million from $130 million for the three months ended March 31, 2023 to $118 million for the three months ended March 31, 2024. The decrease is primarily due to a $17 million favorable change in operating costs primarily driven by increase in capitalized maintenance services in the current period, offset by a $5 million increase driven by the write-off of certain development assets.

Depreciation and Amortization

Depreciation and amortization for the three months ended March 31, 2024 was $298 million compared to $280 million for the three months ended March 31, 2023, an increase of $18 million. The increase is primarily driven by $15 million from plant additions in Networks and Renewables, and $3 million impact of accelerated depreciation from the repowering of wind farms in the current period.

Other Income (Expense) and Earnings (Losses) from Equity Method Investments

Other income (expense) and equity earnings (losses) increased by $33 million from $27 million for the three months ended March 31, 2023 to $60 million for the three months ended March 31, 2024. The increase is primarily due to a $18 million

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increase in allowance for funds used during construction in Networks primarily driven by the NECEC project construction, $11 million increase in carrying costs on regulatory deferrals and a $4 million of favorable equity earnings in the current period.

Interest Expense, Net of Capitalization

Interest expense for the three months ended March 31, 2024 and 2023 was $125 million and $95 million, respectively. The change is primarily due to a $17 million increase in interest expense mainly driven by increased debt in the period at Networks and a $28 million increase in Other mainly driven by increased outstanding balances on commercial paper and the intragroup loan and unfavorable changes in the fair value hedges in the current period, offset by $15 million of capitalized interest driven by higher interest rates in the period.

Income Tax

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2024 was 5.8% which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items, partially offset by tax equity financing impacts and state taxes. The 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.

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented in accordance with U.S. GAAP, we consider adjusted net income and adjusted earnings per share, adjusted EBITDA and adjusted EBITDA with Tax Credits as financial measures that are not prepared in accordance with U.S. GAAP. The non-GAAP financial measures we use are specific to Avangrid and the non-GAAP financial measures of other companies may not be calculated in the same manner. We use these non-GAAP financial measures, in addition to U.S. GAAP measures, to establish operating budgets and operational goals to manage and monitor our business, evaluate our operating and financial performance and to compare such performance to prior periods and to the performance of our competitors. We believe that presenting such non-GAAP financial measures is useful because such measures can be used to analyze and compare profitability between companies and industries by eliminating the impact of certain non-cash charges. In addition, we present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance.

We define adjusted net income as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments and accelerated depreciation from the repowering of wind farms. We believe adjusted net income is more useful in understanding and evaluating actual and projected financial performance and contribution of Avangrid core lines of business and to more fully compare and explain our results. The most directly comparable U.S. GAAP measure to adjusted net income is net income. We also define adjusted earnings per share, or adjusted EPS, as adjusted net income converted to an earnings per share amount.

We define adjusted EBITDA as adjusted net income adjusted to fully exclude the effects of net (loss) income attributable to noncontrolling interests, income tax expense (benefit), depreciation and amortization, interest expense, net of capitalization, other (income) expense and (earnings) losses from equity method investments. We further define adjusted EBITDA with tax credits as adjusted EBITDA adding back the pre-tax effect of retained Production Tax Credits (PTCs) and Investment Tax Credits (ITCs) and PTCs allocated to tax equity investors. The most directly comparable U.S. GAAP measure to adjusted EBITDA and adjusted EBITDA with tax credits is net income.

The use of non-GAAP financial measures is not intended to be considered in isolation or as a substitute for, or superior to, Avangrid’s U.S. GAAP financial information, and investors are cautioned that the non-GAAP financial measures are limited in their usefulness, may be unique to Avangrid and should be considered only as a supplement to Avangrid’s U.S. GAAP financial measures. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools.

Non-GAAP financial measures are not primary measurements of our performance under U.S. GAAP and should not be considered as alternatives to operating income, net income or any other performance measures determined in accordance with U.S. GAAP.

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The following tables provide a reconciliation between Net Income attributable to Avangrid and non-GAAP measures Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA with Tax Credits by segment for the three months ended March 31, 2024 and 2023, respectively:

	Three Months Ended March 31, 2024
	Total		Networks		Renewables		Corporate*
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	351	$	268	$	95	$	(11)
Adjustments:
Mark-to-market adjustments - Renewables	(17)		—		(17)		—
Accelerated depreciation from repowering	3		—		3		—
Income tax impact of adjustments (1)	4		—		4		—
Adjusted Net Income (2)	$	341	$	268	$	84	$	(11)
Net (loss) income attributable to noncontrolling interests	(29)		1		(30)		—
Income tax expense (benefit)	16		57		(10)		(31)
Depreciation and amortization	298		178		118		2
Interest expense, net of capitalization	125		89		4		32
Other (income) expense	(54)		(58)		(1)		5
(Earnings) losses from equity method investments	(6)		(4)		(2)		—
Adjusted EBITDA (3)	$	691	$	531	$	163	$	(3)
Retained PTCs and ITCs	47		—		47		—
PTCs allocated to tax equity investors	36		—		36		—
Adjusted EBITDA with Tax Credits (3)	$	775	$	531	$	247	$	(3)

	Three Months Ended March 31, 2023
	Total		Networks		Renewables		Corporate*
	(in millions)
Net Income (Loss) Attributable to Avangrid, Inc.	$	245	$	195	$	49	$	1
Adjustments:
Mark-to-market earnings – Renewables	4		—		4		—
Income tax impact of adjustments (1)	(1)		—		(1)		—
Adjusted Net Income (2)	$	248	$	195	$	51	$	1
Net (loss) income attributable to noncontrolling interests	(30)		1		(31)		—
Income tax expense (benefit)	(17)		44		(33)		(28)
Depreciation and amortization	280		174		105		1
Interest expense, net of capitalization	95		70		6		19
Other (income) expense	(25)		(29)		(2)		6
(Earnings) losses from equity method investments	(2)		(4)		2		—
Adjusted EBITDA (3)	$	549	$	451	$	98	$	—
Retained PTCs and ITCs	45		—		45		—
PTCs allocated to tax equity investors	39		—		39		—
Adjusted EBITDA with Tax Credits (3)	$	633	$	451	$	182	$	—

(1)Income tax impact of adjustments: 2024 - $5 million from MtM earnings and $(1) million from repowering for the three months ended March 31, 2024; 2023 - $(1) million from MtM earnings for the three months ended March 31, 2023.

(2)Adjusted Net Income is a non-GAAP financial measure and is presented after excluding MtM activities in Renewables and accelerated depreciation from the repowering of wind farms.

(3)Adjusted EBITDA is a non-GAAP financial measure defined as adjusted net income adjusted to fully exclude the effects of net (loss) income attributable to noncontrolling interests, income tax expense (benefit), depreciation and amortization, interest expense, net of capitalization, other (income) expense

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and (earnings) losses from equity method investments. We further define adjusted EBITDA with tax credits as adjusted EBITDA adding back the pre-tax effect of retained PTCs and ITCs and PTCs allocated to tax equity investors.

    * Includes corporate and other non-regulated entities as well as intersegment eliminations.

Three Months Ended March 31, 2024 Compared to Three Months Ended March 31, 2023

Adjusted net income

Our adjusted net income increased by $93 million from $248 million for the three months ended March 31, 2023 to $341 million for the three months ended March 31, 2024. The increase is primarily due to a $73 million increase in Networks driven primarily by rate increases in New York effective October 12, 2023, a $33 million increase in Renewables primarily driven by favorable thermal and power trading due to higher average prices in the period primarily due to cold weather, offset by a $13 million decrease in Corporate mainly driven by higher interest expenses in the period.

The following tables reconcile Net Income attributable to Avangrid to Adjusted Net Income (non-GAAP), and EPS attributable to Avangrid to adjusted EPS (non-GAAP) for the three months ended March 31, 2024 and 2023, respectively:

	Three Months Ended
	March 31,
(Millions)	2024		2023
Networks	$	268	$	195
Renewables	95		49
Corporate (1)	(11)		1
Net Income	$	351	$	245
Adjustments:
Mark-to-market adjustments - Renewables (2)	(17)		4
Accelerated depreciation from repowering (3)	3		—
Income tax impact of adjustments	4		(1)
Adjusted Net Income (4)	$	341	$	248

	Three Months Ended
	March 31,
	2024		2023
Networks	$	0.69	$	0.51
Renewables	0.24		0.13
Corporate (1)	(0.03)		—
Net Income	$	0.91	$	0.63
Adjustments:
Mark-to-market adjustments - Renewables (2)	(0.05)		0.01
Accelerated depreciation from repowering (3)	0.01		—
Income tax impact of adjustments	0.01		—
Adjusted Earnings Per Share (4)	$	0.88	$	0.64

(1)Includes corporate and other non-regulated entities as well as intersegment eliminations.

(2)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(3)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

(4)Adjusted Net Income and Adjusted Earnings Per Share are non-GAAP financial measures and are presented after excluding MtM activities in Renewables and accelerated depreciation from the repowering of wind farms.

Liquidity and Capital Resources

Our operations, capital investment and business development require significant short-term liquidity and long-term capital resources. Historically, we have used cash from operations and borrowings under our credit facilities and commercial paper program as our primary sources of liquidity. Our long-term capital requirements have been met primarily through retention of earnings, equity issuances and borrowings in the investment grade debt capital markets. Continued access to these sources of liquidity and capital are critical to us. Risks may increase due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions.

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We and our subsidiaries are required to comply with certain covenants in connection with our respective loan agreements. The covenants are standard and customary in financing agreements, and we and our subsidiaries were in compliance with such covenants as of and throughout the three months ended March 31, 2024.

Liquidity Position

We optimize our liquidity within the United States through a series of arms-length intercompany lending arrangements with our subsidiaries and among our regulated utilities to provide for lending of surplus cash to subsidiaries with liquidity needs, subject to the limitation that the regulated utilities may not lend to unregulated affiliates. These arrangements minimize overall short-term funding costs and maximize returns on the temporary cash investments of the subsidiaries. We have the capacity to borrow up to $3,575 million from the lenders committed to the Avangrid Credit Facility described below

The following table provides the components of our liquidity position as of March 31, 2024 and December 31, 2023, respectively:

	As of March 31,		As of December 31,
	2024		2023
	(in millions)
Cash and cash equivalents	$	152	$	91
Avangrid Credit Facility	3,575		3,575
Iberdrola Group Credit Facility	750		750
Less: borrowings	(2,364)		(1,332)
Total	$	2,113	$	3,084

Avangrid Commercial Paper Program

Avangrid has a commercial paper program with a limit of $2 billion that is backstopped by the Avangrid Credit Facility (described below). As of March 31, 2024 and April 23, 2024, there was $1,864 million and $1,883 million, respectively, of commercial paper outstanding, presented net of discounts on the balance sheet.

Avangrid Credit Facility

Avangrid and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC, each of which are joint borrowers, have a revolving credit facility with a syndicate of banks, or the Avangrid Credit Facility, that provides for maximum borrowings of up to $3,575 million in the aggregate, which was executed on November 23, 2021.

Under the terms of the Avangrid Credit Facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit contained in the agreement. On November 23, 2021, the executed Avangrid Credit Facility increased Avangrid's maximum sublimit from $1,500 million to $2,500 million. The Avangrid Credit Facility contains pricing that is sensitive to Avangrid’s consolidated greenhouse gas emissions intensity. The Credit Facility also contains negative covenants, including one that sets the ratio of maximum allowed consolidated debt to consolidated total capitalization at 0.65 to 1.00, for each borrower. Under the Avangrid Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. The initial facility fees will range from 10 to 22.5 basis points. The maturity date for the Avangrid Credit Facility is November 22, 2026. On July 17, 2023, the Avangrid Credit Facility was amended and restated to, among other things, provide for the replacement of LIBOR-based rates with SOFR-based rates. As of both March 31, 2024 and April 23, 2024, we had $0 of borrowings outstanding under this credit facility.

Since the Avangrid credit facility is also a backstop to the Avangrid commercial paper program, the total amount available under the facility as of both March 31, 2024 and April 23, 2024 was $1,701 million and $1,682 million, respectively.

Iberdrola Group Credit Facility

On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and a maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of March 31, 2024 and April 23, 2024, we had $500 million and $602 million borrowings outstanding under this credit facility, respectively.

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Intragroup Green Loan

On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan).

Capital Requirements

We expect to fund our capital requirements, including, without limitation, any quarterly shareholder dividends and capital investments primarily from the cash provided by operations of our businesses and through the access to the capital markets in the future. We have revolving credit facilities, as described above, to fund short-term liquidity needs and we believe that we will continue to have access to the capital markets as long-term growth capital is needed. While taking into consideration the current economic environment, management expects that we will continue to have sufficient liquidity and financial flexibility to meet our business requirements.

We expect to incur approximately $2.8 billion in capital expenditures through the remainder of 2024. This estimate is subject to continuing review and actual capital expenditures may vary significantly. As a result, the timing and ultimate cost associated with solar panels and cells and related project capital expenditures may vary from our current expectations.

Cash Flows

Our cash flows depend on many factors, including general economic conditions, regulatory decisions, weather, commodity price movements and operating expense and capital spending control.

The following is a summary of the cash flows by activity for the three months ended March 31, 2024 and 2023, respectively:

	Three Months Ended
	March 31,
	2024		2023
	(in millions)
Net cash provided by operating activities	$	153	$	204
Net cash used in investing activities	(944)		(819)
Net cash provided by financing activities	852		618
Net increase in cash, cash equivalents and restricted cash	$	61	$	3

Operating Activities

The cash from operating activities for the three months ended March 31, 2024 compared to the three months ended March 31, 2023 decreased by $51 million, primarily attributable to a net decrease in current assets and liabilities driven by timing of cash collections and cash disbursements during the period and higher interest payments in the current period.

Investing Activities

For the three months ended March 31, 2024, net cash used in investing activities was $944 million, which was comprised of $872 million of capital expenditures and $116 million of capital contributions to the offshore joint venture, partially offset by $40 million of contributions in aid of construction.

For the three months ended March 31, 2023, net cash used in investing activities was $819 million, which was comprised of $836 million of capital expenditures, partially offset by $19 million of contributions in aid of construction.

Financing Activities

For the three months ended March 31, 2024, financing activities provided $852 million in cash reflecting primarily a net increase in current notes payable of $1 billion, contribution from non-controlling interests of $53 million, offset by distributions to non-controlling interests of $39 million and dividends of $170 million in the period.

For the three months ended March 31, 2023, financing activities used $618 million in cash reflecting primarily a net increase in non-current debt and current notes payable of $718 million, contribution from non-controlling interests of $74 million, offset by distributions to non-controlling interests of $3 million and dividends of $170 million in the period.

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Off-Balance Sheet Arrangements

There have been no material changes in our off-balance sheet arrangements during the three months ended March 31, 2024 as compared to those reported for the fiscal year ended December 31, 2023 in our Form 10-K.

Contractual Obligations

There have been no material changes in contractual and contingent obligations during the three months ended March 31, 2024 as compared to those reported for the fiscal year ended December 31, 2023 in our Form 10-K.

Critical Accounting Policies and Estimates

We have prepared the accompanying condensed consolidated financial statements provided herein in accordance with U.S. GAAP. In preparing the accompanying condensed consolidated financial statements, our management has made certain estimates and assumptions that affect the reported amounts of assets, liabilities, stockholders’ equity, revenues and expenses and the disclosures thereof. While we believe that these policies and estimates used are appropriate, actual future events can and often do result in outcomes that can be materially different from these estimates. As of March 31, 2024, the only notable changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2023, are with respect to our adoption of the new accounting pronouncements described in the Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2024.

New Accounting Standards

We review new accounting standards to determine the expected financial effect, if any, that the adoption of each such standard will have. The new accounting pronouncements we have adopted as of January 1, 2024, and reflected in our condensed consolidated financial statements are described in Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2024.

