Avangrid (AGR) 10-K 22 Feb 24 2023 FY Annual report Financial data

Cover Page

Cover Page - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Feb. 21, 2024	Jun. 30, 2023
Cover [Abstract]
Document Type	10-K
Document Annual Report	true
Document Period End Date	Dec. 31, 2023
Current Fiscal Year End Date	--12-31
Document Transition Report	false
Entity File Number	001-37660
Entity Registrant Name	Avangrid, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	14-1798693
Entity Address, Address Line One	180 Marsh Hill Road
Entity Address, City or Town	Orange,
Entity Address, State or Province	CT
Entity Address, Postal Zip Code	06477
City Area Code	207
Local Phone Number	629-1190
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	AGR
Security Exchange Name	NYSE
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
ICFR Auditor Attestation Flag	true
Document Financial Statement Error Correction Flag	false
Entity Shell Company	false
Entity Public Float			$ 2,665
Entity Common Stock, Shares Outstanding		386,779,949
Documents Incorporated by Reference	Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved. Designated portions of the Proxy Statement relating to the 2024 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.
Amendment Flag	false
Document Fiscal Year Focus	2023
Document Fiscal Period Focus	FY
Entity Central Index Key	0001634997

Audit Information

Audit Information	12 Months Ended
	Dec. 31, 2023
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	New York, NY
Auditor Firm ID	185

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Statement [Abstract]
Operating Revenues	$ 8,309	$ 7,923	$ 6,974
Operating Expenses
Purchased power, natural gas and fuel used	2,429	2,456	1,719
Operations and maintenance	3,109	2,872	2,706
Depreciation and amortization	1,158	1,085	1,014
Taxes other than income taxes, net	683	658	640
Total Operating Expenses	7,379	7,071	6,079
Operating Income	930	852	895
Other Income and (Expense)
Other income	129	30	60
Earnings (losses) from equity method investments	6	262	7
Interest expense, net of capitalization	(409)	(303)	(298)
Income Before Income Tax	656	841	664
Income tax (benefit) expense	(9)	20	21
Net Income	665	821	643
Net loss attributable to noncontrolling interests	121	60	64
Net Income Attributable to Avangrid, Inc.	$ 786	$ 881	$ 707
Earnings Per Common Share, Basic (in dollars per share)	$ 2.03	$ 2.28	$ 1.97
Earnings Per Common Share, Diluted (in dollars per share)	$ 2.03	$ 2.27	$ 1.97
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	386,810,088	386,727,246	358,086,621
Diluted (in shares)	387,164,874	387,215,785	358,578,608

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Net Income	$ 665	$ 821	$ 643
Other Comprehensive Income
Gain for defined benefit plans, net of income taxes of $0, $3 and $0, respectively	0	14	2
Amortization of pension cost, net of income taxes of $0, $1 and $(1), respectively	(1)	4	(8)
Unrealized gain (loss) from equity method investment, net of income taxes of $1, $6 and $(3), respectively	5	22	(9)
Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes of $6, $0 and $(44), respectively	17	(1)	(159)
Reclassification to net income of losses on cash flow hedges, net of income taxes of $48, $19 and $(3), respectively	134	54	12
Other Comprehensive Income (Loss)	155	93	(162)
Comprehensive Income	820	914	481
Net loss attributable to noncontrolling interests	121	60	64
Comprehensive Income Attributable to Avangrid, Inc.	$ 941	$ 974	$ 545

Consolidated Statements of Co_2

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, income taxes	$ 0	$ 3	$ 0
Amortization of pension cost, income taxes	0	1	(1)
Unrealized gain (loss) from equity method investment, income taxes	1	6	(3)
Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, income taxes	6	0	(44)
Reclassification to net income of losses on cash flow hedges, income taxes	$ 48	$ 19	$ (3)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Current Assets
Cash and cash equivalents	$ 91	$ 69
Derivative assets	68	60
Fuel and gas in storage	185	268
Materials and supplies	310	235
Prepayments and other current assets	429	386
Regulatory assets	718	447
Total Current Assets	3,404	3,210
Total Property, Plant and Equipment ($2,643 and $2,707 related to VIEs, respectively)	32,857	30,994
Operating lease right-of-use assets	195	159
Equity method investments	718	437
Other investments	46	49
Regulatory assets	2,811	2,321
Other Assets
Goodwill	3,119	3,119
Intangible assets	284	281
Derivative assets	162	140
Other	393	413
Total Other Assets	3,958	3,953
Total Assets	43,989	41,123
Current Liabilities
Current portion of debt	612	412
Interest accrued	104	66
Accounts payable and accrued liabilities	1,924	2,007
Dividends payable	170	170
Taxes accrued	66	61
Operating lease liabilities	16	13
Derivative liabilities	64	133
Other current liabilities	662	593
Regulatory liabilities	261	354
Total Current Liabilities	5,239	4,416
Regulatory liabilities	2,694	2,915
Other Non-current Liabilities
Deferred income taxes	2,451	2,234
Deferred income	996	1,062
Pension and other postretirement	554	491
Operating lease liabilities	199	161
Derivative liabilities	111	164
Asset retirement obligations	306	273
Environmental remediation costs	254	279
Other	525	563
Total Other Non-current Liabilities	5,396	5,227
Total Non-current Liabilities	18,074	16,365
Total Liabilities	23,313	20,781
Commitments and Contingencies	0	0
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,872,787 and 387,734,757 shares issued; 386,770,915 and 386,628,586 shares outstanding, respectively	4	3
Additional paid-in capital	17,701	17,694
Treasury stock	(47)	(47)
Retained earnings	2,015	1,910
Accumulated other comprehensive loss	(25)	(180)
Total Stockholders’ Equity	19,648	19,380
Noncontrolling interests	1,028	962
Total Equity	20,676	20,342
Total Liabilities and Equity	43,989	41,123
Nonrelated Party
Current Assets
Accounts receivable from affiliates	1,588	1,737
Current Liabilities
Notes payable	1,347	566
Other Non-current Liabilities
Non-current debt	9,184	8,215
Related Party
Current Assets
Accounts receivable from affiliates	11	5
Notes receivable from affiliates	4	3
Current Liabilities
Notes payable	13	2
Accounts payable to affiliates	0	39
Other Non-current Liabilities
Non-current debt	$ 800	$ 8

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property, plant and equipment	$ 32,857	$ 30,994
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	500,000,000	500,000,000
Common stock issued (in shares)	387,872,787	387,734,757
Common stock, outstanding (in shares)	386,770,915	386,628,586
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 2,643	$ 2,707