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains a number of forward-looking statements. Forward-looking statements may be identified by the use of forward-looking terms such as “may,” “will,” “should,” “would,” “could,” “can,” “expect(s),” “believe(s),” “anticipate(s),” “intend(s),” “plan(s),” “estimate(s),” “project(s),” “assume(s),” “guide(s),” “target(s),” “forecast(s),” “are (is) confident that” and “seek(s)” or the negative of such terms or other variations on such terms or comparable terminology. Such forward-looking statements include, but are not limited to, statements about our plans, objectives and intentions, outlooks or expectations for earnings, revenues, expenses or other future financial or business performance, strategies or expectations, or the impact of legal or regulatory matters on business, results of operations or financial condition of the business and other statements that are not historical facts. Such statements are based upon the current reasonable beliefs, expectations, and assumptions of our management and are subject to significant risks and uncertainties that could cause actual outcomes and results to differ materially. Important factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC. Specifically, forward-looking statements include, without limitation:

•any statements regarding the proposed transaction with Iberdrola including the expected timetable for the Committee’s review, evaluation, negotiation and recommendation to the board regarding the proposed transaction, the expected timetable or ability to complete the proposed transaction, or the expected benefits of the proposed transaction;

•actions or inactions of local, state or federal regulatory agencies;

•the ability of our regulated utility operations to recover costs in a timely manner or at all or obtain a return on certain assets or invested capital through base rates, cost recovery clauses, other regulatory mechanism;

•potentially material adverse effect on our business, and financial condition due to the purchase and sales of energy commodities and related transportation and services by our operating subsidiaries;

•adverse developments in general market, business, economic, labor, regulatory and political conditions including, without limitation, the impacts of inflation, deflation, supply-chain interruptions and changing prices and labor costs;

•the impact of any change to applicable laws and regulations, including those subject to referendums affecting the ownership and operations of electric and gas utilities and renewable energy generation facilities, respectively, including, without limitation, those relating to the environment and climate change, taxes, price controls, regulatory approval and permitting;

•efforts to maintain a responsive sustainability program;

•new tariffs imposed on imported goods;

•the impact of extraordinary external events, such as any cyber breaches or other incidents, grid disturbances, acts of war or terrorism, civil or social unrest, natural disasters, pandemic health events or other similar occurrences;

•potential restrictions by interconnecting utility and/or RTO rules, policies, procedures and FERC tariffs and market conditions on renewable project operations and ability to generate revenue;

•our rights, and the rights of our subsidiaries to sites that projects are located may be subordinate to the rights of lienholders and leaseholders;

•strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms;

•technological developments;

•geopolitical instability could exacerbate existing risk factors;

•the future financial performance, anticipated liquidity and capital expenditures;

•weather conditions are unfavorable or below production forecasts;

•customary business and market related risks including warranty limitation and expiration as well as PPA expiration or early termination;

•impact of Iberdrola’s influence over stock as well as the future sale of issuance of common stock by Iberdrola;

•the “controlled company” exemption to the corporate governance rules for NYSE-listed companies could make shares of our common stock less attractive to some investors or otherwise harm our stock price;

•our dividend policy is subject to the discretion of our board of directors and may be limited by our debt agreements and limitations under New York law;

•ability to meet our financial obligations and to pay dividends on our common stock if our subsidiaries are unable to pay dividends or repay loans from us;

•the ability to maintain effective internal control over financial reporting;

•our investments and cash balances are subject to the risk of loss;

•the cost and availability of capital to finance our business is inherently uncertain;

•litigation or administrative proceedings;

•inability to insure against all potential risks;

•the ability to recruit and retain a highly qualified and diverse workforce in the competitive labor market;

57

•changes in amount, timing or ability to complete capital projects;

•adverse developments in general market, business, economic, labor, regulatory and political conditions including, without limitation, the impacts of inflation, deflation, supply-chain interruptions and changing prices and labor costs, including the Department of Commerce's anti-circumvention petition that could adversely impact renewable solar energy projects;

•the impacts of climate change, fluctuations in weather patterns and extreme weather events;

•the impact of extraordinary external events, such as any cyber breaches or other incidents, grid disturbances, acts of war or terrorism, civil or social unrest, natural disasters, pandemic health events or other similar occurrences, including the ongoing geopolitical conflict with Russia and Ukraine;

•the impact of a catastrophic or geopolitical event on business and economic conditions;

•the implementation of changes in accounting standards;

•adverse publicity or other reputational harm; and

•other presently unknown unforeseen factors.

Should one or more of these risks or uncertainties materialize, or should any of the underlying assumptions prove incorrect, actual results may vary in material respects from those expressed or implied by these forward-looking statements. You should not place undue reliance on these forward-looking statements. We do not undertake any obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this report, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. Other risk factors are detailed from time to time in our reports filed with the SEC, and we encourage you to consult such disclosures.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in our market risk during the three months ended March 31, 2024, as compared to those reported for the fiscal year ended December 31, 2023 in our Form 10-K.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer, or CEO, and our Chief Financial Officer, or CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on such evaluation, our CEO and CFO have concluded that as of such date, our disclosure controls and procedures were effective.

Changes in Internal Control

There has been no change in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the period covered by this Quarterly Report on Form 10-Q that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

58

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please read “Note 8—Contingencies” and “Note 9—Environmental Liabilities” to the accompanying unaudited condensed consolidated financial statements under Part I, Item 1 of this report for a discussion of legal proceedings that we believe could be material to us.

Item 1A. Risk Factors

Shareholders and prospective investors should carefully consider the risk factors disclosed in our Form 10-K for the fiscal year ended December 31, 2023. The only significant change to our risk factors relates to the following item:

Risk Factors Relating to Ownership of Our Common Stock

There is no assurance that Iberdrola, S.A.’s expression of interest will result in a definitive transaction and, the absence of such, changes to the proposal, and commencement of related litigation may have an adverse impact on the market price of our common stock

On March 6, 2024, the Unaffiliated Committee, or the Committee, of the Board of Directors, or the Board, of Avangrid received a non-binding proposal from Iberdrola, S.A., or Iberdrola, to acquire all of the issued and outstanding shares of common stock of Avangrid not owned by Iberdrola or its affiliates for $34.25 in cash per share (the Non-Binding Proposal). Iberdrola owns approximately 81.6% of Avangrid’s issued and outstanding shares of common stock. The public announcement of the receipt of the Non-Binding Proposal affected the price of Avangrid’s shares of common stock.

On March 6, 2024, the Board met and determined that the Committee will review, evaluate, negotiate, and approve or disapprove the Non-Binding Proposal, advised by independent legal and financial advisers, as well as any other alternative proposals or other strategic alternatives that may be available to Avangrid. The consummation of the proposed transaction in the Non-Binding Proposal is conditioned upon the approval of the proposed transaction by the Committee and by the Avangrid shareholders that hold in the aggregate a majority of the outstanding shares of common stock that are not held by Iberdrola, S.A. and its affiliates.

The Committee is currently exploring strategic alternatives, including whether to continue as a public, independent company or as a privately held company, given Iberdrola’s indication in the Non-Binding Proposal that Iberdrola does not intend to sell any shares of Avangrid common stock it owns. No decision has yet been made with respect to Avangrid’s response to the Non-Binding Proposal or any alternatives thereto. The Board cautions that it has only received a Non-Binding Proposal, which does not constitute an offer or proposal capable of acceptance and may be withdrawn at any time and in any manner. There can be no assurance that any definitive offer will be made, that any agreement will be executed, or that the transaction proposed in the Non-Binding Proposal, or any other transaction, will be approved or completed. The absence of a definite offer to acquire Avangrid’s common shares, or changes in the Non-Binding Proposal, as well as the commencement of litigation regarding the Non-Binding Proposal, would likely have an adverse effect on the market price of Avangrid’s shares of common stock.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

59

Item 6. Exhibits

The following documents are included as exhibits to this Form 10-Q:

Exhibit Number	Description
31.1	Chief Executive Officer Certification pursuant to Rule 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
31.2	Chief Financial Officer Certification pursuant to Rule 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.*
32	Certification pursuant to 18 United States Code Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
101.INS	XBRL Instance Document.*
101.SCH	XBRL Taxonomy Extension Schema Document.*
101.CAL	XBRL Taxonomy Extension Calculation Linkbase Document.*
101.DEF	XBRL Taxonomy Extension Definition Linkbase Document.*
101.LAB	XBRL Taxonomy Extension Label Linkbase Document.*
101.PRE	XBRL Taxonomy Extension Presentation Linkbase Document.*

*Filed herewith.

†Compensatory plan or agreement.

60

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.

		Avangrid, Inc.
Date: April 24, 2024	By:	/s/ Pedro Azagra Blázquez
		Pedro Azagra Blázquez
		Director and Chief Executive Officer

Date: April 24, 2024	By:	/s/ Justin B. Lagasse
		Justin B. Lagasse
		Senior Vice President - Chief Financial Officer and Controller

61

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Pedro Azagra Blázquez, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Avangrid, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 24, 2024	/s/ Pedro Azagra Blázquez
	Pedro Azagra Blázquez
	Director and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Justin B. Lagasse, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Avangrid, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 24, 2024	/s/ Justin B. Lagasse
	Justin B. Lagasse
	Senior Vice President - Chief Financial Officer and Controller

EX-32

EXHIBIT 32

CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Pursuant to 18 U.S.C. Section 1350, the undersigned, Pedro Azagra Blázquez and Justin B. Lagasse, the Chief Executive Officer and Chief Financial Officer, respectively, of Avangrid, Inc. (the “issuer”), do each hereby certify that the issuer’s quarterly report on Form 10-Q for the quarter ended March 31, 2024, to which this certification is attached as an exhibit (the “report”), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)) and that information contained in the report fairly presents, in all material respects, the financial condition and results of operations of the issuer.

/s/ Pedro Azagra Blázquez

Pedro Azagra Blázquez

Director and Chief Executive Officer

Avangrid, Inc.

April 24, 2024

/s/ Justin B. Lagasse

Justin B. Lagasse

Senior Vice President - Chief Financial Officer and Controller

Avangrid, Inc.

April 24, 2024

XML

Cover Page - shares	3 Months Ended
	Mar. 31, 2024	Apr. 23, 2024
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2024
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		386,906,260
Amendment Flag	false
Document Fiscal Year Focus	2024
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001634997
Current Fiscal Year End Date	--12-31

XML

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Income Statement [Abstract]
Operating Revenues	$ 2,417	$ 2,466
Operating Expenses
Purchased power, natural gas and fuel used	724	977
Operations and maintenance	792	761
Depreciation and amortization	298	280
Taxes other than income taxes	196	183
Total Operating Expenses	2,010	2,201
Operating Income	407	265
Other Income and (Expense)
Other income	54	25
Earnings from equity method investments	6	2
Interest expense, net of capitalization	(125)	(95)
Income Before Income Tax	342	197
Income tax expense (benefit)	20	(18)
Net Income	322	215
Net loss attributable to noncontrolling interests	29	30
Net Income Attributable to Avangrid, Inc.	$ 351	$ 245
Earnings Per Common Share, Basic (in dollars per share)	$ 0.91	$ 0.63
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.91	$ 0.63
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	386,916,234	386,744,996
Diluted (in shares)	387,239,544	387,077,213

XML

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Net Income	$ 322	$ 215
Other Comprehensive Income
Unrealized loss from equity method investment, net of income taxes of $0 and $0, respectively	0	(1)
Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $15 and $(1), respectively	39	(2)
Reclassification to net income of loss on cash flow hedges, net of income taxes $2 and $18, respectively	7	52
Other Comprehensive Income	46	49
Comprehensive Income	368	264
Net loss attributable to noncontrolling interests	29	30
Comprehensive Income Attributable to Avangrid, Inc.	$ 397	$ 294

XML

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Comprehensive Income [Abstract]
Unrealized gain from equity method investment, income taxes	$ 0	$ 0
Unrealized loss during the period on derivatives qualifying as cash flow hedges, income taxes	(15)	1
Reclassification to net income of loss on cash flow hedges, income taxes	$ (2)	$ (18)

XML

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Current Assets
Cash and cash equivalents	$ 152	$ 91
Derivative assets	87	68
Fuel and gas in storage	169	185
Materials and supplies	321	310
Prepayments and other current assets	496	429
Regulatory assets	745	718
Total Current Assets	3,619	3,404
Total Property, Plant and Equipment ($2,621 and $2,643 related to VIEs, respectively)	33,323	32,857
Operating lease right-of-use assets	204	195
Equity method investments	836	718
Other investments	49	46
Regulatory assets	3,061	2,811
Other Assets
Goodwill	3,119	3,119
Intangible assets	280	284
Derivative assets	185	162
Other	386	393
Total Other Assets	3,970	3,958
Total Assets	45,062	43,989
Current Liabilities
Current portion of debt	729	612
Interest accrued	116	104
Accounts payable and accrued liabilities	1,769	1,924
Dividends payable	171	170
Taxes accrued	88	66
Operating lease liabilities	15	16
Derivative liabilities	66	64
Other current liabilities	584	662
Regulatory liabilities	275	261
Total Current Liabilities	6,208	5,239
Regulatory liabilities	2,676	2,694
Other Non-current Liabilities
Deferred income taxes	2,501	2,451
Deferred income	979	996
Pension and other postretirement	546	554
Operating lease liabilities	208	199
Derivative liabilities	116	111
Asset retirement obligations	310	306
Environmental remediation costs	243	254
Other	527	525
Total Other Non-current Liabilities	5,430	5,396
Total Non-current Liabilities	17,965	18,074
Total Liabilities	24,173	23,313
Commitments and Contingencies	0	0
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 388,008,132 and 387,872,787 shares issued; 386,906,260 and 386,770,915 shares outstanding, respectively	4	4
Additional paid in capital	17,702	17,701
Treasury stock	(47)	(47)
Retained earnings	2,196	2,015
Accumulated other comprehensive income (loss)	21	(25)
Total Stockholders’ Equity	19,876	19,648
Non-controlling interests	1,013	1,028
Total Equity	20,889	20,676
Total Liabilities and Equity	45,062	43,989
Nonrelated Party
Current Assets
Accounts receivable and unbilled revenues, net	1,640	1,588
Current Liabilities
Notes payable	1,862	1,347
Other Non-current Liabilities
Non-current debt	9,059	9,184
Related Party
Current Assets
Accounts receivable and unbilled revenues, net	5	11
Notes receivable from affiliates	4	4
Current Liabilities
Notes payable	515	13
Accounts payable to affiliates	18	0
Other Non-current Liabilities
Non-current debt	$ 800	$ 800

XML

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Property, plant and equipment	$ 33,323	$ 32,857
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)	388,008,132	387,872,787
Common stock, outstanding (in shares)	386,906,260	386,770,915
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 2,621	$ 2,643

XML

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Cash Flow from Operating Activities:
Net Income	$ 322	$ 215
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	298	280
Regulatory assets/liabilities amortization and carrying cost	15	(32)
Pension cost	(3)	(3)
Earnings from equity method investments	(6)	(2)
Distributions of earnings received from equity method investments	3	6
Unrealized (gain) loss on marked-to-market derivative contracts	(17)	4
Deferred taxes	4	(1)
Other non-cash items	(22)	(5)
Changes in operating assets and liabilities:
Current assets	(141)	82
Noncurrent assets	(255)	(96)
Current liabilities	(32)	(242)
Noncurrent liabilities	(13)	(2)
Net Cash Provided by Operating Activities	153	204
Cash Flow from Investing Activities:
Capital expenditures	(872)	(836)
Contributions in aid of construction	40	19
Proceeds from sale of assets	2	6
Proceeds from notes receivable from affiliates	0	1
Distributions received from equity method investments	2	2
Other investments and equity method investments, net	(116)	(11)
Net Cash Used in Investing Activities	(944)	(819)
Cash Flow from Financing Activities:
Repayments of non-current debt	(3)	(4)
Repayments of financing leases	(1)	(1)
Issuance of common stock	(2)	0
Distributions to noncontrolling interests	(39)	(3)
Contributions from noncontrolling interests	53	74
Dividends paid	(170)	(170)
Net Cash Provided by Financing Activities	852	618
Net Increase in Cash, Cash Equivalents and Restricted Cash	61	3
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	94	72
Cash, Cash Equivalents and Restricted Cash, End of Period	155	75
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	103	56
Cash paid (refunded) for income taxes	3	(1)
Nonrelated Party
Cash Flow from Financing Activities:
Receipts of other short-term debt, net	514	722
Related Party
Cash Flow from Financing Activities:
Receipts of other short-term debt, net	$ 500	$ 0

XML

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, 2022	[1]			386,628,586
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	[1]			386,640,918
Balance, end of period at Mar. 31, 2023		$ 20,510	19,507	$ 3		17,697	(47)	1,985	(131)	1,003
Balance, beginning of period (in shares) at Dec. 31, 2023		386,770,915		386,770,915	[1]
Balance, beginning of period at Dec. 31, 2023		$ 20,676	19,648	$ 4		17,701	(47)	2,015	(25)	1,028
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		322	351					351		(29)
Other comprehensive income (loss), net of tax		46	46						46
Comprehensive Income		368
Dividends declared		(170)	(170)					(170)
Issuances of common stock (in shares)	[1]			135,345
Issuance of common stock		(2)				(2)
Stock-based compensation		3	3			3
Distributions to noncontrolling interests		(39)								(39)
Contributions from noncontrolling interests		$ 53								53
Balance, end of period (in shares) at Mar. 31, 2024		386,906,260		386,906,260	[1]
Balance, end of period at Mar. 31, 2024		$ 20,889	$ 19,876	$ 4		$ 17,702	$ (47)	$ 2,196	$ 21	$ 1,013

[1] (*) Par value of share amounts is $0.01

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Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Statement of Stockholders' Equity [Abstract]
Other comprehensive loss, tax	$ 17	$ 17
Dividends declared (in dollars per share)	$ 0.44	$ 0.44
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01

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Background and Nature of Operations

3 Months Ended

Mar. 31, 2024

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).

Non-binding proposal from Iberdrola

On March 6, 2024, the Unaffiliated Committee (Committee) of the Board of Directors of Avangrid received a non-binding proposal from Iberdrola to acquire all of the issued and outstanding shares of common stock not owned by Iberdrola or its affiliates for $34.25 in cash per share. The Committee will review, evaluate, negotiate, and approve or disapprove the proposal, advised by independent legal and financial advisers, as well as any other alternative proposals or other strategic alternatives that may be available to Avangrid. No decision has yet been made with respect to Avangrid’s response to the proposal or any alternatives thereto and there can be no assurance that any definitive offer will be made, that any agreement will be executed or that the transaction proposed in the proposal or any other transaction will be approved or completed. The consummation of the proposed transaction is conditioned upon the approval of the proposed transaction by the Committee and by the shareholders of Avangrid that hold in the aggregate a majority of the outstanding shares of common stock that are not held by Iberdrola and its affiliates

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Basis of Presentation

3 Months Ended

Mar. 31, 2024

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, 2023.

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, 2024, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2024.

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Significant Accounting Policies and New Accounting Pronouncements

3 Months Ended

Mar. 31, 2024

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, 2024, 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, 2023, 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) Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued guidance requiring incremental disclosures for reportable segments. These incremental requirements include disclosing significant expenses that are regularly provided to the chief operating decision maker (CODM) and other segment items, including a description of its composition. The other segment items category is the difference between segment revenue less the significant segment expenses, and each reported measure of segment profit or loss. The guidance clarifies that if the CODM reviews multiple measures of a segments total profit or loss, that the entity may under certain conditions report multiple measures in the segment footnote; however, if only one measure is reported, it should be the one that

best conforms with U.S. GAAP. The guidance requires disclosure of the title and position of the individual or the name of the group identified as the CODM. Finally, all annual disclosures are required in interim reporting starting in the first quarter of 2025. As the guidance impacts disclosures only, it will not have an impact to the consolidated financial results. These changes in disclosures will initially be reflected in the annual financial statement footnotes for the year ended December 31, 2024.

Accounting Pronouncements Issued but Not Yet Adopted

The following are new significant accounting pronouncements not yet adopted, including those issued since December 31, 2023, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Improvements to Income Tax Disclosures

In December 2023, the FASB issued guidance to enhance income tax disclosures. The standard is required to be adopted by public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. The two primary enhancements relate to disaggregation of the annual effective tax rate reconciliation and income taxes paid disclosures. For the rate reconciliation, it requires additional disaggregation of information in a tabular format using both percentages and amounts broken out into specific categories (e.g., state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, and changes in unrecognized tax benefits). For income taxes paid, it requires disaggregation by jurisdiction (e.g., federal, state and foreign). We do not expect the new guidance to have a material impact on our consolidated results of operations, financial position and cash flows.

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Revenue

3 Months Ended

Mar. 31, 2024

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 the FASB issued ASC Topic 606, Revenue from Contracts with Customers (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 significant financing elements in any of the arrangements. 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.

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 Assets and Liabilities

We have contract assets for costs from development success fees and construction delays, which were paid during solar farm assets development period. The contract assets are amortized ratably into expense over the 16 - 21 year life of the respective power purchase agreements (PPAs). Contract assets totaled $19 million and $9 million at  March 31, 2024 and December 31, 2023, respectively, and are presented in "Other non-current assets" on our condensed consolidated balance sheets.

We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $9 million and $18 million at March 31, 2024 and December 31, 2023, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $9 million and $17 million as revenue related to contract liabilities for the three months ended March 31, 2024 and 2023, respectively.

We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2024 and 2023 are as follows:

	Three Months Ended March 31, 2024
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,350	$	—	$	—	$	1,350
Regulated operations – natural gas	592		—		—		592
Nonregulated operations – wind	—		224		—		224
Nonregulated operations – solar	—		7		—		7
Nonregulated operations – thermal	—		91		—		91
Other(a)	20		(13)		(1)		6
Revenue from contracts with customers	1,962		309		(1)		2,270
Leasing revenue	2		—		—		2
Derivative gains	—		87		—		87
Alternative revenue programs	43		—		—		43
Other revenue	11		4		—		15
Total operating revenues	$	2,018	$	400	$	(1)	$	2,417

	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

(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, 2024 and December 31, 2023, accounts receivable balances related to contracts with customers were approximately $1,529 million and $1,441 million, respectively, including $426 million of unbilled revenues as of both March 31, 2024 and December 31, 2023, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

As of March 31, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of March 31, 2024	2025		2026		2027		2028		2029		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	30		10		7		5		5		49		106
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	72		48		26		3		1		1		151
Total operating revenues	$	102	$	58	$	33	$	8	$	6	$	50	$	257

As of March 31, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2024 was $116 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).

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2024

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, 2024, the total net amount of these items is approximately $1,157 million.

CMP Distribution Rate Case

On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. On June 6, 2023, the MPUC approved a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 100 basis points of CMP’s allowed ROE. The Stipulation also provides for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. An increase occurred on January 1, 2023. The next two increases will occur on July 1, 2024, and January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecast by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets.

NYSEG and RG&E Rate Plans

On June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the 2023 JP, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs was November 1, 2023 with a make-whole provision back to May 1, 2023.

The 2023 JP, as approved, includes levelization across the three years of the rate plan for delivery rates for NYSEG's and RG&E’s Electric and Gas businesses with an allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas of 9.20%. The common equity ratio for each business is 48.00%.

The 2023 JP also includes Earnings Sharing Mechanism (ESM) applicable to each business varies based on the earned ROE with 100% of the customers’ portion of earnings above the sharing threshold that would otherwise be deferred for the benefit of customers will be used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition,

50% of NYSEG's and RG&E’s portion will be used to reduce their respective outstanding storm-related regulatory asset deferral balances to the extent such balances exist.

The 2023 JP further enhances distribution vegetation management, maintains gas safety performance measures, establishes threshold performance levels for designated aspects of customer service quality, and includes three Electric Reliability Performance Measures (SAIFI, CAIDI, and Distribution Line Inspection Program Metric for Level II Deficiencies) with a negative revenue adjustment (NRA) beginning with calendar year 2023, if NYSEG fails to meet its annual SAIFI performance metric.

NYSEG and RG&E will continue a RAM to return or collect the remaining Customer Bill Credits established in the prior rate plan and will continue an Electric Revenue Decoupling Mechanism on a total revenue per class basis.

The 2023 JP reflects the recovery of deferred NYSEG Electric and RG&E Electric Major Storm costs of approximately $371 million and $54.6 million, respectively. NYSEG’s remaining super storm regulatory asset of $52.3 million and the non-super storm regulatory asset of $96.6 million from the 2020 Joint Proposal are being amortized over seven years. RG&E’s remaining non-super storm regulatory asset of $19.6 million established prior to the 2020 Joint Proposal is being amortized over two years. All other deferred storm costs at both NYSEG and RG&E are being amortized over 10 years. The 2023 JP gradually increases NYSEG’s and RG&E’s Major Storm rate allowances over the term of the 2023 JP to better align NYSEG’s and RG&E’s actual Major Storm costs with such rate allowances and to support NYSEG’s and RG&E’s credit metrics.

The 2023 JP contains provisions consistent with, supportive of, and in furtherance of the objectives of the Climate Leadership and Community Protection Act (CLCPA) including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan.

New York CLCPA

On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act as part of the CLCPA Phase 2. The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.2 billion, including participation with other upstate utilities on certain projects. On October 17, 2023, NYSEG and RG&E filed a petition requesting approval from the NYPSC to seek authorization from the Federal Energy Regulatory Commission (FERC), to utilize 100 percent construction work in progress (CWIP), in rate base for the local transmission upgrades under the CLCPA Phase 2. On April 18, 2024, the NYPSC approved the petition to allow NYSEG and RG&E to seek FERC approval along with adding other related reporting requirements.

UI, CNG, SCG and BGC Rate Plans

Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills.

UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2024 and 50% of the second half of 2024. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first quarter of 2024.

On September 9, 2022, UI filed a distribution revenue requirement case proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (UI Rate Year 1), September 1, 2024 (UI Rate Year 2), and September 1, 2025 (UI Rate Year 3). On August 25, 2023, PURA issued its Final Decision provided for a one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels. On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because of factual and legal errors related to the treatment of deferred assets, plant in service, and operating expenses. We cannot predict the outcome of this matter.

In 2017, PURA approved new tariffs for 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 approximately 52.00% equity ratio. Any dollars due to customers from the ESM are be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.

In 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021.

On November 3, 2023, CNG and SCG filed a distribution revenue requirement case proposing a one-year rate plan commencing November 1, 2024 through October 31, 2025, for each company respectively. CNG requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $19.8 million, and SCG requested approval of new distribution rates to recover an increase in revenue requirements of approximately $40.6 million. CNG’s and SCG’s rate plans also included several measures to moderate the impact of the proposed rate update for all customers, including, the adoption of a low-income discount rate and seeks to maintain its current revenue decoupling and earning sharing mechanisms. Evidentiary hearings commenced on April 22, 2024. We cannot predict the outcome of this matter.

On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval negotiated between BGC and the AGO in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allowed 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. It provided 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, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. On June 29, 2023 the Governor of Connecticut signed SB7 into law, which included language that Level 1 storm events were exempt from the waiver. We will continue to review the requirements of the program for the next legislative session.

PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation

On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.

On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of approximately $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. Following oral arguments in October 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. This matter has been briefed and oral argument was held December 11, 2023. We cannot predict the outcome of this proceeding.

Regulatory Assets and Liabilities

The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.

Regulatory assets as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Pension and other post-retirement benefits	$	439	$	445
Pension and other post-retirement benefits cost deferrals	57		58
Storm costs	1,052		868
Rate adjustment mechanism	42		24
Revenue decoupling mechanism	101		86
Contracts for differences	33		38
Hardship programs	25		23
Deferred purchased gas	6		16
Environmental remediation costs	244		240
Debt premium	57		58
Unamortized losses on reacquired debt	17		17
Unfunded future income taxes	601		578
Federal tax depreciation normalization adjustment	129		130
Asset retirement obligation	20		19
Deferred meter replacement costs	60		59
COVID-19 cost recovery and late payment surcharge	11		12
Low income arrears forgiveness	49		55
Excess generation service charge	86		52
System Expansion	19		22
Non-bypassable charge	124		103
Hedges losses	13		34
Rate change levelization	83		60
Value of distributed energy resources	44		49
Uncollectible reserve	114		104
New York make-whole provision	84		96
Other	296		283
Total regulatory assets	3,806		3,529
Less: current portion	745		718
Total non-current regulatory assets	$	3,061	$	2,811

“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.

“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability.

“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.

“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.

“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 started 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.

“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.

“Value of distributed energy resources” represents the mechanism to compensate for energy created by distributed energy resources, such as solar.

“Uncollectible reserve” includes the anticipated future rate recovery of costs that are recorded as uncollectible since those will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future uncollectible expense, it does not accrue carrying costs and is not included within rate base. It also includes the variance between actual uncollectible expense and uncollectible expense included in rates that is eligible for future recovery in customer rates. The amortization period will be established in future proceedings.

“New York make-whole provision” represents the regulatory asset to recover revenues that would have been received by NYSEG/RGE had Rate Year 1 rates approved in the 22-E-0317 et al. joint proposal gone into effect on the effective date of May 1, 2023. The balance is being recovered through a separately stated make-whole rate, effective November 1, 2022, over 6-30 months.

“Other” includes various items subject to reconciliation including vegetation management and systems benefit charge.

Regulatory liabilities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Energy efficiency portfolio standard	$	24	$	15
Gas supply charge and deferred natural gas cost	10		8
Pension and other post-retirement benefits cost deferrals	88		89
Carrying costs on deferred income tax bonus depreciation	2		3
Carrying costs on deferred income tax - Mixed Services 263(a)	1		2
2017 Tax Act	1,187		1,190
Accrued removal obligations	1,135		1,139
Positive benefit adjustment	7		9
Deferred property tax	21		21
Net plant reconciliation	23		23
Debt rate reconciliation	16		18
Rate refund – FERC ROE proceeding	40		39
Transmission congestion contracts	24		26
Merger-related rate credits	7		8
Accumulated deferred investment tax credits	20		21
Asset retirement obligation	19		19
Middletown/Norwalk local transmission network service collections	16		16
Non-firm margin sharing credits	39		34
Non by-passable charges	6		9
Transmission revenue reconciliation mechanism	32		57
Other	234		209
Total regulatory liabilities	2,951		2,955
Less: current portion	275		261
Total non-current regulatory liabilities	$	2,676	$	2,694

“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.

“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.

"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.

“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 of regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions.

“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.

“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Avangrid (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Net plant reconciliation” represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Debt rate reconciliation” represents the over/under collection of costs related to debt instruments identified in the rate case. Costs would include interest, commissions and fees versus amounts included in rates.

“Rate refund - FERC ROE proceeding” represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details.

“Transmission congestion contracts” represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During the three months ended March 31, 2024 and 2023, $1 million and $1 million of rate credits were applied against customer bills.

“Asset retirement obligation” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.

“Middletown/Norwalk local transmission network service collections” represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project.

“Non-firm margin sharing credits” represents the portion of interruptible and off-system sales revenue set aside to fund gas expansion projects.

“Other” includes various items subject to reconciliation or being returned through rates, such as service quality metrics.

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Fair Value of Financial Instruments and Fair Value Measurements

3 Months Ended

Mar. 31, 2024

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 their 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 New York Mercantile Exchange (NYMEX). We include the fair value measurements in Level 1 because we use prices quoted in an active market.

•NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3.

•UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs).

We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include modeled volumes on unit-contingent contracts, extrapolated power curves through May 2032 and scheduling assumptions on California power exports to cover Nevada physical power sales. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.

We determine the fair value of our interest rate derivative instruments based on a model whose inputs are observable, such as SOFR, forward interest rate curves or other relevant benchmark. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate contracts).

We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2.

The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value.

Restricted cash was $3 million as of both March 31, 2024 and December 31, 2023, respectively and is included in "Other Assets" on our condensed consolidated balance sheets.