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Flow from Operating Activities
Net income	$ 665	$ 821	$ 643
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	1,158	1,085	1,014
Accretion expenses	15	14	12
Regulatory assets/liabilities amortization and carrying cost	(39)	(65)	(72)
Pension cost	(13)	11	52
Earnings from equity method investments	(6)	(262)	(7)
Distribution of earnings from equity method investments	28	23	17
Unrealized (gains) losses on marked to market derivative contracts	(21)	0	86
Loss from divestment and disposal of property	5	2	24
Deferred taxes	44	18	11
Other non-cash items	(87)	(48)	(82)
Changes in operating assets and liabilities:
Current assets	(162)	(837)	(275)
Noncurrent assets	(401)	(123)	(45)
Current liabilities	(147)	385	286
Noncurrent liabilities	(120)	11	(103)
Net Cash Provided by Operating Activities	919	1,035	1,561
Cash Flow from Investing Activities
Capital expenditures	(2,972)	(2,519)	(2,976)
Contributions in aid of construction	112	123	130
Proceeds from sale of property, plant and equipment	65	31	24
(Payments to) receipts from affiliates	0	(3)	5
Cash distribution from equity method investments	4	18	155
Other investments and equity method investments, net	(308)	(198)	222
Net Cash Used in Investing Activities	(3,099)	(2,548)	(2,440)
Cash Flow from Financing Activities
Receipts (Repayments) of other short-term debt, net	768	236	(306)
Repayments of financing leases	(6)	(9)	(6)
Repurchase of common stock	0	0	(33)
Issuance of common stock	(3)	(1)	3,998
Distributions to noncontrolling interests	(16)	(10)	(10)
Contributions from noncontrolling interests	203	147	330
Dividends paid	(681)	(681)	(613)
Net Cash Provided by Financing Activities	2,202	108	889
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	22	(1,405)	10
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	72	1,477	1,467
Cash, Cash Equivalents and Restricted Cash, End of Year	94	72	1,477
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	338	273	279
Cash (refund) paid for income taxes, net of transferred tax credits (Note 16)	(40)	15	2
Nonrelated Party
Cash Flow from Financing Activities
Non-current debt issuances	1,515	791	833
Repayments of non-current debt	(378)	(365)	(304)
Related Party
Cash Flow from Financing Activities
Non-current debt issuances	800	0	0
Repayments of non-current debt	$ 0	$ 0	$ (3,000)

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Total Stockholders' Equity	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Non-controlling Interests
Balance at beginning of period (in shares) at Dec. 31, 2020	[1]			309,077,300
Balance at beginning of period at Dec. 31, 2020		$ 15,826	$ 15,209	$ 3		$ 13,665	$ (14)	$ 1,666	$ (111)	$ 617
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		643	707					707		(64)
Other comprehensive income (loss), net of tax		(162)	(162)						(162)
Comprehensive Income		481
Dividends declared		(647)	(647)					(647)
Release of common stock held in trust (in shares)	[1]			301,239
Issuance of common stock (in shares)	[1]			77,883,713
Issuance of common stock		3,998	3,998			3,998
Repurchase of common stock (in shares)	[1]			(694,148)
Repurchase of common stock		(33)	(33)				(33)
Stock-based compensation		16	16			16
Distributions to noncontrolling interests		(10)								(10)
Contributions from noncontrolling interests		330	(12)					(12)		342
Balance at end of period (in shares) at Dec. 31, 2021	[1]			386,568,104
Balance at end of period at Dec. 31, 2021		19,961	19,076	$ 3		17,679	(47)	1,714	(273)	885
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		821	881					881		(60)
Other comprehensive income (loss), net of tax		93	93						93
Comprehensive Income		914
Dividends declared		$ (681)	(681)					(681)
Release of common stock held in trust (in shares)		4,355		4,355	[1]
Issuance of common stock (in shares)	[1]			56,127
Issuance of common stock		$ (1)	(1)			(1)
Repurchase of common stock		0
Stock-based compensation		16	16			16
Distributions to noncontrolling interests		(10)								(10)
Contributions from noncontrolling interests		$ 143	(4)					(4)		147
Balance at end of period (in shares) at Dec. 31, 2022		386,628,586		386,628,586	[1]
Balance at end of period at Dec. 31, 2022		$ 20,342	19,380	$ 3		17,694	(47)	1,910	(180)	962
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		665	786					786		(121)
Other comprehensive income (loss), net of tax		155	155						155
Comprehensive Income		820
Dividends declared		$ (681)	(681)					(681)
Release of common stock held in trust (in shares)		4,299		4,299	[1]
Issuance of common stock (in shares)	[1]			138,030
Issuance of common stock		$ (3)	(3)	$ 1		(4)
Stock-based compensation		11	11			11
Distributions to noncontrolling interests		(16)								(16)
Contributions from noncontrolling interests		$ 203								203
Balance at end of period (in shares) at Dec. 31, 2023		386,770,915		386,770,915	[1]
Balance at end of period at Dec. 31, 2023		$ 20,676	$ 19,648	$ 4		$ 17,701	$ (47)	$ 2,015	$ (25)	$ 1,028
[1]Par value of share amounts is $.01

Consolidated Statements of Ch_2

Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Statement of Stockholders' Equity [Abstract]
Other comprehensive Income (loss), tax	$ 55	$ 29	$ (51)
Dividends declared (in dollars per share)	$ 1.76	$ 1.76	$ 1.76
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01

Background and Nature of Operat

Background and Nature of Operations	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Background and Nature of Operations	Background and Nature of Operations Avangrid, Inc. (Avangrid, we or the Company) is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.6% of the outstanding common stock of Avangrid. The remaining outstanding shares are owned by various shareholders, with approximately 14.7% of Avangrid's outstanding shares publicly-traded on the New York Stock Exchange (NYSE). Termination of a Material Definitive Agreement On December 31, 2023, Avangrid sent a notice to PNM Resources, Inc., a New Mexico corporation (PNMR), terminating the previously announced Agreement and Plan of Merger (as amended by the Amendment to Merger Agreement dated January 3, 2022, Amendment No. 2 to the Merger Agreement dated April 12, 2023 and Amendment No. 3 to the Merger Agreement dated June 19, 2023 (Merger Agreement)), pursuant to which NM Green Holdings, Inc. a New Mexico corporation and wholly-owned subsidiary of the corporation (Merger Sub), agreed to merge with and into PNMR (Merger), with PNMR surviving the Merger as a direct wholly-owned subsidiary of Avangrid. A description of the Merger Agreement was included in the Current Reports on Form 8-K filed by Avangrid on October 21, 2020, January 3, 2022, April 12, 2023 and June 20, 2023, and is incorporated herein by reference. The Merger was conditioned, among other things, upon the receipt of certain required regulatory approvals, including the approval of the New Mexico Public Regulation Commission (NMPRC), and provided that the Merger Agreement may be terminated by either Avangrid or PNMR if the closing of the Merger shall not have occurred by 5:00 PM New York City Time on December 31, 2023 (End Date). Because the required approval of the NMPRC was not received by the End Date and the conditions to the closing of the Merger were thus not satisfied by the End Date, Avangrid exercised its right to terminate the Merger Agreement. No termination penalties were incurred by either party in connection with the termination of the Merger Agreement. The Funding Commitment Letter and related side letter agreement terminated automatically upon termination of the Merger Agreement. In light of the termination of the Merger Agreement, on January 8, 2024, Avangrid filed a motion to withdraw from the appeal it and PNMR’s subsidiary, Public Service Company of New Mexico (PNM), had filed with the New Mexico Supreme Court with respect to the NMPRC’s December 8, 2021, order which had rejected the amended stipulated agreement entered into by PNM, Avangrid and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of Avangrid and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation in all periods presented.