The financial instruments measured at fair value as of March 31, 2024 and December 31, 2023, respectively, consisted of:

As of March 31, 2024	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	30	$	18	$	—	$	—	$	48
Derivative assets
Derivative financial instruments - power	$	23	$	71	$	95	$	(80)	$	109
Derivative financial instruments - gas	—		19		—		(15)		4
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		158		—		—		158
Total	$	23	$	248	$	96	$	(95)	$	272
Derivative liabilities
Derivative financial instruments - power	$	(33)	$	(71)	$	(44)	$	101	$	(47)
Derivative financial instruments - gas	(3)		(22)		—		25		—
Contracts for differences	—		—		(34)		—		(34)
Derivative financial instruments – Other	—		(101)		—		—		(101)
Total	$	(36)	$	(194)	$	(78)	$	126	$	(182)

As of December 31, 2023	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	29	$	16	$	—	$	—	$	45
Derivative assets
Derivative financial instruments - power	$	15	$	42	$	114	$	(69)	$	102
Derivative financial instruments - gas	—		17		—		(12)		5
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		122		—		—		122
Total	$	15	$	181	$	115	$	(81)	$	230
Derivative liabilities
Derivative financial instruments - power	$	(37)	$	(101)	$	(40)	$	135	$	(43)
Derivative financial instruments - gas	(12)		(26)		—		37		(1)
Contracts for differences	—		—		(39)		—		(39)
Derivative financial instruments - Other	—		(92)		—		—		(92)
Total	$	(49)	$	(219)	$	(79)	$	172	$	(175)

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2024 and 2023, respectively, is as follows:

	Three Months Ended March 31,
(Millions)	2024		2023
Fair Value Beginning of Period,	$	36	$	16
Gains recognized in operating revenues	3		—
(Losses) recognized in operating revenues	(19)		(3)
Total losses recognized in operating revenues	(16)		(3)
Gains recognized in OCI	1		11
(Losses) recognized in OCI	(6)		(3)
Total (losses) gains recognized in OCI	(5)		8
Net change recognized in regulatory assets and liabilities	5		4
Purchases	1		9
Settlements	(3)		(20)
Fair Value as of March 31,	$	18	$	14
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	$	(16)	$	(3)

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, 2024
Index	Avg.		Max.		Min.
Ameren ($/MWh)	$	42.68	$	90.60	$	19.58
ComEd ($/MWh)	$	38.64	$	83.36	$	15.39
ERCOT S hub ($/MWh)	$	45.73	$	150.55	$	16.17
Mid C ($/MWh)	$	84.98	$	248.45	$	16.95
AEP-DAYTON hub ($/MWh)	$	42.79	$	94.32	$	20.58

Our Level 3 valuations primarily consist of a Hydro PPA 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 PPA is a long capacity/energy position in the Northwest that provides balancing services with increases in power prices resulting in unrealized gains and decreases in power prices resulting in unrealized losses. The gas swaps are economic hedges of fuel purchases for a combined cycle gas plant, with increases in gas prices resulting in unrealized gains and decreases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.

Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the modeled volumes on unit-contingent agreements. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products.

Transactions are valued in part on the basis of forward prices and estimated volumes. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction.

The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk

using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:

	Range at
Unobservable Input	March 31, 2024
Risk of non-performance	0.52% - 0.54%
Discount rate	3.84% - 4.01%
Forward pricing ($ per KW-month)	$2.00 - $2.61

Fair Value of Debt

As of March 31, 2024 and December 31, 2023, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $10,136 million and $10,266 million as of March 31, 2024 and December 31, 2023, 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. The fair value of debt is considered Level 2 within the fair value hierarchy.

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Derivative Instruments and Hedging

3 Months Ended

Mar. 31, 2024

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, 2024 and December 31, 2023, 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, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	20	$	5	$	19	$	5
Derivative liabilities	(19)		(5)		(42)		(29)
	1		—		(23)		(24)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		—		(23)		(24)
Cash collateral receivable	—		—		6		7
Total derivatives as presented in the balance sheet	$	1	$	—	$	(17)	$	(17)

As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	13	$	3	$	12	$	3
Derivative liabilities	(12)		(3)		(57)		(32)
	1		—		(45)		(29)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		—		(45)		(29)
Cash collateral receivable	—		—		27		7
Total derivatives as presented in the balance sheet	$	1	$	—	$	(18)	$	(22)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,	December 31,
As of	2024	2023
(Millions)
Wholesale electricity purchase contracts (MWh)	6.0	5.6
Natural gas purchase contracts (Dth)	9.3	10.7

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, 2024 and December 31, 2023 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2024 and 2023 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, 2024	Electricity		Natural Gas		2024	Electricity		Natural Gas
Regulatory assets	$	10	$	3	Purchased power, natural gas and fuel used	$	20	$	11
December 31, 2023					2023
Regulatory assets	$	22	$	12	Purchased power, natural gas and fuel used	$	49	$	6

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, 2024, 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 $33 million, a gross derivative liability of $34 million ($33 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, 2023, 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 $38 million, a gross derivative liability of $39 million ($38 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, 2024 and 2023, respectively, were as follows:

	Three Months Ended March 31,
	2024		2023
(Millions)
Derivative liabilities	$	5	$	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, 2024 and 2023, 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)
2024
Interest rate contracts	$	—	Interest expense	$	1	$	125
Commodity contracts	—		Purchased power, natural gas and fuel used	—		724
Total	$	—		$	1
2023
Interest rate contracts	$	—	Interest expense	$	1	$	95
Commodity contracts	—		Purchased power, natural gas and fuel used	—		977
Total	$	—		$	1

(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 $38 million and $39 million as of March 31, 2024 and December 31, 2023, respectively. For the three months ended March 31, 2024 and 2023, we recorded net derivative losses related to discontinued cash flow hedges of $1 million and $1 million, respectively. We will amortize approximately $4 million of discontinued cash flow hedges within the next twelve months.

(b) Renewables activities

Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities.

Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.

Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price

NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms.

The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,	December 31,
As of	2024	2023
(MWh/Dth in millions)
Wholesale electricity purchase contracts	1	1
Wholesale electricity sales contracts	6	6
Natural gas and other fuel purchase contracts	14	21
Financial power contracts	4	4
Basis swaps – purchases	21	24
Basis swaps – sales	1	1

The fair values of derivative contracts associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Wholesale electricity purchase contracts	$	8	$	29
Wholesale electricity sales contracts	46		14
Natural gas and other fuel purchase contracts	3		4
Financial power contracts	10		17
Total	$	67	$	64

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, 2024 and December 31, 2023, the fair value of the interest rate swap was $158 million and $122 million, respectively, as non-current assets. 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, 2024 and December 31, 2023, 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, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	64	$	48	$	43	$	5
Derivative liabilities	(3)		(1)		(53)		(7)
	61		47		(10)		(2)
Designated as hedging instruments
Derivative assets	30		138		14		1
Derivative liabilities	(1)		—		(37)		(35)
	29		138		(23)		(34)
Total derivatives before offset of cash collateral	90		185		(33)		(36)
Cash collateral (payable) receivable	(4)		—		14		8
Total derivatives as presented in the balance sheet	$	86	$	185	$	(19)	$	(28)

As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	53	$	52	$	53	$	1
Derivative liabilities	—		(3)		(73)		(4)
	53		49		(20)		(3)
Designated as hedging instruments
Derivative assets	15		113		7		1
Derivative liabilities	(1)		—		(47)		(37)
	14		113		(40)		(36)
Total derivatives before offset of cash collateral	67		162		(60)		(39)
Cash collateral receivable	—		—		43		13
Total derivatives as presented in the balance sheet	$	67	$	162	$	(17)	$	(26)

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, 2024 and 2023, consisted of:

	Three Months Ended March 31, 2024
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(3)	$	—
Wholesale electricity sales contracts	11		22
Financial power contracts	(2)		2
Financial and natural gas contracts	—		(2)
Total gain included in operating revenues	$	6	$	22	$	2,417
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(17)
Financial power contracts	—		—
Financial and natural gas contracts	—		8
Total loss included in purchased power, natural gas and fuel used	$	—	$	(9)	$	724
Total Gain	$	6	$	13

	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 gain included in purchased power, natural gas and fuel used	$	—	$	(56)	$	977
Total Gain (Loss)	$	5	$	(6)

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, 2024 and 2023, 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)
2024
Interest rate contracts	$	36	Interest Expense	$	—	$	125
Commodity contracts	20		Operating revenues	5		$	2,417
Total	$	56		$	5
2023
Interest rate contracts	$	90	Interest Expense	$	—	$	95
Commodity contracts	23		Operating revenues	66		$	2,466
Total	$	113		$	66

(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 $20 million of losses included in accumulated OCI at March 31, 2024, are expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2024 and 2023.

(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, 2024 and December 31, 2023, the net loss in accumulated OCI related to previously settled interest rate contracts was $27 million and $29 million, respectively. For both the three months ended March 31, 2024 and 2023, we amortized into income $2 million of the loss related to settled interest rate contracts. We will amortize approximately $9 million of the net loss on the interest rate contracts within the next twelve months.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2024 and 2023, 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)
2024
Interest rate contracts	$	—	Interest expense	$	2	$	125
2023
Interest rate contracts	$	—	Interest expense	$	2	$	95

(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, 2024 and 2023 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, 2024			Three Months Ended March 31, 2024
Current Liabilities	$	(29)	Interest Expense	$	11	$	125
Non-current liabilities	$	(71)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	100

	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, 2023			Three Months Ended March 31, 2023
Current Liabilities	$	(26)	Interest Expense	$	7	$	95
Non-current liabilities	$	(63)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	89

(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, 2024, UI would have had to post an aggregate of approximately $27 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 both March 31, 2024 and December 31, 2023, the amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $63 million. 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, 2024 was $13 million, for which we have posted collateral.

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Contingencies and Commitments

3 Months Ended

Mar. 31, 2024

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 of 9.2%. CMP and UI are NETOs with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.

On December 26, 2012, a second related complaint for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On July 31, 2014, a third related complaint was filed for a subsequent rate period requesting the ROE be reduced to 8.84%. On April 29, 2016, a fourth complaint was filed for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%.

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 FERC. We cannot predict the final outcome of the proceedings.

Customer Invoice Dispute

On May 4, 2021, Nike USA, Inc. (Nike), the buyer under a virtual PPA with a subsidiary of Renewables, provided notice that it disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations, most notably during Winter Storm Uri in February of 2021. Nike has requested an adjustment to the invoices that would increase the amount payable by approximately $31 million. Renewables has responded that the invoices have been properly calculated in accordance with the provisions of the PPA, and that Nike is not entitled to any further payments. On June 16, 2023, Nike filed suit against the Company and certain subsidiaries of Renewables alleging breach of contract, and seeking more than $31 million in invoice adjustments, fees, and interest. The Company filed a motion to dismiss the complaint, which the Circuit Court of the State of Oregon for the County of Multnomah denied on October 25, 2023 following oral arguments. The case is currently proceeding with an expected trial beginning on October 14, 2024. We cannot predict the outcome of this matter.

Solar Contractor Dispute

Renewables, through certain subsidiaries, has Engineering, Procurement and Construction (EPC) contracts with Sterling and Wilson Solar Solutions, Inc. (SWSS) for the construction of two Solar farms–Lund Hill in Klickitat, WA (Lund Hill), and Pachwáywit Fields in Gillam County, OR (Montague). Renewables believes that SWSS is in default of a number of its obligations under the respective EPC contracts, including construction flaws and failing to pay certain subcontractors. As a result, Renewables drew on Letters of Credit for both Montague and Lund Hill. In response, SWSS filed liens on both projects totaling approximately $105 million claiming that this amount is due under EPC contracts. Renewables has bonded over the liens on both properties. On October 27, 2023, SWSS commenced foreclosure actions in Oregon on the lien at Montague, and added claims for breach of contract and quantum meruit, seeking up to $111.8 million. SWSS has also commenced foreclosure procedures in Washington State against Lund Hill seeking to close on its lien of $59.9 million. On February 26, 2024, SWSS filed a lawsuit against Lund Hill and Renewables in New York State court alleging breach of contract, quantum meruit and violation of the Prompt Payment Act, all based on the same facts as the previously filed foreclosure matter seeking $59.9 million in damages. We cannot predict the outcome of these disputes.

Guarantee Commitments to Third Parties

As of March 31, 2024, we had approximately $918 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 and an indemnification of Vineyard Wind tax equity investors as described in Note 19, which are 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, 2024, neither we nor our subsidiaries have any liabilities recorded for these instruments.

NECEC Commitments

On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately $11 million was paid through the three months ended March 31, 2024.

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Environmental Liabilities

3 Months Ended

Mar. 31, 2024

Environmental Remediation Obligations [Abstract]

Environmental Liabilities

Environmental Liabilities

Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies.

Waste sites

The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; two sites are included in Maine’s Uncontrolled Sites Program; and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, five of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and several for certain sites.

We have recorded an estimated liability of $6 million related to six of the twenty-four sites. We have paid remediation costs related to the remaining eighteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $10 million related to another ten sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of March 31, 2024, our estimate for costs to remediate these sites ranges from $15 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs.

Manufactured Gas Plants

We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry, thirty-nine sites are included in the New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order of Consent; two sites with individual NYSDEC Orders of Consent; two sites under a Brownfield Cleanup Program and two sites are included in Maine Department of Environmental Protection programs (none in the Voluntary Response Action Program, Brownfield Cleanup Program and Uncontrolled Sites Program). The remaining sites are not included in a formal program. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.

As of March 31, 2024, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $117 million to $213 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 of 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, 2024, 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, 2024 and December 31, 2023, 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, 2024 and December 31, 2023, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $245 million and $250 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 2058.

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, 2024, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $8 million and $5 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 August 4, 2016, DEEP issued a partial consent order (the consent order), that requires UI to investigate and remediate certain environmental conditions within the perimeter of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000. 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. UI must comply with the terms of the consent order, but may seek to recover costs above $30 million in consultation with the state. UI continues its activities to investigate and remediate the environmental conditions at the site. In 2023 and 2024, DEEP sent UI a series of letters requesting details on remediation plans and security, which UI has responded to.

On January 25, 2024, DEEP issued a notice of declaratory ruling to determine the “high occupancy standard” necessary “to abate on-site pollution and impacts for industrial/commercial use of the Site…inside the buildings” as referenced in section (B)(1)(e)(4) of the Partial Consent Order. On February 26, 2024, UI was granted intervenor status and it subsequently submitted its written comments objecting to the proceedings on March 11, 2024. On January 29, 2024, DEEP served UI with a Summons and Complaint seeking injunctive relief and enforcement of the consent order from the Connecticut Superior Court. On April 9, 2024, the application to transfer the proceedings to the Complex Litigation Docket of the Connecticut Superior Court was granted. The court also granted UI’s Motion to Stay the proceeding until the April 30, 2024 court conference.

As of both March 31, 2024 and December 31, 2023, the amount reserved related to English Station was $19 million. Since its inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of these proceedings.

Eagle Takings Inquiry

In April 2023, Avangrid Renewables received a letter from the U.S. Fish and Wildlife Service regarding certain bald and golden eagle fatalities that allegedly occurred at certain Avangrid Renewables facilities that are not covered by an eagle take permit. Avangrid Renewables has responded to the U.S. Fish and Wildlife Service providing information about the relevant eagle taking permit applications and relevant mitigation activity at each facility. On February 12, 2024, the U.S. Fish and Wildlife Service published a new Eagle Rule, superseding the 2016 Eagle Rule. Avangrid Renewables subsequently communicated to the U.S. Fish and Wildlife Service that it would be applying for the General Permit option under the new Eagle Rule and is waiting for the permit application form to become available in the preferred electronic permit platform, ePermits. The U.S. Fish and Wildlife Service acknowledged receipt of this communication. We cannot predict the outcome of these applications.

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Post-retirement and Similar Obligations

3 Months Ended

Mar. 31, 2024

Retirement Benefits [Abstract]

Post-retirement and Similar Obligations

Post-retirement and Similar Obligations

We made $1 million of pension contributions for the three months ended March 31, 2024. We expect to make additional contributions of $27 million for the remainder of 2024.

The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of:

	Three Months Ended March 31,
	2024		2023
(Millions)
Service cost	$	2	$	2
Interest cost	28		30
Expected return on plan assets	(40)		(36)
Amortization of:
Prior service costs	—		—
Actuarial loss	7		1
Net Periodic Benefit Cost	$	(3)	$	(3)

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of: 

	Three Months Ended March 31,
	2024		2023
(Millions)
Service cost	$	—	$	—
Interest cost	3		3
Expected return on plan assets	(1)		(1)
Amortization of:
Prior service costs	—		—
Actuarial loss	(1)		(3)
Net Periodic Benefit Cost (Credit)	$	1	$	(1)

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Equity

3 Months Ended

Mar. 31, 2024

Equity [Abstract]

Equity

Equity

As of both March 31, 2024 and December 31, 2023, we had 103,889 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2024 and 2023, we issued 135,345 and 12,332 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, 2024, 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, 2024.

Accumulated Other Comprehensive Income (Loss) 

Accumulated Other Comprehensive Loss for the three months ended March 31, 2024 and 2023, 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,
	2023		2024		2024		2022		2023		2023
(Millions)
Net loss on pension plans	(21)		—		(21)		(20)		—		(20)
Unrealized (loss) gain from equity method investment, net of income tax expense of $0 for 2024 and $0 for 2023 (a)	18		—		18		13		(1)		12
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $15 for 2024 and $(1) for 2023	(178)		39		(139)		(195)		(2)		(197)
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $2 for 2024 and $18 for 2023 (b)	156		7		163		22		52		74
Loss (gain) on derivatives qualifying as cash flow hedges	(22)		46		24		(173)		50		(123)
Accumulated Other Comprehensive Income (Loss)	$	(25)	$	46	$	21	$	(180)	$	49	$	(131)

(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.

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Earnings Per Share

3 Months Ended

Mar. 31, 2024

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, 2024 and 2023, 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, 2024 and 2023, respectively, consisted of:

	Three Months Ended March 31,
	2024		2023
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to Avangrid	$	351	$	245
Denominator:
Weighted average number of shares outstanding - basic	386,916,234		386,744,996
Weighted average number of shares outstanding - diluted	387,239,544		387,077,213
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic	$	0.91	$	0.63
Earnings Per Common Share, Diluted	$	0.91	$	0.63

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Segment Information

3 Months Ended

Mar. 31, 2024

Segment Reporting [Abstract]

Segment Information

Segment Information

Our segment reporting structure uses our management reporting structure as its foundation to reflect how Avangrid manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments:

•Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of

customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment.

•Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities.

The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments and accelerated depreciation from the repowering of wind farms.

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, 2024, consisted of:

Three Months Ended March 31, 2024	Networks		Renewables		Other (a)		Avangrid Consolidated
(Millions)
Revenue - external	$	2,017	$	400	$	—	$	2,417
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	178		118		2		298
Operating income (loss)	353		60		(6)		407
Earnings from equity method investments	4		2		—		6
Interest expense, net of capitalization	89		4		32		125
Income tax expense (benefit)	57		(6)		(31)		20
Adjusted net income (loss)	268		84		(11)		341
Capital expenditures	691		179		2		872
As of March 31, 2024
Property, plant and equipment	22,068		11,243		12		33,323
Equity method investments	188		648		—		836
Total assets	$	31,238	$	14,114	$	(290)	$	45,062

(a) Includes Corporate and intersegment eliminations.

Segment information for the three months ended March 31, 2023 and as of December 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 (loss)	195		51		1		248
Capital expenditures	609		227		—		836
As of December 31, 2023
Property, plant and equipment	21,692		11,153		12		32,857
Equity method investments	186		532		—		718
Total assets	$	30,413	$	14,538	$	(962)	$	43,989

(a) Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the three months ended March 31, 2024 and 2023, respectively, is as follows:

	Three Months Ended March 31,
	2024		2023
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	341	$	248
Adjustments:
Mark-to-market adjustments - Renewables (1)	17		(4)
Accelerated depreciation from repowering (2)	(3)		—
Income tax impact of adjustments	(4)		1
Net Income Attributable to Avangrid, Inc.	$	351	$	245

(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(2)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

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Related Party Transactions

3 Months Ended

Mar. 31, 2024

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, 2024 and 2023, respectively, consisted of:

Three Months Ended March 31,	2024				2023
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(12)	$	—	$	(11)
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(16)	$	—	$	(4)
Vineyard Wind	$	3	$	—	$	2	$	—

Related party balances as of March 31, 2024 and December 31, 2023, respectively, consisted of:

As of	March 31, 2024				December 31, 2023
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	1	$	(12)	$	1	$	—
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	4	$	—
Iberdrola Financiación, S.A.	$	—	$	(1,304)	$	—	$	(799)
Vineyard Wind	$	4	$	(8)	$	6	$	(8)
Iberdrola Solutions	$	—	$	(6)	$	—	$	(6)
Other	$	4	$	(1)	$	4	$	—

Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of Avangrid, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 15 for a discussion of the Iberdrola Intragroup Green Loan.

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, 2024 and December 31, 2023, was $0.

On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and a

maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of March 31, 2024 and December 31, 2023, there was $500 million and $0 outstanding amount under this credit facility, respectively.

We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balances of $6 million and as of both March 31, 2024 and December 31, 2023.

See Note 19 - Equity Method Investments for more information on transactions with our equity method investees.

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Other Financial Statement Items

3 Months Ended

Mar. 31, 2024

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, 2024 and December 31, 2023 consisted of:

As of	March 31, 2024		December 31, 2023
(Millions)
Trade receivables and unbilled revenues	$	1,809	$	1,749
Allowance for credit losses	(169)		(161)
Accounts receivable and unbilled revenues, net	$	1,640	$	1,588

The change in the allowance for credit losses for the three months ended March 31, 2024 and 2023 consisted of:

	Three Months Ended March 31,
(Millions)	2024		2023
As of Beginning of Period,	$	161	$	155
Current period provision	46		17
Write-off as uncollectible	(38)		(24)
As of March 31,	$	169	$	148

The Deferred Payment Arrangements (DPA) receivable balance was $116 million and $110 million as of March 31, 2024 and December 31, 2023, respectively. The allowance for credit losses for DPAs at March 31, 2024 and December 31, 2023 was $46 million and $44 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2024 and 2023, was $2 million and $(2) million, respectively.

Prepayments and other current assets

Included in prepayments and other current assets are $164 million and $142 million of prepaid other taxes as of March 31, 2024 and December 31, 2023, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of March 31, 2024 and December 31, 2023, respectively, were as follows:

	March 31,		December 31,
As of	2024		2023
(Millions)
Property, plant and equipment
Accumulated depreciation	$	12,732	$	12,479
Intangible assets
Accumulated amortization	$	357	$	351

As of March 31, 2024 and 2023, accrued liabilities for property, plant and equipment additions were $553 million and $239 million, respectively.

Debt

Commercial Paper

As of March 31, 2024 and December 31, 2023, there was $1,864 million and $1,332 million of commercial paper outstanding, respectively. As of March 31, 2024 and December 31, 2023, the weighted-average interest rate on commercial paper was 5.55% and 5.65%, respectively.

Intragroup Green Loan

On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan).

Other current liabilities

Included in other current liabilities are $224 million and $236 million of advances received as of March 31, 2024 and December 31, 2023, respectively.

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Income Tax Expense

3 Months Ended

Mar. 31, 2024

Income Tax Disclosure [Abstract]

Income Tax Expense

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2024 was 5.8% which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, the effect of the excess deferred tax amortization resulting from the Tax Act, the equity component of allowance for funds used during construction and other property related flow through items, partially offset by tax equity financing impacts and state taxes.

The 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.

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Stock-Based Compensation Expense

3 Months Ended

Mar. 31, 2024

Share-Based Payment Arrangement [Abstract]

Stock-Based Compensation Expense

Stock-Based Compensation Expense

The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares).

Performance Stock Units

In March 2023, a total number of 677,752 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and are payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The remaining unvested PSUs were forfeited. The second installment was paid in March 2024, and 126,311 shares of common stock were issued to settle this installment payment.

During 2023 and 2024, 1,067,500 and 15,296 PSUs, respectively, 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 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 second and final installment of this RSU grant was settled in January 2024, net of applicable taxes, by issuing 9,034 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 four 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 2024, $0.1 million was paid to settle the fourth and final 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, 2025 and 2026 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In February 2024, $1.0 million was paid to settle the first installment under this plan.

As of March 31, 2024 and December 31, 2023, the total liability was $1 million and $2 million, respectively, which is included in other current and non-current liabilities.

The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2024 and 2023, was $3 million and $4 million, respectively.

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Variable Interest Entities

3 Months Ended

Mar. 31, 2024

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

Variable Interest Entities

We participate in certain partnership arrangements that qualify as VIEs. These arrangements 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.

The assets and liabilities of the VIEs totaled approximately $2,740 million and $196 million, respectively, at March 31, 2024. As of December 31, 2023, the assets and liabilities of VIEs totaled approximately $2,741 million and $174 million, respectively. At March 31, 2024 and December 31, 2023, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.

Wind and solar power generation are 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 and solar farms. Under these structures, we contribute certain wind / solar assets, relating both to existing wind farms and wind farms / solar facilities 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 targeted 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, 2024, 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.

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Equity Method Investments

3 Months Ended

Mar. 31, 2024

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 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 in 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.

On October 24, 2023, Vineyard Wind 1 closed on a TEF agreement, pursuant to which Vineyard Wind 1 is expected to receive approximately $1.2 billion from tax equity investors in installments based on the number of turbines reaching or about to reach mechanical completion each month until the entire project reaches commercial operation date. Vineyard Wind 1 received the initial funding of $85 million from tax equity investors in 2023. The remaining $1.1 billion is expected to be received in 2024. In conjunction with the equity installments received since the closing of the TEF agreement, we have issued an indemnification of our joint share of the investor contributions. As of both March 31, 2024 and December 31, 2023, our total indemnified amount was $43 million.

Vineyard Wind 1 is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. During 2024, Renewables made a capital contribution of $116 million to Vineyard Wind 1. As of March 31, 2024 and December 31, 2023, the carrying amount of Renewables' investments in Vineyard Wind LLC and Vineyard Wind 1 Pledgor LLC was $419 million and $297 million, respectively.

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Subsequent Event

3 Months Ended

Mar. 31, 2024

Subsequent Events [Abstract]

Subsequent Event

Subsequent Event

On April 11, 2024, 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 1, 2024 to shareholders of record at the close of business on June 3, 2024.

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Significant Accounting Policies and New Accounting Pronouncements (Policies)

3 Months Ended

Mar. 31, 2024

Accounting Policies [Abstract]

Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued but Not Yet Adopted

Adoption of New Accounting Pronouncements

(a) Improvements to Reportable Segment Disclosures

In November 2023, the FASB issued guidance requiring incremental disclosures for reportable segments. These incremental requirements include disclosing significant expenses that are regularly provided to the chief operating decision maker (CODM) and other segment items, including a description of its composition. The other segment items category is the difference between segment revenue less the significant segment expenses, and each reported measure of segment profit or loss. The guidance clarifies that if the CODM reviews multiple measures of a segments total profit or loss, that the entity may under certain conditions report multiple measures in the segment footnote; however, if only one measure is reported, it should be the one that

best conforms with U.S. GAAP. The guidance requires disclosure of the title and position of the individual or the name of the group identified as the CODM. Finally, all annual disclosures are required in interim reporting starting in the first quarter of 2025. As the guidance impacts disclosures only, it will not have an impact to the consolidated financial results. These changes in disclosures will initially be reflected in the annual financial statement footnotes for the year ended December 31, 2024.

Accounting Pronouncements Issued but Not Yet Adopted

The following are new significant accounting pronouncements not yet adopted, including those issued since December 31, 2023, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Improvements to Income Tax Disclosures

In December 2023, the FASB issued guidance to enhance income tax disclosures. The standard is required to be adopted by public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. The two primary enhancements relate to disaggregation of the annual effective tax rate reconciliation and income taxes paid disclosures. For the rate reconciliation, it requires additional disaggregation of information in a tabular format using both percentages and amounts broken out into specific categories (e.g., state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, and changes in unrecognized tax benefits). For income taxes paid, it requires disaggregation by jurisdiction (e.g., federal, state and foreign). We do not expect the new guidance to have a material impact on our consolidated results of operations, financial position and cash flows.

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 the FASB issued ASC Topic 606, Revenue from Contracts with Customers (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 significant financing elements in any of the arrangements. 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.

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 Assets and Liabilities

We have contract assets for costs from development success fees and construction delays, which were paid during solar farm assets development period. The contract assets are amortized ratably into expense over the 16 - 21 year life of the respective power purchase agreements (PPAs). Contract assets totaled $19 million and $9 million at  March 31, 2024 and December 31, 2023, respectively, and are presented in "Other non-current assets" on our condensed consolidated balance sheets.

We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $9 million and $18 million at March 31, 2024 and December 31, 2023, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $9 million and $17 million as revenue related to contract liabilities for the three months ended March 31, 2024 and 2023, respectively.

We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

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Revenue (Tables)

3 Months Ended

Mar. 31, 2024

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, 2024 and 2023 are as follows:

	Three Months Ended March 31, 2024
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,350	$	—	$	—	$	1,350
Regulated operations – natural gas	592		—		—		592
Nonregulated operations – wind	—		224		—		224
Nonregulated operations – solar	—		7		—		7
Nonregulated operations – thermal	—		91		—		91
Other(a)	20		(13)		(1)		6
Revenue from contracts with customers	1,962		309		(1)		2,270
Leasing revenue	2		—		—		2
Derivative gains	—		87		—		87
Alternative revenue programs	43		—		—		43
Other revenue	11		4		—		15
Total operating revenues	$	2,018	$	400	$	(1)	$	2,417

	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

(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, 2024, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of March 31, 2024	2025		2026		2027		2028		2029		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	30		10		7		5		5		49		106
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	72		48		26		3		1		1		151
Total operating revenues	$	102	$	58	$	33	$	8	$	6	$	50	$	257

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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2024

Regulated Operations [Abstract]

Schedule of Current and Non-Current Regulatory Assets

Regulatory assets as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Pension and other post-retirement benefits	$	439	$	445
Pension and other post-retirement benefits cost deferrals	57		58
Storm costs	1,052		868
Rate adjustment mechanism	42		24
Revenue decoupling mechanism	101		86
Contracts for differences	33		38
Hardship programs	25		23
Deferred purchased gas	6		16
Environmental remediation costs	244		240
Debt premium	57		58
Unamortized losses on reacquired debt	17		17
Unfunded future income taxes	601		578
Federal tax depreciation normalization adjustment	129		130
Asset retirement obligation	20		19
Deferred meter replacement costs	60		59
COVID-19 cost recovery and late payment surcharge	11		12
Low income arrears forgiveness	49		55
Excess generation service charge	86		52
System Expansion	19		22
Non-bypassable charge	124		103
Hedges losses	13		34
Rate change levelization	83		60
Value of distributed energy resources	44		49
Uncollectible reserve	114		104
New York make-whole provision	84		96
Other	296		283
Total regulatory assets	3,806		3,529
Less: current portion	745		718
Total non-current regulatory assets	$	3,061	$	2,811

Schedule of Current and Non-Current Regulatory Liabilities

Regulatory liabilities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Energy efficiency portfolio standard	$	24	$	15
Gas supply charge and deferred natural gas cost	10		8
Pension and other post-retirement benefits cost deferrals	88		89
Carrying costs on deferred income tax bonus depreciation	2		3
Carrying costs on deferred income tax - Mixed Services 263(a)	1		2
2017 Tax Act	1,187		1,190
Accrued removal obligations	1,135		1,139
Positive benefit adjustment	7		9
Deferred property tax	21		21
Net plant reconciliation	23		23
Debt rate reconciliation	16		18
Rate refund – FERC ROE proceeding	40		39
Transmission congestion contracts	24		26
Merger-related rate credits	7		8
Accumulated deferred investment tax credits	20		21
Asset retirement obligation	19		19
Middletown/Norwalk local transmission network service collections	16		16
Non-firm margin sharing credits	39		34
Non by-passable charges	6		9
Transmission revenue reconciliation mechanism	32		57
Other	234		209
Total regulatory liabilities	2,951		2,955
Less: current portion	275		261
Total non-current regulatory liabilities	$	2,676	$	2,694

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Fair Value of Financial Instruments and Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2024

Fair Value Disclosures [Abstract]

Schedule of Fair Value Measurements

The financial instruments measured at fair value as of March 31, 2024 and December 31, 2023, respectively, consisted of:

As of March 31, 2024	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	30	$	18	$	—	$	—	$	48
Derivative assets
Derivative financial instruments - power	$	23	$	71	$	95	$	(80)	$	109
Derivative financial instruments - gas	—		19		—		(15)		4
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		158		—		—		158
Total	$	23	$	248	$	96	$	(95)	$	272
Derivative liabilities
Derivative financial instruments - power	$	(33)	$	(71)	$	(44)	$	101	$	(47)
Derivative financial instruments - gas	(3)		(22)		—		25		—
Contracts for differences	—		—		(34)		—		(34)
Derivative financial instruments – Other	—		(101)		—		—		(101)
Total	$	(36)	$	(194)	$	(78)	$	126	$	(182)

As of December 31, 2023	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	29	$	16	$	—	$	—	$	45
Derivative assets
Derivative financial instruments - power	$	15	$	42	$	114	$	(69)	$	102
Derivative financial instruments - gas	—		17		—		(12)		5
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		122		—		—		122
Total	$	15	$	181	$	115	$	(81)	$	230
Derivative liabilities
Derivative financial instruments - power	$	(37)	$	(101)	$	(40)	$	135	$	(43)
Derivative financial instruments - gas	(12)		(26)		—		37		(1)
Contracts for differences	—		—		(39)		—		(39)
Derivative financial instruments - Other	—		(92)		—		—		(92)
Total	$	(49)	$	(219)	$	(79)	$	172	$	(175)

Summary of 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, 2024 and 2023, respectively, is as follows:

	Three Months Ended March 31,
(Millions)	2024		2023
Fair Value Beginning of Period,	$	36	$	16
Gains recognized in operating revenues	3		—
(Losses) recognized in operating revenues	(19)		(3)
Total losses recognized in operating revenues	(16)		(3)
Gains recognized in OCI	1		11
(Losses) recognized in OCI	(6)		(3)
Total (losses) gains recognized in OCI	(5)		8
Net change recognized in regulatory assets and liabilities	5		4
Purchases	1		9
Settlements	(3)		(20)
Fair Value as of March 31,	$	18	$	14
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	$	(16)	$	(3)

Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:

	Range at
Unobservable Input	March 31, 2024
Risk of non-performance	0.52% - 0.54%
Discount rate	3.84% - 4.01%
Forward pricing ($ per KW-month)	$2.00 - $2.61

Summary of 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, 2024
Index	Avg.		Max.		Min.
Ameren ($/MWh)	$	42.68	$	90.60	$	19.58
ComEd ($/MWh)	$	38.64	$	83.36	$	15.39
ERCOT S hub ($/MWh)	$	45.73	$	150.55	$	16.17
Mid C ($/MWh)	$	84.98	$	248.45	$	16.95
AEP-DAYTON hub ($/MWh)	$	42.79	$	94.32	$	20.58

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Derivative Instruments and Hedging (Tables)

3 Months Ended

Mar. 31, 2024

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, 2024 and December 31, 2023, 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, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	20	$	5	$	19	$	5
Derivative liabilities	(19)		(5)		(42)		(29)
	1		—		(23)		(24)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		—		(23)		(24)
Cash collateral receivable	—		—		6		7
Total derivatives as presented in the balance sheet	$	1	$	—	$	(17)	$	(17)

As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	13	$	3	$	12	$	3
Derivative liabilities	(12)		(3)		(57)		(32)
	1		—		(45)		(29)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		—		(45)		(29)
Cash collateral receivable	—		—		27		7
Total derivatives as presented in the balance sheet	$	1	$	—	$	(18)	$	(22)

The tables below present Renewables' derivative positions as of March 31, 2024 and December 31, 2023, 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, 2024	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	64	$	48	$	43	$	5
Derivative liabilities	(3)		(1)		(53)		(7)
	61		47		(10)		(2)
Designated as hedging instruments
Derivative assets	30		138		14		1
Derivative liabilities	(1)		—		(37)		(35)
	29		138		(23)		(34)
Total derivatives before offset of cash collateral	90		185		(33)		(36)
Cash collateral (payable) receivable	(4)		—		14		8
Total derivatives as presented in the balance sheet	$	86	$	185	$	(19)	$	(28)

As of December 31, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	53	$	52	$	53	$	1
Derivative liabilities	—		(3)		(73)		(4)
	53		49		(20)		(3)
Designated as hedging instruments
Derivative assets	15		113		7		1
Derivative liabilities	(1)		—		(47)		(37)
	14		113		(40)		(36)
Total derivatives before offset of cash collateral	67		162		(60)		(39)
Cash collateral receivable	—		—		43		13
Total derivatives as presented in the balance sheet	$	67	$	162	$	(17)	$	(26)

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, 2024 and December 31, 2023, respectively, consisted of:

	March 31,	December 31,
As of	2024	2023
(Millions)
Wholesale electricity purchase contracts (MWh)	6.0	5.6
Natural gas purchase contracts (Dth)	9.3	10.7

The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,	December 31,
As of	2024	2023
(MWh/Dth in millions)
Wholesale electricity purchase contracts	1	1
Wholesale electricity sales contracts	6	6
Natural gas and other fuel purchase contracts	14	21
Financial power contracts	4	4
Basis swaps – purchases	21	24
Basis swaps – sales	1	1

Summary of Unrealized Gains and Losses from Fair Value Adjustments

The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2024 and December 31, 2023 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2024 and 2023 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, 2024	Electricity		Natural Gas		2024	Electricity		Natural Gas
Regulatory assets	$	10	$	3	Purchased power, natural gas and fuel used	$	20	$	11
December 31, 2023					2023
Regulatory assets	$	22	$	12	Purchased power, natural gas and fuel used	$	49	$	6

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, 2024 and 2023, respectively, were as follows:

	Three Months Ended March 31,
	2024		2023
(Millions)
Derivative liabilities	$	5	$	4

Derivative Instruments, Gain (Loss)

The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2024 and 2023, 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)
2024
Interest rate contracts	$	—	Interest expense	$	1	$	125
Commodity contracts	—		Purchased power, natural gas and fuel used	—		724
Total	$	—		$	1
2023
Interest rate contracts	$	—	Interest expense	$	1	$	95
Commodity contracts	—		Purchased power, natural gas and fuel used	—		977
Total	$	—		$	1

(a) Changes in accumulated OCI are reported on a pre-tax basis.

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2024 and 2023, 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)
2024
Interest rate contracts	$	36	Interest Expense	$	—	$	125
Commodity contracts	20		Operating revenues	5		$	2,417
Total	$	56		$	5
2023
Interest rate contracts	$	90	Interest Expense	$	—	$	95
Commodity contracts	23		Operating revenues	66		$	2,466
Total	$	113		$	66

(a) Changes in OCI are reported on a pre-tax basis.

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2024 and 2023, 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)
2024
Interest rate contracts	$	—	Interest expense	$	2	$	125
2023
Interest rate contracts	$	—	Interest expense	$	2	$	95

(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, 2024 and 2023 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, 2024			Three Months Ended March 31, 2024
Current Liabilities	$	(29)	Interest Expense	$	11	$	125
Non-current liabilities	$	(71)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	100

	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, 2023			Three Months Ended March 31, 2023
Current Liabilities	$	(26)	Interest Expense	$	7	$	95
Non-current liabilities	$	(63)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	89

Schedule of Fair Value, Net Derivative Contracts

The fair values of derivative contracts associated with Renewables' activities as of March 31, 2024 and December 31, 2023, respectively, consisted of:

	March 31,		December 31,
As of	2024		2023
(Millions)
Wholesale electricity purchase contracts	$	8	$	29
Wholesale electricity sales contracts	46		14
Natural gas and other fuel purchase contracts	3		4
Financial power contracts	10		17
Total	$	67	$	64

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, 2024 and 2023, consisted of:

	Three Months Ended March 31, 2024
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(3)	$	—
Wholesale electricity sales contracts	11		22
Financial power contracts	(2)		2
Financial and natural gas contracts	—		(2)
Total gain included in operating revenues	$	6	$	22	$	2,417
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(17)
Financial power contracts	—		—
Financial and natural gas contracts	—		8
Total loss included in purchased power, natural gas and fuel used	$	—	$	(9)	$	724
Total Gain	$	6	$	13

	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 gain included in purchased power, natural gas and fuel used	$	—	$	(56)	$	977
Total Gain (Loss)	$	5	$	(6)

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Post-retirement and Similar Obligations (Tables)

3 Months Ended

Mar. 31, 2024

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, 2024 and 2023, respectively, consisted of:

	Three Months Ended March 31,
	2024		2023
(Millions)
Service cost	$	2	$	2
Interest cost	28		30
Expected return on plan assets	(40)		(36)
Amortization of:
Prior service costs	—		—
Actuarial loss	7		1
Net Periodic Benefit Cost	$	(3)	$	(3)

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2024 and 2023, respectively, consisted of: 

	Three Months Ended March 31,
	2024		2023
(Millions)
Service cost	$	—	$	—
Interest cost	3		3
Expected return on plan assets	(1)		(1)
Amortization of:
Prior service costs	—		—
Actuarial loss	(1)		(3)
Net Periodic Benefit Cost (Credit)	$	1	$	(1)

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Equity (Tables)

3 Months Ended

Mar. 31, 2024

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Income (Loss)

Accumulated Other Comprehensive Loss for the three months ended March 31, 2024 and 2023, 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,
	2023		2024		2024		2022		2023		2023
(Millions)
Net loss on pension plans	(21)		—		(21)		(20)		—		(20)
Unrealized (loss) gain from equity method investment, net of income tax expense of $0 for 2024 and $0 for 2023 (a)	18		—		18		13		(1)		12
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $15 for 2024 and $(1) for 2023	(178)		39		(139)		(195)		(2)		(197)
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $2 for 2024 and $18 for 2023 (b)	156		7		163		22		52		74
Loss (gain) on derivatives qualifying as cash flow hedges	(22)		46		24		(173)		50		(123)
Accumulated Other Comprehensive Income (Loss)	$	(25)	$	46	$	21	$	(180)	$	49	$	(131)

(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.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2024

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, 2024 and 2023, respectively, consisted of:

	Three Months Ended March 31,
	2024		2023
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to Avangrid	$	351	$	245
Denominator:
Weighted average number of shares outstanding - basic	386,916,234		386,744,996
Weighted average number of shares outstanding - diluted	387,239,544		387,077,213
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic	$	0.91	$	0.63
Earnings Per Common Share, Diluted	$	0.91	$	0.63

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2024

Segment Reporting [Abstract]

Schedule of Segment Information

Segment information as of and for the three months ended March 31, 2024, consisted of:

Three Months Ended March 31, 2024	Networks		Renewables		Other (a)		Avangrid Consolidated
(Millions)
Revenue - external	$	2,017	$	400	$	—	$	2,417
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	178		118		2		298
Operating income (loss)	353		60		(6)		407
Earnings from equity method investments	4		2		—		6
Interest expense, net of capitalization	89		4		32		125
Income tax expense (benefit)	57		(6)		(31)		20
Adjusted net income (loss)	268		84		(11)		341
Capital expenditures	691		179		2		872
As of March 31, 2024
Property, plant and equipment	22,068		11,243		12		33,323
Equity method investments	188		648		—		836
Total assets	$	31,238	$	14,114	$	(290)	$	45,062

(a) Includes Corporate and intersegment eliminations.

Segment information for the three months ended March 31, 2023 and as of December 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 (loss)	195		51		1		248
Capital expenditures	609		227		—		836
As of December 31, 2023
Property, plant and equipment	21,692		11,153		12		32,857
Equity method investments	186		532		—		718
Total assets	$	30,413	$	14,538	$	(962)	$	43,989

(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, 2024 and 2023, respectively, is as follows:

	Three Months Ended March 31,
	2024		2023
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	341	$	248
Adjustments:
Mark-to-market adjustments - Renewables (1)	17		(4)
Accelerated depreciation from repowering (2)	(3)		—
Income tax impact of adjustments	(4)		1
Net Income Attributable to Avangrid, Inc.	$	351	$	245

(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(2)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2024

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Related party transactions for the three months ended March 31, 2024 and 2023, respectively, consisted of:

Three Months Ended March 31,	2024				2023
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(12)	$	—	$	(11)
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(16)	$	—	$	(4)
Vineyard Wind	$	3	$	—	$	2	$	—

Related party balances as of March 31, 2024 and December 31, 2023, respectively, consisted of:

As of	March 31, 2024				December 31, 2023
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	1	$	(12)	$	1	$	—
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	4	$	—
Iberdrola Financiación, S.A.	$	—	$	(1,304)	$	—	$	(799)
Vineyard Wind	$	4	$	(8)	$	6	$	(8)
Iberdrola Solutions	$	—	$	(6)	$	—	$	(6)
Other	$	4	$	(1)	$	4	$	—

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Other Financial Statement Items (Tables)

3 Months Ended

Mar. 31, 2024

Balance Sheet Related Disclosures [Abstract]

Schedule of Accounts, Notes, Loans and Financing Receivable

Accounts receivable and unbilled revenues, net as of March 31, 2024 and December 31, 2023 consisted of:

As of	March 31, 2024		December 31, 2023
(Millions)
Trade receivables and unbilled revenues	$	1,809	$	1,749
Allowance for credit losses	(169)		(161)
Accounts receivable and unbilled revenues, net	$	1,640	$	1,588

The change in the allowance for credit losses for the three months ended March 31, 2024 and 2023 consisted of:

	Three Months Ended March 31,
(Millions)	2024		2023
As of Beginning of Period,	$	161	$	155
Current period provision	46		17
Write-off as uncollectible	(38)		(24)
As of March 31,	$	169	$	148

Schedule of Accumulated Depreciation and Amortization

The accumulated depreciation and amortization as of March 31, 2024 and December 31, 2023, respectively, were as follows:

	March 31,		December 31,
As of	2024		2023
(Millions)
Property, plant and equipment
Accumulated depreciation	$	12,732	$	12,479
Intangible assets
Accumulated amortization	$	357	$	351

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Background and Nature Of Operations (Details) - $ / shares	Mar. 31, 2024	Mar. 06, 2024
Noncontrolling Interest [Line Items]
Non-binding proposal to acquire common stock, price (in dollars per share)		$ 34.25
Avangrid | Iberdrola, S.A.
Noncontrolling Interest [Line Items]
Parent company, ownership percentage	81.60%
Avangrid | Various Shareholders
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners	14.70%

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Revenue - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Disaggregation of Revenue [Line Items]
Contract assets	$ 19		$ 9
TCC contract liabilities	9		18
Revenue recognized	9	$ 17
Accounts receivable related to contracts with customers	1,529		1,441
Unbilled contracts receivable	426		$ 426
Revenue, remaining performance obligation, amount	$ 257
Minimum
Disaggregation of Revenue [Line Items]
Contract assets amortization term	16 years
Minimum | Transmission congestion contracts
Disaggregation of Revenue [Line Items]
Revenue auction period	6 months
Maximum
Disaggregation of Revenue [Line Items]
Contract assets amortization term	21 years
Maximum | Transmission congestion contracts
Disaggregation of Revenue [Line Items]
Revenue auction period	2 years
Networks
Disaggregation of Revenue [Line Items]
Revenue auction period	1 year

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Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 2,270	$ 2,289
Leasing revenue	2	2
Derivative gains (losses)	87	122
Alternative revenue programs	43	37
Other revenue	15	16
Total operating revenues	2,417	2,466
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,350	1,308
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	592	722
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	224	216
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	7	4
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	91	55
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	6	(16)
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(1)	0
Leasing revenue	0	0
Derivative gains (losses)	0	0
Alternative revenue programs	0	0
Other revenue	0	0
Total operating revenues	(1)	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	(1)	0
Networks
Segment Reporting Information [Line Items]
Total operating revenues	2,018	2,076
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,962	2,027
Leasing revenue	2	2
Derivative gains (losses)	0	0
Alternative revenue programs	43	37
Other revenue	11	10
Total operating revenues	2,017	2,076
Networks | Operating Segments | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,350	1,308
Networks | Operating Segments | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	592	722
Networks | Operating Segments | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Operating Segments | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Operating Segments | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Operating Segments | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	20	(3)
Renewables
Segment Reporting Information [Line Items]
Total operating revenues	400	390
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	309	262
Leasing revenue	0	0
Derivative gains (losses)	87	122
Alternative revenue programs	0	0
Other revenue	4	6
Total operating revenues	400	390
Renewables | Operating Segments | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Renewables | Operating Segments | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Renewables | Operating Segments | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	224	216
Renewables | Operating Segments | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	7	4
Renewables | Operating Segments | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	91	55
Renewables | Operating Segments | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ (13)	$ (13)