Summary of Significant Accounti

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates	Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates Significant Accounting Policies We consider the following policies to be the most significant in understanding the judgments that are involved in preparing our consolidated financial statements: (a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting. (b) Revenue recognition We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Refer to Note 4 for further details. (c) Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets primarily represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates. (d) Business combinations and assets acquisitions (disposals) We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred. In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed. (e) Noncontrolling interests Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement. Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets. (f) Equity method investments We account for joint ventures and other equity investments that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from equity method investments as a reduction in the carrying amount of the investment and not as dividend income. When an equity method investee executes derivative transactions that have cash flow hedge accounting treatment, we recognize our share of the OCI in our consolidated balance sheet. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary. (g) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four (h) Property, plant and equipment We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment. We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service. We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation. We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations Structural components 25-40 Rotary components 25-30 Solar power stations 30 Transmission and transport facilities 10-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 10-85 Computer software 1-25 Other Buildings 10-75 Operations offices 4-70 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation was 2.8% of average depreciable property for both 2023 and 2022. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income. (i) Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on the information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes an option to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets. (j) Impairment of long-lived assets We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. For the Renewables segment, the property, plant and equipment are grouped on a market hub-basis where we have interdependent revenues. Renewables development projects (e.g., prior to reaching the commercial operation date) are analyzed for impairment at a project level. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset. (k) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair value. (l) Equity investments with readily determinable fair values We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income. (m) Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Certain derivatives that hedge specific cash flows that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. Certain interest rate derivatives that hedge a liability (i.e. debt) that qualify and are designated for hedge accounting are classified as fair value hedges. Changes in the fair value of interest rate derivatives designated as a fair value hedge and the offsetting changes in the fair value of the underlying hedged exposure (i.e. debt) are recorded in Interest expense. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Renewables classifies certain contracts for the purchase and sale of both gas and electricity as derivatives, in accordance with the applicable accounting standards. Renewables may also have gains or losses from certain contracts, that are not designated as cash flow hedges, including those entered into for proprietary trading purposes, which it generally classifies as derivative revenue. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. (n) Cash and cash equivalents Cash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows. (o) Trade receivables and unbilled revenues, net of allowance for credit losses We record trade receivables at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain trade receivables and payables related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services and energy management are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets. Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. As required by their state regulatory commissions, the affected utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. We consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts. (p) Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors. (q) Debentures, bonds and bank borrowings We record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets. (r) Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.” (s) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses. (t ) Deferred income Apart from government grants, we occasionally receive payments from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such payments on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met. (u) Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. We record AROs for the decommissioning of the wind and solar farms and thermal facilities. Projected removal costs are based on engineering estimates which are updated on an annual basis based on the relevant inflation and discount rate factors. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations. (v) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis. (w) Post-employment and other employee benefits We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. If a plan meets settlement or curtailment criteria, we recognize a regulatory asset or liability if these costs are probable of recovery from ratepayers. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amor

Revenue

Revenue	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Revenue	Revenue We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of 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 24. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all or a percentage of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. There are no 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 Costs, Contract Liabilities and Practical Expedient We have contract assets for costs from development success fees, which we paid during a solar farm asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in April 2024 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2023 and 2022, and are presented in "Other non-current assets" on our consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $18 million and $33 million at December 31, 2023 and 2022, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $45 million, $33 million and $22 million as revenue related to contract liabilities for the years ended December 31, 2023, 2022 and 2021, respectively. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs. Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2023, 2022 and 2021 are as follows: Year Ended December 31, 2023 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,962 $ — $ — $ 4,962 Regulated operations – natural gas 1,617 — — 1,617 Nonregulated operations – wind — 817 — 817 Nonregulated operations – solar — 46 — 46 Nonregulated operations – thermal — 180 — 180 Other (a) 76 (52) (2) 22 Revenue from contracts with customers 6,655 991 (2) 7,644 Leasing revenue 9 — — 9 Derivative revenue — 450 — 450 Alternative revenue programs 137 — — 137 Other revenue 54 15 — 69 Total operating revenues $ 6,855 $ 1,456 $ (2) $ 8,309 Year Ended December 31, 2022 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,610 $ — $ — $ 4,610 Regulated operations – natural gas 1,931 — — 1,931 Nonregulated operations – wind — 947 — 947 Nonregulated operations – solar — 36 — 36 Nonregulated operations – thermal — 96 — 96 Other (a) 117 48 — 165 Revenue from contracts with customers 6,658 1,127 — 7,785 Leasing revenue 8 — — 8 Derivative revenue — 4 — 4 Alternative revenue programs 68 — — 68 Other revenue 48 10 — 58 Total operating revenues $ 6,782 $ 1,141 $ — $ 7,923 Year Ended December 31, 2021 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,015 $ — $ — $ 4,015 Regulated operations – natural gas 1,516 — — 1,516 Nonregulated operations – wind — 1,028 — 1028 Nonregulated operations – solar — 20 — 20 Nonregulated operations – thermal — 63 — 63 Other (a) 67 84 — 151 Revenue from contracts with customers 5,598 1,195 — 6,793 Leasing revenue 7 — — 7 Derivative revenue — 3 — 3 Alternative revenue programs 115 — — 115 Other revenue 34 22 — 56 Total operating revenues $ 5,754 $ 1,220 $ — $ 6,974 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations. As of December 31, 2023 and 2022, accounts receivable balances related to contracts with customers were approximately $1,441 million and $1,622 million, respectively, including unbilled revenues of $426 million and $541 million, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets. As of December 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2023 2024 2025 2026 2027 2028 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ — $ — $ — $ — $ — $ 1 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 69 67 34 13 1 2 186 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 89 28 10 7 5 54 193 Total operating revenues $ 159 $ 95 $ 44 $ 20 $ 6 $ 56 $ 380 We do not disclose information about remaining performance obligations for contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

Industry Regulation

Industry Regulation	12 Months Ended
	Dec. 31, 2023
Regulated Operations [Abstract]
Industry Regulation	Industry Regulation Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts Each of Networks’ eight regulated utility companies must comply with regulatory procedures that differ in form but in all cases conform to the basic framework outlined below. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection from, and automatic adjustments for, exceptional costs incurred and efficiency incentives. The distribution rates and allowed ROEs for Networks’ regulated utilities in New York are subject to regulation by the New York Public Service Commission (NYPSC), in Maine by the Maine Public Utilities Commission (MPUC), in Connecticut by the Connecticut Public Utilities Regulatory Authority (PURA) and in Massachusetts by the Department of Public Utilities (DPU). The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to the Networks companies are approved by the regulatory commissions of the different states and are based on the cost of providing service. The revenues of each of the Networks companies are set to be sufficient to cover their operating costs, including energy costs, finance costs and the costs of equity, the last of which reflects our capital ratio and a reasonable ROE. Energy costs that are incurred in the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York and Connecticut revenues that allow a utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting in future tariff reductions. The NYSEG and RG&E rate plans, the Maine distribution rate plan and associated proceedings, the Federal Energy Regulatory Commission (FERC) Transmission Return on Equity (ROE) case, the Connecticut rate plans, proceedings on Transmission Planning Pursuant to the Accelerated Renewable Energy Growth and Community Benefit Act, Climate Leadership and Community Protection Act (CLCPA), Gas Planning Order, Reforming Energy Vision (REV), the storm proceedings in New York and the Tax Act are some of the most important specific regulatory processes that currently affect Networks. CMP Distribution Rate Case In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. Commencing on March 1, 2020, the MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order. On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. On May 31, 2023, CMP filed a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 100 basis points of CMP’s allowed ROE. The Stipulation also provides for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. The next three increases will occur on January 1, 2024, July 1, 2024, and January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecast by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets. No party opposed the Stipulation and it was approved in its entirety by the MPUC on June 6, 2023. NYSEG and RG&E Rate Plans 2020 Joint Proposal On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG and RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed ESM, the equity ratio is the lower of the actual equity ratio or 50.00%. 2023 Joint Proposal On May 26, 2022, NYSEG and RG&E filed for a new rate plan with the NYPSC. The rate filings were based on test year 2021 financial results adjusted to the rate year May 1, 2023 – April 30, 2024. NYSEG and RG&E filed for a one-year rate plan but expressed interest in exploring a multi-year plan during the pendency of the case (as is the custom in New York). On September 16, 2022, the NYPSC suspended new tariffs and rates through April 21, 2023, and NYSEG and RG&E voluntarily agreed to subsequent suspensions through October 18, 2023, subject to a make-whole provision. Following discovery and settlement negotiations, on June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. Hearings on the settlement followed in July 2023. The 2023 JP provides for a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2023 and continuing through April 30, 2026. For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the JP 2023, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs 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. Actual bill impacts vary by customer class based on the agreed‑upon revenue allocation and rate design. The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas is 9.20%. The common equity ratio for each business is 48.00%. The 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 CLCPA including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan. UI, CNG, SCG and BGC Rate Plans Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills. UI has wholesale power supply agreements in place for its entire standard service load for the first 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. In 2016, PURA approved new distribution rate schedules for UI for three years, which became effective January 1, 2017 and, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% equity ratio, continued UI’s existing ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. On September 9, 2022, UI filed a distribution revenue requirement case proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (UI Rate Year 1), September 1, 2024 (UI Rate Year 2), and September 1, 2025 (UI Rate Year 3). UI requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $91 million in UI Rate Year 1, an incremental increase of approximately $20 million in UI Rate Year 2, and an incremental increase of approximately $19 million in UI Rate Year 3, compared to total revenues that would otherwise be recovered under UI’s current rate schedules. UI’s Rate Plan also included several measures to moderate the impact of the proposed rate update for all customers, including, without limitation, a rate levelization proposal to spread the proposed total rate increase over the three rate years, which would result in a change in revenue in UI Rate Year 1 of approximately $54 million. On July 21, 2023, PURA issued a proposed Final Decision (draft decision), providing for an 8.8% ROE, 50% equity ratio, and for a one-year rate plan. UI filed exceptions to the draft decision on August 7, 2023. On August 25, 2023 PURA issued its Final Decision on UI's one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels. On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because 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 April 24, 2023 the Connecticut Attorney General, Office of Consumer Counsel, Connecticut Public Utilities Regulatory Authority Office of Education, Outreach, and Enforcement and the Connecticut Industrial Energy Consumer filed a Petition requesting that PURA conduct a general rate hearing for CNG. On May 5, 2023, CNG and SCG responded indicating a willingness to file general rate cases for each company by November 1, 2023. PURA assented to the companies’ proposal on May 21, 2023. On September 29, 2023, SCG and CNG filed a notice of intent to file general rate cases on or about November 3, 2023. On 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. The filing was based on a test year ending December 31, 2022. 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 Plan 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. On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval. The Settlement Agreement followed BGC’s December 14, 2021 filing of a Notice of Intent to File Rate Schedules. Following that filing, BGC and the AGO negotiated the Settlement Agreement in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allows for agreed-upon adjustments to BGC’s revenue requirement as well as various step increases BGC shall be entitled to on January 1, 2023 and January 1, 2024. The Settlement Agreement provides that it shall be void unless approved in its entirety by the DPU by November 1, 2022. It provides for the opportunity to increase BGC’s revenue requirement by as much as $5.6 million over current rates (reflective of a 9.70% ROE and a 54.00% equity ratio as well as other stepped adjustments) through January 1, 2024. The Settlement Agreement was approved in its entirety by the DPU on October 27, 2022, and new rates went into effect January 1, 2023. REV In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide-ranging initiative to reform New York State’s energy industry and regulatory practices. REV was divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources (DER), such as micro grids, on-site power supplies and storage. The NYPSC issued a 2015 order in Track 1, which acknowledged the utilities’ role as a Distribution System Platform provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) followed by bi-annual updates. The next scheduled DSIP update is June 30, 2025. A Track 2 order was issued in May 2016, and included guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs and data utilization and security. EAMs were approved by the Commission on November 19, 2020 in its Order approving the companies' 2020 Rate Plan. Modifications to EAMs were approved by the Commission on October 12, 2023 in its Order approving the companies' 2023 Rate Plan. In 2017, the NYPSC approved a transition from traditional Net Energy Metering (NEM) towards a more values-based approach (Value Stack) for compensating DER. Since that time, the Commission has issued a number of orders on additional Value of Distributed Energy Resources matters. Most recently, the NYPSC Staff issued a proposal on Community Distributed Generation (CDG) Billing and Crediting Performance Metrics and Negative Revenue Adjustments (NRA). The NYPSC Staff recommends six CDG performance metrics with associated NRAs that would incent improvements to the CDG billing processes. At this time, the outcome of this proceeding is unknown. Other REV-related orders pertaining to electric vehicles (EV), an Integrated Energy Data Resource (IEDR) platform and energy storage are summarized below. • The NYPSC issued an Order on April 20, 2023 instituting a proceeding to advance infrastructure for medium and heavy-duty vehicles. The Joint Utilities filed an implementation plan with the NYPSC for the medium and heavy-duty pilot program. The Joint Utilities are awaiting the NYPSC's approval of the implementation plan. • On February 11, 2021, the NYPSC issued an Order to implement an Integrated Energy Data Resource platform, where NYSERDA was designated as the Program Sponsor of the platform. The Order established a combined cost cap of $12 Million for NYSEG and RG&E for Phase 1, to be deferred and recovered in the next rate case filing after Phase 1 is complete. On January 19, 2024, the NYPSC issued an Order approving Phase 2 budget, with costs up to the combined cost cap deferred for future recovery in the same manner as Phase 1. • An order was issued on July 16, 2020 approving a $700 million statewide program (NYSEG and RG&E combined share is approximately $118 million) funded by customers to accelerate the deployment of EV charging stations. • On December 13, 2018, the NYPSC issued an Order for utilities to file implementation plans detailing a competitive procurement process and cost recovery for deploying qualified storage systems. NYSEG and RG&E have tariffs in effect to collect costs for the procurement of qualified energy storage assets. Tax Cuts and Jobs Act On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Tax Act) was signed into law. The Tax Act significantly changed the federal taxation of business entities including, among other things, implementing a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions. With regard to SCG, we expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case, unless PURA determines otherwise. Power Tax Audits Previously, CMP, NYSEG and RG&E implemented Power Tax software to track and measure their respective deferred tax amounts. In connection with this change, we identified historical updates needed with deferred taxes recognized by CMP, NYSEG and RG&E and increased our deferred tax liabilities, with a corresponding increase to regulatory assets, to reflect the updated amounts calculated by the Power Tax software. Since 2015, the NYPSC and MPUC accepted certain adjustments to deferred taxes and associated regulatory assets for this item in recent distribution rate cases, resulting in regulatory asset balances of approximately $130 million and $137 million, respectively for this item at December 31, 2023 and 2022. In 2017, audits of the power tax regulatory assets were commenced by the NYPSC and MPUC. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax accounting. The NYPSC audit process was completed and the final audit report issued by the NYPSC on November 21, 2023 with no impacts to the recorded regulatory assets. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which required CMP to provide support for the beginning balance of the regulatory assets. On December 17, 2019, CMP filed a stipulation with the MPUC providing for recovery of the power tax regulatory asset and adjusting the carrying costs values for the period of July 1, 2017 through June 30, 2019. The MPUC approved the stipulation on January 21, 2020, which allowed CMP to start collecting the Power Tax Regulatory asset over the next 32.5 years beginning in July 2020. Minimum Equity Requirements for Regulated Subsidiaries Our regulated utility subsidiaries of Maine and New York (NYSEG, RG&E, CMP and MNG) are each subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements, each of NYSEG, RG&E, CMP and MNG must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis, each utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that may be paid and may, under certain circumstances, require that the parent contribute equity capital. In addition, NYSEG and RG&E equity distributions that would result in a 13-month average common equity less than the maximum equity ratio utilized for the earnings sharing mechanism, or ESM, are prohibited if the credit ratings of NYSEG, RG&E, Avangrid or Iberdrola are downgraded by a nationally recognized rating agency to the lowest investment grade with a negative watch or downgraded to non-investment grade. These regulated utility subsidiaries are prohibited by regulation from lending to unregulated affiliates. These regulated utility subsidiaries have also agreed to minimum equity ratio requirements in certain borrowing agreements. These requirements are lower than the regulatory requirements. Pursuant to agreements with the relevant utility commission, UI, SCG, CNG and BGC are restricted from paying dividends if paying such dividend would result in a common equity ratio lower than 300 basis points below the equity percentage used to set rates in the most recent distribution rate proceeding as measured using a trailing 13-month average calculated as of the most recent quarter end. In addition, UI, SCG, CNG and BGC are prohibited from paying dividends to their parent if the utility’s credit rating, as rated by any of the three major credit rating agencies, falls below investment grade, or if the utility’s credit rating, as determined by two of the three major credit rating agencies, falls to the lowest investment grade and there is a negative watch or review downgrade notice. We had restricted net assets of approximately $6,860 million associated with the minimum equity requirements as of December 31, 2023. Movement of capital from our wholly owned unregulated subsidiaries is unrestricted. New Renewable Source Generation Under Connecticut Public Act (PA) 11-80, Connecticut electric utilities are required to enter into long-term contracts to purchase Connecticut Class I RECs from renewable generators located on customer premises. Under this program, UI was initially required to enter into contracts totaling approximately $200 million in commitments over an approximate 21-year period. The obligations were initially expected to phase in over a six-year solicitation period and peak at an annual commitment level of about $14 million per year after all selected projects are online. PA 17-144, PA 18-50 and PA 19-35 extended the original six-year solicitation period of the program by adding seventh, eighth, ninth, and tenth years, and increased the original funding level of this program by adding up to $64 million in additional commitments by UI. Upon purchase, UI accounts for the RECs as inventory. UI expects to partially mitigate the cost of these contracts through the resale of the RECs. PA 11-80 provides that the remaining costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable from (or credited to) customers through electric rates. In October of 2018, UI entered into five PPAs totaling approximately 50 MW from developers of offshore wind and fuel cell generation pursuant to state law that provides the net costs of the PPAs are recoverable through electric rates. On December 19, 2018, PURA approved the PPAs, and approved UI’s use of the non-bypassable federally mandated congestion charges for all customers to recover the net costs of the PPAs. In 2019, UI entered into PPAs with 11 projects, totaling approximately 12 million MWh, pursuant to state law that provides that the net costs of the PPAs are recoverable through electric rates. UI terminated eight of these contracts in 2022 and 2023, and the remaining three projects with existing contracts from these 2019 procurements are with Millstone Nuclear, Seabrook Nuclear and Revolution Wind. In 2020, pursuant to the Connecticut Act Concerning the Procurement of Energy Derived From Offshore Wind, UI entered into a PPA with Vineyard Wind, an affiliate of UI, to provide 804 MW of offshore wind through the development of its Park City Wind Project. Similar to the case with the zero carbon PPAs discussed above, the net costs of the PPAs were recoverable through electric rates. On October 13, 2023, PURA approved the termination of this agreement between UI and its affiliate for the development of Park City Wind Project. Pursuant to Maine law, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of energy, capacity or RECs, from qualifying resources. The MPUC is further authorized to order Maine transmission and distribution utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreen’s 60 Megawatt (MW) Rollins wind farm. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. Pursuant to a MPUC Order dated August 17, 2013, CMP entered into a 20-year fixed rate agreement with Maine Wood Pellets, a 7.1 MW wood-fired biomass cogeneration facility. Pursuant to a MPUC Order dated September 22, 2016, CMP entered into a 20-year fixed rate agreement with Georges River Energy, a 7.5 MW wood-fired biomass cogeneration facility. Pursuant to a MPUC Order dated August 3, 2017, CMP entered into a 20-year fixed rate agreement with Pittsfield Solar 9.9 MW photovoltaic facility. Pursuant to a MPUC Order dated December 18, 2017, CMP entered into a 20-year agreement with Dirigo Solar, LLC on September 10, 2018, to purchase capacity and energy from multiple Dirigo solar facilities throughout CMP’s service territory. CMP’s purchase obligations under the Dirigo contract will increase as additional solar facilities are brought on line, eventually reaching a level of approximately $4 million per year. Pursuant to a MPUC Order dated November 6, 2019, CMP entered into a 20-year agreement with Maine Aqua Ventus I GP LLC on December 9, 2019, to purchase capacity and energy from an off-shore wind farm under development near Monhegan Island, Maine. CMP’s purchase obligations under the Maine Aqua Ventus contract will be approximately $12 million per year once the facility begins commercial operation. Pursuant to Maine law, the MPUC conducted two competitive solicitation processes to procure, in the aggregate, an amount of energy or RECs from Class 1A resources that is equal to 14% of retail electricity sales in the State during calendar year 2018, or 1.715 million MWh. Of that 14% total, the MPUC must acquire at least 7%, but not more than 10%. Through contracts approved in December 2020 (Tranche 1), CMP was ordered to execute 13 contracts of which six have been terminated. In October 2021 CMP executed contracts with six additional facilities (Tranche 2), of which one has since terminated. Each of the Tranche 1 and Tranche 2 contracts are for 20-year terms. In accordance with MPUC orders, CMP either sells the purchased energy, or in one case the RECs, from these facilities in the ISO New England markets, through periodic auctions of the purchased output to wholesale buyers in the New England regional market, or through a sale to a third party for the RECs. Under Maine law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under Maine law, and has tentatively accepted long-term proposals from other sellers, these selections have not yet resulted in additional currently effective contracts with CMP. Connecticut Energy L