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Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Mar. 31, 2024 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 257
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	106
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	151
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 116
Remaining performance obligation, period	9 months
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	$ 102
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	$ 30
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	$ 72
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 retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
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	$ 58
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	$ 48
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 retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
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	$ 33
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	$ 26
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 retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
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	$ 8
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	$ 3
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 retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
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	$ 6
Remaining performance obligation, period	1 year
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	$ 5
Remaining performance obligation, period	1 year
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	$ 1
Remaining performance obligation, period	1 year
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]
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 50
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | 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	$ 49
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | 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
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2030-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Remaining performance obligation, period

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Regulatory Assets and Liabilities - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Public Utilities, General Disclosures [Line Items]
Unrecorded regulatory assets	$ 1,157
Unfunded future income tax expense collection period	46 years
Min.
Public Utilities, General Disclosures [Line Items]
Recovery period	6 months
Max.
Public Utilities, General Disclosures [Line Items]
Recovery period	30 months
UIL Holdings
Public Utilities, General Disclosures [Line Items]
Business combination merger related rate credits	$ 1	$ 1
Central Maine Power
Public Utilities, General Disclosures [Line Items]
Deferred income tax recovery period	32 years 6 months

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Regulatory Assets and Liabilities - CMP Distribution Rate Case (Details) - Central Maine Power $ in Thousands	Jun. 06, 2023 USD ($)
Public Utilities, General Disclosures [Line Items]
Distribution revenue requirement	$ 16,750
Approved return on equity	9.35%
Equity ratio	50.00%
Equity ratio for earnings sharing	50.00%
Public utilities, earnings sharing percentage calculation basis	0.0100
Maximum penalty per year for failure to meet specified service quality indicator target	$ 8,800

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Regulatory Assets and Liabilities - NYSEG and RG&E Rate Plans (Details) - USD ($) $ in Millions		3 Months Ended
	Jun. 14, 2023	Mar. 31, 2024	Dec. 31, 2023
Public Utilities, General Disclosures [Line Items]
Regulatory assets		$ 3,806.0	$ 3,529.0
Deferred storm costs, amortization period	10 years
NYSEG and RG&E
Public Utilities, General Disclosures [Line Items]
Percentage of customers' portion of earnings above sharing threshold deferred To reduce outstanding regulatory asset deferral balances		100.00%
Percentage Of Service Provider's Portion Used To Reduce Outstanding Storm-Related Regulatory Asset Deferral Balance		50.00%
Capital investment amount projected	$ 634.0
NYSEG | Electricity
Public Utilities, General Disclosures [Line Items]
Approved return on equity		9.20%
Equity ratio		48.00%
Public utilities, recovery of Major Storm costs	371.0
NYSEG | Natural Gas
Public Utilities, General Disclosures [Line Items]
Approved return on equity		9.20%
Equity ratio		48.00%
RG&E | Electricity
Public Utilities, General Disclosures [Line Items]
Approved return on equity		9.20%
Equity ratio		48.00%
Public utilities, recovery of Major Storm costs	54.6
RG&E | Natural Gas
Public Utilities, General Disclosures [Line Items]
Approved return on equity		9.20%
Equity ratio		48.00%
Super Storm Costs | NYSEG
Public Utilities, General Disclosures [Line Items]
Regulatory assets	52.3
Non-Super Storm Costs | NYSEG
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 96.6
Regulatory items amortization period	7 years
Non-Super Storm Costs | RG&E
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 19.6
Regulatory items amortization period	2 years

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Regulatory Assets and Liabilities - New York Climate Leadership and Community Protection Act(Details) $ in Billions	Oct. 17, 2023	Feb. 16, 2023 USD ($) MW
NYPSC
Public Utilities, General Disclosures [Line Items]
Public utilities, approved transmission upgrade costs		$ 4.4
Public utilities, clean energy capacity (in MW) | MW		3,500
NYSEG and RG&E
Public Utilities, General Disclosures [Line Items]
Public utilities, approved transmission upgrade costs		$ 2.2
Public utilities, utilization rate for construction work in progress	100.00%

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Regulatory Assets and Liabilities - UI, CNG, SCG and BGC Rate Plans (Details) - USD ($) $ in Millions							3 Months Ended
	Nov. 03, 2023	Aug. 25, 2023	Jun. 24, 2022	Jan. 01, 2019	Jan. 01, 2018	Jan. 01, 2017	Mar. 31, 2024
Public Utilities, General Disclosures [Line Items]
Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2024							50.00%
BGC
Public Utilities, General Disclosures [Line Items]
Average increase in customer bills, percentage			$ 5.6
Requested return on equity base percentage			9.70%
Customer receiving percentage			54.00%
PURA
Public Utilities, General Disclosures [Line Items]
Average increase in customer bills, percentage		$ 23.0
PURA | Max.
Public Utilities, General Disclosures [Line Items]
Average increase in base distribution rate, percentage		6.60%
PURA | Min.
Public Utilities, General Disclosures [Line Items]
Average increase in customer bills, percentage		2.00%
PURA | United Illuminating Company (UI)
Public Utilities, General Disclosures [Line Items]
Approved return on equity		8.63%				9.10%
Equity ratio		50.00%
Approved debt capital structure, percentage		50.00%
PURA | SCG
Public Utilities, General Disclosures [Line Items]
Approved return on equity					9.25%
Equity ratio					52.00%
Average increase in customer bills, percentage	$ 40.6
PURA | Connecticut Natural Gas Corporation (CNG)
Public Utilities, General Disclosures [Line Items]
Approved return on equity				9.30%
Average increase in customer bills, percentage	$ 19.8
PURA | Connecticut Natural Gas Corporation (CNG) | Electric And Gas Service Rate Plan Year One
Public Utilities, General Disclosures [Line Items]
Approved return on equity				54.00%
PURA | Connecticut Natural Gas Corporation (CNG) | Electric And Gas Service Rate Plan Year Two
Public Utilities, General Disclosures [Line Items]
Approved return on equity				54.50%
PURA | Connecticut Natural Gas Corporation (CNG) | Electric And Gas Service Rate Plan Year Three
Public Utilities, General Disclosures [Line Items]
Approved return on equity				55.00%

XML

Regulatory Assets and Liabilities - Connecticut Energy Legislation (Details)	Jun. 30, 2022 USD ($) hour
Regulated Operations [Abstract]
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

XML

Regulatory Assets and Liabilities - PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation (Details) - USD ($) $ in Millions	Jul. 14, 2021	May 06, 2021	Apr. 15, 2021
Public Utilities, General Disclosures [Line Items]
Civil penalty amount	$ 1	$ 2
United Illuminating Company (UI)
Public Utilities, General Disclosures [Line Items]
ROE reduction			0.15%

XML

Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Regulatory Assets [Line Items]
Total regulatory assets	$ 3,806	$ 3,529
Less: current portion	745	718
Regulatory assets	3,061	2,811
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	439	445
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	57	58
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	1,052	868
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	42	24
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	101	86
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	33	38
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	25	23
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	6	16
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	244	240
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	57	58
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	17	17
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	601	578
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	129	130
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	19
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	60	59
COVID-19 cost recovery and late payment surcharge
Regulatory Assets [Line Items]
Total regulatory assets	11	12
Low income arrears forgiveness
Regulatory Assets [Line Items]
Total regulatory assets	49	55
Excess generation service charge
Regulatory Assets [Line Items]
Total regulatory assets	86	52
System Expansion
Regulatory Assets [Line Items]
Total regulatory assets	19	22
Non-bypassable charge
Regulatory Assets [Line Items]
Total regulatory assets	124	103
Hedges losses
Regulatory Assets [Line Items]
Total regulatory assets	13	34
Rate Change Levelization [Member]
Regulatory Assets [Line Items]
Total regulatory assets	83	60
Value of distributed energy resources
Regulatory Assets [Line Items]
Total regulatory assets	44	49
Uncollectible reserve
Regulatory Assets [Line Items]
Total regulatory assets	114	104
New York make-whole provision
Regulatory Assets [Line Items]
Total regulatory assets	84	96
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 296	$ 283

XML

Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 2,951	$ 2,955
Less: current portion	275	261
Total non-current regulatory liabilities	2,676	2,694
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	15
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	10	8
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	88	89
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	3
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1	2
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,187	1,190
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,135	1,139
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	9
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	21	21
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	23
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	18
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	40	39
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	26
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	8
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20	21
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	19	19
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	16
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	39	34
Non by-passable charges
Regulatory Liabilities [Line Items]
Total regulatory liabilities	6	9
Transmission revenue reconciliation mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	57
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 234	$ 209

XML

Fair Value of Financial Instruments and Fair Value Measurements - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Fair value of debt	$ 10,136	$ 10,266
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	70.00%
Percentage of natural gas load obligations hedged	55.00%

XML

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	$ 48	$ 45
Netting adjustment	(95)	(81)
Derivative assets	272	230
Netting adjustment	126	172
Derivative liabilities	(182)	(175)
Derivative Financial Instruments, Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(80)	(69)
Derivative assets	109	102
Netting adjustment	101	135
Derivative liabilities	(47)	(43)
Derivative Financial Instruments, Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(15)	(12)
Derivative assets	4	5
Netting adjustment	25	37
Derivative liabilities	0	(1)
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	(34)	(39)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	158	122
Netting adjustment	0	0
Derivative liabilities	(101)	(92)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	30	29
Derivative assets, before netting	23	15
Derivative liabilities, before netting	(36)	(49)
Level 1 | Derivative Financial Instruments, Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	23	15
Derivative liabilities, before netting	(33)	(37)
Level 1 | Derivative Financial Instruments, Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	(3)	(12)
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	18	16
Derivative assets, before netting	248	181
Derivative liabilities, before netting	(194)	(219)
Level 2 | Derivative Financial Instruments, Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	71	42
Derivative liabilities, before netting	(71)	(101)
Level 2 | Derivative Financial Instruments, Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	19	17
Derivative liabilities, before netting	(22)	(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	158	122
Derivative liabilities, before netting	(101)	(92)
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	96	115
Derivative liabilities, before netting	(78)	(79)
Level 3 | Derivative Financial Instruments, Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	95	114
Derivative liabilities, before netting	(44)	(40)
Level 3 | Derivative Financial Instruments, Gas [Member]
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 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	(34)	(39)
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

XML

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, 2024	Mar. 31, 2023
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value Beginning of Period,	$ 36	$ 16
Gains recognized in operating revenues	3	0
(Losses) recognized in operating revenues	$ (19)	$ (3)
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	$ (16)	$ (3)
Gains recognized in OCI	1	11
(Losses) recognized in OCI	$ (6)	$ (3)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Other Comprehensive Income or Comprehensive Income [Extensible Enumeration]	Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $15 and $(1), respectively	Unrealized gain (loss) during the period on derivatives qualifying as cash flow hedges, net of income tax of $15 and $(1), respectively
Total gains or losses recognized in OCI	$ (5)	$ 8
Net change recognized in regulatory assets and liabilities	5	4
Purchases	1	9
Settlements	(3)	(20)
Fair Value as of March 31,	18	14
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	$ (16)	$ (3)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Revenues	Revenues

XML

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price	Mar. 31, 2024 $ / MWh
Ameren | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	42.68
Ameren | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	19.58
Ameren | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	90.60
ComEd | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	38.64
ComEd | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	15.39
ComEd | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	83.36
ERCOT S hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	45.73
ERCOT S hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	16.17
ERCOT S hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	150.55
Mid C | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	84.98
Mid C | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	16.95
Mid C | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	248.45
AEP-DAYTON hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	42.79
AEP-DAYTON hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	20.58
AEP-DAYTON hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	94.32

XML

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details) - Contracts for differences - Level 3	Mar. 31, 2024 $ / kilowatt-MonthOfEnergy
Minimum | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0052
Minimum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0384
Minimum | Measurement Input, Commodity Forward Price
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	2.00
Maximum | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0054
Maximum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0401
Maximum | Measurement Input, Commodity Forward Price
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	2.61

XML

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	$ 272	$ 230
Derivative liabilities	182	175
Cash collateral (payable) receivable	(63)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	1	1
Cash collateral (payable) receivable	0	0
Total derivatives as presented in the balance sheet, Asset	1	1
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	20	13
Derivative liabilities	(19)	(12)
Derivative assets	1	1
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative assets	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	0	0
Cash collateral (payable) receivable	0	0
Total derivatives as presented in the balance sheet, Asset	0	0
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	3
Derivative liabilities	(5)	(3)
Derivative assets	0	0
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative assets	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(23)	(45)
Cash collateral receivable, Liability	6	27
Total derivatives as presented in the balance sheet, Liability	(17)	(18)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	19	12
Derivative liabilities	(42)	(57)
Derivative liabilities	23	45
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative liabilities	0	0
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(24)	(29)
Cash collateral receivable, Liability	7	7
Total derivatives as presented in the balance sheet, Liability	(17)	(22)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	3
Derivative liabilities	(29)	(32)
Derivative liabilities	24	29
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative liabilities	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	90	67
Cash collateral (payable) receivable	(4)	0
Total derivatives as presented in the balance sheet, Asset	86	67
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	64	53
Derivative liabilities	(3)	0
Derivative assets	61	53
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	30	15
Derivative liabilities	(1)	(1)
Derivative assets	29	14
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	185	162
Cash collateral (payable) receivable	0	0
Total derivatives as presented in the balance sheet, Asset	185	162
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	48	52
Derivative liabilities	(1)	(3)
Derivative assets	47	49
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	138	113
Derivative liabilities	0	0
Derivative assets	138	113
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(33)	(60)
Cash collateral receivable, Liability	14	43
Total derivatives as presented in the balance sheet, Liability	(19)	(17)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	43	53
Derivative liabilities	(53)	(73)
Derivative liabilities	10	20
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	14	7
Derivative liabilities	(37)	(47)
Derivative liabilities	23	40
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(36)	(39)
Cash collateral receivable, Liability	8	13
Total derivatives as presented in the balance sheet, Liability	(28)	(26)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	1
Derivative liabilities	(7)	(4)
Derivative liabilities	2	3
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	1
Derivative liabilities	(35)	(37)
Derivative liabilities	$ 34	$ 36

XML

Derivative Instruments and Hedging - Net Notional Volume (Details) MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2024 USD ($) MMBTU MWh	Dec. 31, 2023 USD ($) MWh MMBTU
Networks | Wholesale electricity purchase contracts (MWh) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	6.0	5.6
Networks | Natural gas purchase contracts (Dth) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	9.3	10.7
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value | $	$ 67	$ 64
Renewables | Wholesale electricity purchase contracts (MWh) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	1.0	1.0
Derivative assets (liabilities), fair value | $	$ 8	$ 29
Renewables | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	6.0	6.0
Derivative assets (liabilities), fair value | $	$ 46	$ 14
Renewables | Natural gas and other fuel purchase contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	14.0	21.0
Derivative assets (liabilities), fair value | $	$ 3	$ 4
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	4.0	4.0
Derivative assets (liabilities), fair value | $	$ 10	$ 17
Renewables | Basis swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	21.0	24.0
Renewables | Basis swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	1.0	1.0

XML

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Derivative liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 5	$ 4
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	10		$ 22
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	20	49
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	3		$ 12
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 11	$ 6

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Derivative Instruments and Hedging - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2024 USD ($) instrument	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)	Sep. 15, 2021 USD ($)	Jul. 15, 2021 USD ($)	May 27, 2021 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 3,806		$ 3,529
Regulatory liabilities	2,951		2,955
Derivative assets	185		162
Derivative liabilities	182		175
Aggregate fair value of additional collateral	27
Cash collateral pledged	63
Collateral already posted	$ 13
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative instruments | instrument	2
Derivative liabilities	$ 34		39
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]
Cash flow hedge gain (loss) to be reclassified within twelve months	(9)
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	27		29
Fair Value Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liabilities					$ 750
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(1)	(1)
Cash flow hedge gain (loss) to be reclassified within twelve months	4
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	38		39
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	56	113
Renewables | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	36	$ 90
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	(20)
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount				$ 956		$ 935
Derivative assets	$ 158		122
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	20.00%
Gross derivative asset	$ 1		1
Regulatory assets	33		38
Gross amounts of recognized liabilities	34		39
Regulatory liabilities	$ 0		0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	80.00%
Gross derivative asset	$ 0		0
Gross amounts of recognized liabilities	$ 33		$ 38