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2023
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize as regulatory assets incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,249 million. The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. Regulatory assets as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Pension and other post-retirement benefits $ 445 $ 365 Pension and other post-retirement benefits cost deferrals 58 93 Storm costs 868 671 Rate adjustment mechanism 24 41 Revenue decoupling mechanism 86 52 Contracts for differences 38 56 Hardship programs 23 33 Deferred purchased gas 16 56 Environmental remediation costs 240 248 Debt premium 58 64 Unamortized losses on reacquired debt 17 19 Unfunded future income taxes 578 492 Federal tax depreciation normalization adjustment 130 137 Asset retirement obligation 19 20 Deferred meter replacement costs 59 55 COVID-19 cost recovery and late payment surcharge 12 17 Low income arrears forgiveness 55 31 Excess generation service charge 52 24 System Expansion 22 21 Non-bypassable charge 103 14 Hedges losses 34 13 Rate change levelization 60 — Value of distributed energy resources 49 36 Uncollectible reserve 104 — New York make-whole provision 96 — Other 283 210 Total regulatory assets 3,529 2,768 Less: current portion 718 447 Total non-current regulatory assets $ 2,811 $ 2,321 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases. “Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period. "Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. “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 December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Energy efficiency portfolio standard $ 15 $ 30 Gas supply charge and deferred natural gas cost 8 15 Pension and other post-retirement benefits cost deferrals 89 117 Carrying costs on deferred income tax bonus depreciation 3 9 Carrying costs on deferred income tax - Mixed Services 263(a) 2 3 2017 Tax Act 1,190 1,232 Accrued removal obligations 1,139 1,178 Positive benefit adjustment 9 16 Deferred property tax 21 17 Net plant reconciliation 23 11 Debt rate reconciliation 18 32 Rate refund – FERC ROE proceeding 39 36 Transmission congestion contracts 26 31 Merger-related rate credits 8 10 Accumulated deferred investment tax credits 21 22 Asset retirement obligation 19 18 Middletown/Norwalk local transmission network service collections 16 17 Non-firm margin sharing credits 34 27 Non by-passable charges 9 76 Transmission revenue reconciliation mechanism 57 75 Other 209 297 Total regulatory liabilities 2,955 3,269 Less: current portion 261 354 Total non-current regulatory liabilities $ 2,694 $ 2,915 “Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. "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 14 for more details. "Transmission congestion contracts" represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In both of the years ended December 31, 2023 and 2022, $2 million of rate credits were applied against customer bills. "Asset retirement obligation" represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability . "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.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Goodwill and Intangible Assets Goodwill by reportable segment as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 372 Total $ 3,119 $ 3,119 During 2023, there were no changes in gross amounts and accumulated losses of goodwill for the Networks and Renewables reportable segments. Goodwill Impairment Assessment For impairment testing purposes, our reporting units are the same as operating segments, except for Networks, which contains three reporting units, Maine, New York and UIL. Goodwill for the Maine reporting unit is $325 million from the purchase of CMP by Energy East Corporation in 2000. Goodwill for the New York reporting unit is $654 million primarily from the purchase of RG&E by Energy East in 2002. Goodwill for the UIL reporting unit is $1,768 million from the 2015 acquisition of UIL. We perform our annual impairment testing in the fourth quarter, as of October 1. Our qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events and events affecting a reporting unit. Our quantitative assessment utilizes a discounted cash flow model under the income approach and includes critical assumptions, primarily the discount rate and internal estimates of forecasted cash flows. We use a discount rate that is developed using market participant assumptions, which consider the risk and nature of the respective reporting unit’s cash flows and the rates of return market participants would require in order to invest their capital in our reporting units. We test the reasonableness of the conclusions of our quantitative impairment testing using a range of discount rates and a range of assumptions for long-term cash flows. For 2023, we utilized a qualitative assessment for the Networks reporting units and a quantitative assessment for the Renewables reporting unit. We had no impairment of goodwill in 2023 and 2022 as a result of our impairment testing. Intangible Assets Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2023 and 2022: As of December 31, 2023 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 587 $ (325) $ 262 Other 48 (26) 22 Total Intangible Assets $ 635 $ (351) $ 284 As of December 31, 2022 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 590 $ (313) $ 277 Other 22 (18) 4 Total Intangible Assets $ 612 $ (331) $ 281 Wind development costs, with the exception of future ‘pipeline’ development costs, are amortized on a straight-line basis in accordance with the life of the related assets once placed in service. Amortization expense was $15 million, $14 million and $13 million for the years ended December 31, 2023, 2022 and 2021, respectively. We believe our future cash flows will support the recoverability of our intangible assets. We expect amortization expense for the five years subsequent to December 31, 2023, to be as follows: Year ending December 31, Amount (Millions) 2024 $ 15 2025 $ 14 2026 $ 14 2027 $ 13 2028 $ 12

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Property, Plant and Equipment	Property, Plant and Equipment Property, plant and equipment as of December 31, 2023, consisted of: As of December 31, 2023 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 19,729 $ 14,620 $ 34,349 Natural gas transportation, distribution and other 5,751 14 5,765 Other common operating property — 341 341 Total Property, Plant and Equipment in Service 25,480 14,975 40,455 Total accumulated depreciation (6,742) (5,737) (12,479) Total Net Property, Plant and Equipment in Service 18,738 9,238 27,976 Construction work in progress 2,902 1,979 4,881 Total Property, Plant and Equipment $ 21,640 $ 11,217 $ 32,857 Property, plant and equipment as of December 31, 2022, consisted of: As of December 31, 2022 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 18,634 $ 14,096 $ 32,730 Natural gas transportation, distribution and other 5,392 14 5,406 Other common operating property — 317 317 Total Property, Plant and Equipment in Service 24,026 14,427 38,453 Total accumulated depreciation (6,277) (5,265) (11,542) Total Net Property, Plant and Equipment in Service 17,749 9,162 26,911 Construction work in progress 2,225 1,858 4,083 Total Property, Plant and Equipment $ 19,974 $ 11,020 $ 30,994 Capitalized interest costs were $115 million, $53 million and $33 million for the years ended December 31, 2023, 2022 and 2021, respectively. Accrued liabilities for property, plant and equipment additions were $653 million, $481 million and $297 million as of December 31, 2023, 2022 and 2021, respectively. We impaired or wrote off amounts of $6 million, $11 million and $20 million for the years ended December 31, 2023, 2022 and 2021, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction. Depreciation expense for the years ended December 31, 2023, 2022 and 2021, amounted to $1,143 million, $1,071 million and $1,001 million, respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Asset Retirement Obligations AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities. The reconciliation of ARO carrying amounts for the years ended December 31, 2023 and 2022 consisted of: (Millions) As of December 31, 2021 $ 253 Liabilities settled during the year (1) Liabilities incurred during the year 13 Accretion expense 14 Revisions in estimated cash flows (a) (6) As of December 31, 2022 $ 273 Liabilities settled during the year (1) Liabilities incurred during the year 12 Accretion expense 15 Revisions in estimated cash flows (a) 7 As of December 31, 2023 $ 306 (a) Represents an increase (decrease) in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities. Several of the wind generation facilities have restricted cash for purposes of settling AROs. As of both December 31, 2023 and 2022, restricted cash related to AROs was $3 million. These amounts have been included in “Other Assets” on our consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in our consolidated statements of income. We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains.