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Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest expense	$ 125	$ 95
Purchased power, natural gas and fuel used	724	977
Revenues	2,417	2,466
Networks
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
Revenues	2,018	2,076
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	56	113
Loss (Gain) Reclassified from Accumulated OCI into Income	5	66
Revenues	400	390
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	36	90
Loss (Gain) Reclassified from Accumulated OCI into Income	0	0
Interest expense	125	95
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	0
Loss (Gain) Reclassified from Accumulated OCI into Income	0	0
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) Recognized in OCI on Derivatives	20	23
Loss (Gain) Reclassified from Accumulated OCI into Income	5	66
Revenues	$ 2,417	$ 2,466

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Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 67	$ 64
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	10	17
Long | Wholesale electricity purchase contracts (MWh)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	8	29
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	3	4
Short | Wholesale electricity purchase contracts (MWh)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 46	$ 14

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Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 87	$ 122
Operating revenues	2,417	2,466
Utilities operating expense, purchased power	$ 724	$ 977
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]
Operating revenues	$ 400	$ 390
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	6	5
Renewables | Trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 6	$ 5
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	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]	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	$ (3)	$ (4)
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	11	7
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	0
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	13	(6)
Operating revenues	2,417	2,466
Utilities operating expense, purchased power	724	977
Renewables | Non-trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 22	$ 50
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	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	$ (9)	$ (56)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	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	$ 0	$ 1
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	(17)	(35)
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	22	24
Renewables | Non-trading | Financial power contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	2	15
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	0
Renewables | Non-trading | Financial and natural gas contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(2)	10
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	$ 8	$ (21)

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Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) loss on fair value hedges recognized in Income Statement	$ 11	$ 7
Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(29)		$ (26)
Non-current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(71)		(63)
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	0		0
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	100		$ 89
Fair Value Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Year to date total per Income Statement	$ 125	$ 95

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Contingencies and Commitments (Details) - USD ($) $ in Millions							12 Months Ended
	Feb. 26, 2024	Oct. 27, 2023	Apr. 29, 2016	Jul. 31, 2014	Dec. 26, 2012	Sep. 30, 2011	Dec. 31, 2021	Mar. 31, 2024	Jun. 16, 2023	May 04, 2021	Jan. 04, 2021
Loss Contingencies [Line Items]
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding								$ 918.0
Future payments committed											$ 90.0
NECEC commitment, payment during period							$ 11.0
Transmission - ROE Complaint
Loss Contingencies [Line Items]
Requested return on equity base percentage						11.14%
Customer Service Invoice Dispute
Loss Contingencies [Line Items]
Litigation settlement, adjustment amount requested									$ 31.0	$ 31.0
Solar Contractor Dispute
Loss Contingencies [Line Items]
Amount of liens claimed due under contracts								$ 105.0
Loss contingency, damages sought value	$ 59.9	$ 111.8
Litigation settlement, amount of lien seeking to close		$ 59.9
Unfavorable Regulatory Action | Complaint I
Loss Contingencies [Line Items]
Requested return on equity base percentage						9.20%
Unfavorable Regulatory Action | Transmission - ROE Complaint Two
Loss Contingencies [Line Items]
Requested return on equity base percentage					8.70%
Unfavorable Regulatory Action | Transmission - ROE Complaint Three
Loss Contingencies [Line Items]
Requested return on equity base percentage				8.84%
Unfavorable Regulatory Action | Transmission - ROE Complaint Four
Loss Contingencies [Line Items]
Requested return on equity base percentage			8.61%
Unfavorable Regulatory Action | Transmission - ROE Complaint Four | Max.
Loss Contingencies [Line Items]
Requested return on equity base percentage			11.24%

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Environmental Liabilities (Details)	3 Months Ended	12 Months Ended		80 Months Ended
	Mar. 31, 2024 USD ($) site	Dec. 31, 2012 site	Dec. 31, 2009 site	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($)	Aug. 04, 2016 USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	24
Number of sites with liability recorded	6
Number of sits note expected to incur additional liabilities	18
Number of additional sites with liability recorded	10
Number of sites where gas was manufactured in the past	53
Number of sites for which we have entered into consent orders to investigate and remediate	41
Accrual related to investigation and remediation | $	$ 245,000,000				$ 250,000,000
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 | $	19,000,000
Cost of investigation and remediation | $						$ 30,000,000
Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	15,000,000
Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 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	2
Number of sites where gas was manufactured in the past	0
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past	2
Massachusetts Non-Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	5
Hazardous Substances Waste Sites With Liability Recorded
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 6,000,000
Hazardous Substances Waste Sites Will Incur Remediation And / Or Monitoring Costs
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 10,000,000
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
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	117,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	213,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	0
MGP Sites | FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute			2
NYSEG | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	8,000,000
RG&E | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 5,000,000
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	2

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Post-retirement and Similar Obligations - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2024 USD ($)
Retirement Benefits [Abstract]
Defined benefit, pension contributions	$ 1
Expected future employer contributions in current fiscal year	$ 27

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Post-retirement and Similar Obligations - Periodic Benefit Costs Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 2	$ 2
Interest cost	28	30
Expected return on plan assets	(40)	(36)
Prior service costs	0	0
Actuarial loss	7	1
Net Periodic Benefit Cost	(3)	(3)
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	0	0
Interest cost	3	3
Expected return on plan assets	(1)	(1)
Prior service costs	0	0
Actuarial loss	(1)	(3)
Net Periodic Benefit Cost	$ 1	$ (1)

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Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023	Dec. 31, 2022
Class of Stock [Line Items]
Common stock, held in trust (in shares)	103,889		103,889
Common stock, par value (in dollars per share)	$ 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)	135,345	12,332

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Equity - Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	$ 20,676	$ 20,342
Other comprehensive income (loss), net of tax	46	49
Balance, end of period	20,889	20,510
Unrealized (loss) gain from equity method investment, income tax expense	0	0
Unrealized loss during period on derivatives qualifying as cash flow hedges, income tax benefit	15	(1)
Reclassification to net income of loss on cash flow hedges, income taxes	2	18
Net loss on pension plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(21)	(20)
Other comprehensive income (loss), net of tax	0	0
Balance, end of period	(21)	(20)
Unrealized (loss) gain from equity method investment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	18	13
Other comprehensive income (loss), net of tax	0	(1)
Balance, end of period	18	12
Unrealized loss during period on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(178)	(195)
Other comprehensive income (loss), net of tax	39	(2)
Balance, end of period	(139)	(197)
Reclassification to net income of losses on cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	156	22
Other comprehensive income (loss), net of tax	7	52
Balance, end of period	163	74
Loss (gain) on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(22)	(173)
Other comprehensive income (loss), net of tax	46	50
Balance, end of period	24	(123)
Accumulated Other Comprehensive Income (Loss)
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(25)	(180)
Other comprehensive income (loss), net of tax	46	49
Balance, end of period	$ 21	$ (131)

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Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Numerator:
Net income attributable to Avangrid, basic	$ 351	$ 245
Net income attributable to Avangrid, diluted	$ 351	$ 245
Denominator:
Weighted average number of shares outstanding - basic (in shares)	386,916,234	386,744,996
Weighted average number of shares outstanding - diluted (in shares)	387,239,544	387,077,213
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic (in dollars per share)	$ 0.91	$ 0.63
Earnings Per Common Share, Diluted (in dollars per share)	$ 0.91	$ 0.63

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Segment Information - Additional Information (Details)	3 Months Ended
	Mar. 31, 2024 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

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Segment Information - By Segment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023
Segment Reporting Information [Line Items]
Revenues	$ 2,417	$ 2,466
Depreciation and amortization	298	280
Operating income (loss)	407	265
Earnings (losses) from equity method investments	6	2
Interest expense, net of capitalization	125	95
Income tax expense (benefit)	20	(18)
Adjusted net income (loss)	341	248
Capital expenditures	872	836
Property, plant and equipment	33,323		$ 32,857
Equity method investments	836		718
Total assets	45,062		43,989
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	(1)
Other
Segment Reporting Information [Line Items]
Revenues	0	0
Depreciation and amortization	2	1
Operating income (loss)	(6)	(2)
Earnings (losses) from equity method investments	0	0
Interest expense, net of capitalization	32	19
Income tax expense (benefit)	(31)	(28)
Adjusted net income (loss)	(11)	1
Capital expenditures	2	0
Property, plant and equipment	12		12
Equity method investments	0		0
Total assets	(290)		(962)
Networks
Segment Reporting Information [Line Items]
Revenues	2,018	2,076
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenues	2,017	2,076
Depreciation and amortization	178	174
Operating income (loss)	353	277
Earnings (losses) from equity method investments	4	4
Interest expense, net of capitalization	89	70
Income tax expense (benefit)	57	44
Adjusted net income (loss)	268	195
Capital expenditures	691	609
Property, plant and equipment	22,068		21,692
Equity method investments	188		186
Total assets	31,238		30,413
Networks | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	1
Renewables
Segment Reporting Information [Line Items]
Revenues	400	390
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenues	400	390
Depreciation and amortization	118	105
Operating income (loss)	60	(10)
Earnings (losses) from equity method investments	2	(2)
Interest expense, net of capitalization	4	6
Income tax expense (benefit)	(6)	(34)
Adjusted net income (loss)	84	51
Capital expenditures	179	$ 227
Property, plant and equipment	11,243		11,153
Equity method investments	648		532
Total assets	14,114		$ 14,538
Renewables | Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues	$ 0

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Segment Information - Reconciliation of Adjusted Net Income to Net Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 341	$ 248
Adjustments:
Mark-to-market earnings - Renewables	17	(4)
Accelerated depreciation from repowering	(3)	0
Income tax impact of adjustments	(4)	1
Net Income Attributable to Avangrid, Inc.	$ 351	$ 245

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Related Party Transactions - Schedule of Related Party Transactions (Details) - Related Party - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Sales To | Iberdrola, S.A.
Related Party Transaction [Line Items]
Related party transaction, amount	$ 0	$ 0
Sales To | Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Related party transaction, amount	0	0
Sales To | Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Related party transaction, amount	0	0
Sales To | Vineyard Wind
Related Party Transaction [Line Items]
Related party transaction, amount	3	2
Purchases From | Iberdrola, S.A.
Related Party Transaction [Line Items]
Related party transaction, amount	(12)	(11)
Purchases From | Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Related party transaction, amount	(2)	(2)
Purchases From | Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Related party transaction, amount	(16)	(4)
Purchases From | Vineyard Wind
Related Party Transaction [Line Items]
Related party transaction, amount	$ 0	$ 0

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Related Party Transactions - Schedule of Related Party Balances (Details) - Related Party - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Related Party Transaction [Line Items]
Owed By	$ 5	$ 11
Owed To	(18)	0
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Owed By	0	4
Owed To	(2)	0
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	4	6
Owed To	(8)	(8)
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	1	1
Owed To	(12)	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(6)	(6)
Other
Related Party Transaction [Line Items]
Owed By	4	4
Owed To	(1)	0
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	$ (1,304)	$ (799)

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Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2024	Dec. 31, 2023	Jul. 19, 2023	Jun. 18, 2023
Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Credit facility, amount outstanding	$ 500,000,000	$ 0
Related Party
Related Party Transaction [Line Items]
Notes payable	515,000,000	13,000,000
Related Party | Iberdrola Solutions
Related Party Transaction [Line Items]
Notes payable	6,000,000	6,000,000
Related Party | Affiliated Entity
Related Party Transaction [Line Items]
Impairments	0
Related Party | Iberdrola
Related Party Transaction [Line Items]
Deposit balance	$ 0	$ 0
Related Party | Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity			$ 750,000,000	$ 500,000,000
Credit facility fees percentage	0.225%

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Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - Nonrelated Party - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Supplemental Balance Sheet Information [Line Items]
Trade receivables and unbilled revenues	$ 1,809	$ 1,749
Allowance for credit losses	(169)	(161)
Accounts receivable and unbilled revenues, net	$ 1,640	$ 1,588

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Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 169	$ 148
Current period provision	46	17
Write-off as uncollectible	(38)	(24)
Ending balance	$ 161	$ 155

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Other Financial Statement Items - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023	Dec. 31, 2023	Jul. 19, 2023	Jul. 03, 2023	Dec. 31, 2022
Supplemental Balance Sheet Information [Line Items]
Allowance for doubtful accounts, deferred payment arrangement	$ 169	$ 148	$ 161			$ 155
Provision for doubtful accounts, accounts receivable	46	17
Prepaid other taxes	164		142
Accrued liabilities for property, plant and equipment additions	553	239
Commercial paper	1,864		1,332
Advances received	$ 224		$ 236
Commercial Paper
Supplemental Balance Sheet Information [Line Items]
Weighted-average interest rate	5.55%		5.65%
Intragroup Green Loan | Subordinated Debt
Supplemental Balance Sheet Information [Line Items]
Face amount of debt				$ 800
Fixed interest rate					5.45%
Deferred Payment Arrangements
Supplemental Balance Sheet Information [Line Items]
Accounts receivable	$ 116		$ 110
Allowance for doubtful accounts, deferred payment arrangement	46		$ 44
Provision for doubtful accounts, accounts receivable	$ 2	$ (2)

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Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Property, plant and equipment
Accumulated depreciation	$ 12,732	$ 12,479
Intangible assets
Accumulated amortization	$ 357	$ 351

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Income Tax Expense (Details)	3 Months Ended
	Mar. 31, 2024	Mar. 31, 2023
Income Tax Disclosure [Abstract]
Effective income tax rate	5.80%	(9.10%)

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Stock-Based Compensation Expense (Details) $ / shares in Units, $ in Millions	1 Months Ended							3 Months Ended		12 Months Ended
	Mar. 31, 2024 USD ($) shares	Feb. 29, 2024 USD ($)	Jan. 31, 2024 shares	Mar. 31, 2023 installment shares	Feb. 28, 2023 installment shares	Jun. 30, 2022 installment $ / shares shares	Feb. 28, 2022 installment shares	Mar. 31, 2024 USD ($) installment shares	Mar. 31, 2023 USD ($)	Dec. 31, 2023 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $								$ 3.0	$ 4.0
Performance Shares Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				677,752				15,296		1,067,500
Number of vesting installments | installment				3				3
Number of shares issued (in shares)	126,311
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
Number of vesting installments | installment						2
Number of shares issued (in shares)			9,034
Grant date fair value (in dollars per share) | $ / shares						$ 47.64
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		4
Share based compensation liability | $	$ 1.0							$ 1.0		$ 2.0
Phantom Shares | February 2022 Grant
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash used to settle award | $		$ 0.1
Phantom Shares | February 2023 Grant
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Cash used to settle award | $		$ 1.0

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Variable Interest Entities (Details) - USD ($) $ in Millions	Mar. 31, 2024	Dec. 31, 2023
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)	$ 45,062	$ 43,989
Liabilities of variable interest entities (VIEs)	24,173	23,313
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)	2,740	2,741
Liabilities of variable interest entities (VIEs)	$ 196	$ 174

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Equity Method Investments (Details) $ in Millions		3 Months Ended	12 Months Ended
	Oct. 24, 2023 USD ($)	Mar. 31, 2024 USD ($)	Dec. 31, 2022 USD ($) a easement	Dec. 31, 2023 USD ($)	Jan. 10, 2022 USD ($)	Sep. 15, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Remaining amount expected from tax equity investors in installments		$ 1,100
TEF agreement, total indemnified amount				$ 43
Equity method investments		$ 836		718
Vineyard Wind 1, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		50.00%			50.00%
Remaining amount expected from tax equity investors in installments	$ 1,200
TEF agreement, amount received from tax equity investors	$ 85
TEF agreement, total indemnified amount		$ 43
Vineyard Wind 1, LLC | Renewables
Schedule of Equity Method Investments [Line Items]
Capital amount contributed		116
Vineyard Wind, LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%
Number of easements | easement			2
Equity method investments		$ 419		$ 297
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

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Subsequent Event (Details) - $ / shares		3 Months Ended
	Apr. 11, 2024	Mar. 31, 2024	Mar. 31, 2023
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