Debt

Debt	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Debt	Debt Long-term debt as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2025-2053 $ 3,316 1.85%-8.00% $ 2,882 1.85%-8.00% Unsecured pollution control notes - fixed 2024-2034 545 1.40%-4.00% 545 1.40%-4.00% Intragroup Green Loan 2033 800 5.45% — Other various non-current debt - fixed 2024-2052 5,988 1.95%-6.66% 5,276 1.95%-6.66% Unamortized debt issuance costs and discount (53) (76) Total Debt including with affiliate 10,596 8,627 Less: debt due within one year, included in current liabilities 612 412 Total Non-current Debt including with affiliate $ 9,984 $ 8,215 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $8,906 million. 2023 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity NYSEG 7/3/2023 Tax Exempt Bond $ 100 4.00% 2034 UI 10/2/2023 Tax Exempt Bond $ 64 4.50% 2033 NYSEG 8/8/2023 Green 144A Bond $ 350 5.65% 2028 NYSEG 8/8/2023 Green 144A Bond $ 400 5.85% 2033 RG&E 12/13/2023 Green Private Bond $ 100 5.62% 2028 RG&E 12/13/2023 Green Private Bond $ 25 5.89% 2034 RG&E 12/13/2023 Green Private Bond $ 50 5.99% 2036 RG&E 12/13/2023 Green Private Bond $ 75 6.22% 2053 CMP 12/13/2023 Green Private Bond $ 55 5.65% 2029 CMP 12/13/2023 Green Private Bond $ 70 6.04% 2038 UI 12/13/2023 Green Private Bond $ 156 6.09% 2034 UI 12/13/2023 Green Private Bond $ 34 6.29% 2038 CNG 12/13/2023 Private Bond $ 36 6.20% 2032 CNG 12/13/2023 Private Bond $ 19 6.49% 2038 SCG 12/13/2023 Private Bond $ 30 6.04% 2034 SCG 12/13/2023 Private Bond $ 30 6.24% 2038 Corporate 7/19/2023 Intragroup Green Loan $ 800 5.45% 2033 Long-term debt maturities, including sinking fund obligations, due over the next five years consist of: 2024 2025 2026 2027 2028 Total (Millions) $ 612 $ 1,107 $ 660 $ 484 $ 716 $ 3,579 We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were in breach of covenants or of any obligation that could trigger the early redemption of our debt as of both December 31, 2023 and 2022 and throughout 2023 and 2022. Fair Value of Debt As of December 31, 2023 and 2022, the estimated fair value of long-term debt, including the Intragroup Green Loan, was $10,266 million and $7,991 million, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy. 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). Short-term Debt Avangrid had $1,347 million and $566 million of notes payable as of December 31, 2023 and 2022, respectively. Avangrid has a commercial paper program with a limit of $2 billion which is backstopped by the Avangrid credit facilities described below. As of December 31, 2023 and 2022, the amount of notes payable under the commercial paper program was $1,332 million and $397 million, respectively, presented net of discounts on the balance shee t. As of December 31, 2023, the weighted-average interest rate on outstanding commercial paper was 5.65%. 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 and remove provisions related to the extension of credit to the Public Service Company of New Mexico and Texas-New Mexico Power Company. As of both December 31, 2023 and 2022, we had no borrowings outstanding under this credit facility. Since the Avangrid credit facility is also a backstop to the Avangrid commercial paper program, the total amount available under the facility as of December 31, 2023 was $2,233 million. 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 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 both December 31, 2023 and 2022, there was no outstanding amount under this credit facility. Supplier Financing Arrangements We operate a supplier financing arrangement. During 2021, we arranged for the extension of payment terms with some suppliers, which could elect to be paid by a financial institution earlier than maturity under supplier financing arrangements. Due to the interest cost associated with these arrangements, the balances are classified as " Notes payable December 31, 2023 and 2022, the amount of notes payable under supplier financing arrangements was $0 and $171 million, respectively. For the year ended December 31, 2023, $4 million of invoices were confirmed and $175 million of confirmed invoices were paid under the program. As of December 31, 2022, the weighted average interest rate on the balance was 5.48%.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and non-current equity investments associated with Networks’ activities utilizing market approach valuation techniques: • Our equity and other investments consist of Rabbi Trusts. Our Rabbi Trusts, which cover certain deferred compensation plans and non-qualified pension plan obligations, consist 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. • UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 12 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as New York Mercantile Exchange (NYMEX) futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include 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 12 for further discussion of interest rate contracts). We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value. Restricted cash was $3 million as of both December 31, 2023 and 2022, respectively and is included in “Other Assets” on our consolidated balance sheets. The financial instruments measured at fair value as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other 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) As of December 31, 2022 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 35 $ 13 $ — $ — $ 48 Derivative assets Derivative financial instruments - power $ 37 $ 55 $ 165 $ (177) $ 80 Derivative financial instruments - gas 1 47 — (45) 3 Contracts for differences — — 1 — 1 Derivative financial instruments – Other — 116 — — 116 Total $ 38 $ 218 $ 166 $ (222) $ 200 Derivative liabilities Derivative financial instruments - power $ (46) $ (350) $ (93) $ 364 $ (125) Derivative financial instruments - gas (4) (26) — 30 — Contracts for differences — — (57) — (57) Derivative financial instruments – Other — (115) — — (115) Total $ (50) $ (491) $ (150) $ 394 $ (297) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2023, 2022 and 2021 consisted of: (Millions) 2023 2022 2021 Fair value as of January 1, $ 16 $ (69) $ 13 Gains for the year recognized in operating revenues 10 108 21 Losses for the year recognized in operating revenues (22) (30) (34) Total gains or losses for the period recognized in operating revenues (12) 78 (13) Gains recognized in OCI 7 2 2 Losses recognized in OCI (8) (57) (52) Total gains or losses recognized in OCI (1) (55) (50) Net change recognized in regulatory assets and liabilities 18 17 13 Purchases 90 10 (17) Settlements (87) 8 (13) Transfers out of Level 3 (a) 12 27 (2) Fair value as of December 31, $ 36 $ 16 $ (69) (Losses) 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 $ (12) $ 78 $ (13) (a) Transfers out of Level 3 were the result of increased observability of market data. Level 3 Fair Value Measurement The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2023. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.44 $ 9.86 $ 1.99 AECO ($/MMBtu) $ 3.11 $ 10.80 $ 1.00 Ameren ($/MWh) $ 53.73 $ 225.62 $ 20.92 COB ($/MWh) $ 81.30 $ 400.10 $ 10.85 ComEd ($/MWh) $ 48.92 $ 222.49 $ 16.77 ERCOT S hub ($/MWh) $ 50.77 $ 320.63 $ 16.85 Mid C ($/MWh) $ 78.47 $ 400.10 $ 7.85 AEP-DAYTON hub ($/MWh) $ 54.53 $ 229.75 $ 22.50 PJM W hub ($/MWh) $ 57.22 $ 227.60 $ 21.61 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 12 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input December 31, 2023 Risk of non-performance 0.42% - 0.52% Discount rate 3.84% - 4.01% Forward pricing ($ per KW-month) $2.00 - $2.61

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Derivative Instruments and Hedging Our operating and financing activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities The tables below present Networks' derivative positions as of December 31, 2023 and 2022, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 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) As of December 31, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 30 $ 8 $ 30 $ 7 Derivative liabilities (30) (7) (58) (50) — 1 (28) (43) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral — 1 (28) (43) Cash collateral receivable — — 11 2 Total derivatives as presented in the balance sheet $ — $ 1 $ (17) $ (41) The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.7 Natural gas purchase contracts (Dth) 10.7 9.6 Derivatives not designated as hedging instruments NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of December 31, 2023 and 2022 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2023, 2022 and 2021 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2023 Electricity Natural Gas 2023 Electricity Natural Gas Regulatory assets $ 22 $ 12 Purchased power, natural gas and fuel used $ 102 $ 15 Regulatory liabilities $ — $ — December 31, 2022 2022 Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (127) $ (16) Regulatory liabilities $ — $ — 2021 Purchased power, natural gas and fuel used $ (23) $ (11) Pursuant to a PURA order, UI and Connecticut’s other electric utility, CL&P, each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of December 31, 2023, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $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. As of December 31, 2022, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $56 million, a gross derivative liability of $57 million ($55 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2023, 2022 and 2021, respectively, were as follows: Years Ended December 31, 2023 2022 2021 (Millions) Derivative Assets $ — $ (1) $ — Derivative Liabilities $ 18 $ 18 $ 13 Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 4 $ 409 Commodity contracts — Purchased power, natural gas and fuel used — 2,429 Total $ — $ 4 2022 Interest rate contracts $ — Interest expense $ 4 $ 303 Commodity contracts 2 Purchased power, natural gas and fuel used (3) 2,456 Foreign currency exchange contracts — — Total $ 2 $ 1 2021 Interest rate contracts $ — Interest expense $ 4 $ 298 Commodity contracts 2 Purchased power, natural gas and fuel used (1) 1,719 Foreign currency exchange contracts (5) — Total $ (3) $ 3 (a) Changes in accumulated OCI are reported on a pre-tax basis. On June 20, 2019, Networks entered into a forward contract to hedge the foreign currency exchange risk of approximately $100 million in forecasted capital expenditures through June 2023. The forward foreign currency contracts, which were designated and qualified as cash flow hedges, were settled in December 2021. The net loss of $5 million in accumulated OCI on the foreign exchange derivative will be reclassified into earnings over the useful life of the underlying capital expenditures. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $39 million and $43 million as of December 31, 2023 and 2022, respectively. We recorded $4 million in net derivative losses related to discontinued cash flow hedges during each of the years ended December 31, 2023, 2022 and 2021, respectively. We will amortize approximately $4 million of discontinued cash flow hedges in 2024. (b) Renewables activities Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (MWh/Dth in Millions) Wholesale electricity purchase contracts 1 2 Wholesale electricity sales contracts 6 7 Natural gas and other fuel purchase contracts 21 15 Financial power contracts 4 6 Basis swaps - purchases 24 22 Basis swaps - sales 1 — The fair values of derivative contracts associated with Renewables' activities as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (Millions) Wholesale electricity purchase contracts $ 29 $ 149 Wholesale electricity sales contracts 14 (200) Natural gas and other fuel purchase contracts 4 2 Financial power contracts 17 8 Total $ 64 $ (41) On May 27, 2021, Renewables entered into a forward interest rate swap, with a total notional amount of $935 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As part of the financial close of Vineyard Wind 1 described in Note 22, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of December 31, 2023 and 2022, the fair value of the interest rate swap was $122 million and $116 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 December 31, 2023 and 2022, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 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) As of December 31, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 121 $ 63 $ 79 $ 4 Derivative liabilities (61) (40) (103) (7) 60 23 (24) (3) Designated as hedging instruments Derivative assets — 116 — 1 Derivative liabilities — — (168) (89) — 116 (168) (88) Total derivatives before offset of cash collateral 60 139 (192) (91) Cash collateral receivable — — 105 54 Total derivatives as presented in the balance sheet $ 60 $ 139 $ (87) $ (37) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2023, 2022 and 2021 consisted of: Year Ended December 31, 2023 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (8) $ (5) Wholesale electricity sales contracts 71 67 Financial power contracts (5) 41 Financial and natural gas contracts — 10 Total gain included in operating revenues $ 58 $ 113 $ 8,309 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (109) Financial and natural gas contracts — (41) Total loss included in purchased power, natural gas and fuel used $ — $ (150) $ 2,429 Total Gain (Loss) $ 58 $ (37) Year Ended December 31, 2022 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 9 $ 6 Wholesale electricity sales contracts 1 (63) Financial power contracts 1 (52) Financial and natural gas contracts 1 (6) Total gain (loss) included in operating revenues $ 12 $ (115) $ 7,923 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 98 Financial and natural gas contracts — 5 Total gain included in purchased power, natural gas and fuel used $ — $ 103 $ 2,456 Total Gain (Loss) $ 12 $ (12) Year Ended December 31, 2021 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ (1) Wholesale electricity sales contracts (2) (33) Financial power contracts 4 (42) Financial and natural gas contracts (1) (25) Total gain (loss) included in operating revenues $ 2 $ (101) $ 6,974 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 32 Financial and natural gas contracts — 12 Total gain included in purchased power, natural gas and fuel used $ — $ 44 $ 1,719 Total Gain (Loss) $ 2 $ (57) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ 122 Interest Expense $ — $ 409 Commodity contracts $ 17 Operating revenues $ 169 $ 8,309 Total $ 139 $ 169 2022 Interest rate contracts $ 116 Interest Expense $ — $ 303 Commodity contracts $ (178) Operating revenues $ 59 $ 7,923 $ (62) $ 59 2021 Interest rate contracts $ (58) Interest Expense $ — $ 298 Commodity contracts $ (142) Operating revenues $ (3) $ 6,974 $ (200) $ (3) (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 $41 million of loss included in accumulated OCI at December 31, 2023 is expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2023, 2022 and 2021. (c) Corporate activities Avangrid uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. The net loss in accumulated OCI related to previously settled interest rate contracts is $29 million and $38 million as of December 31, 2023 and 2022, respectively. We amortized into income $9 million of the loss related to the settled interest rate contracts for each of the years ended December 31, 2023, 2022 and 2021. We will amortize approximately $9 million of the net loss on the interest rate contracts during 2024. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 9 $ 409 2022 Interest rate contracts $ — Interest expense $ 9 $ 303 2021 Interest rate contracts $ — Interest expense $ 9 $ 298 (a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029. On July 15, 2021, Corporate entered into an interest rate swap to hedge the fair value of $750 million of existing debt included in "Non-current debt" on our consolidated balance sheets. The interest rate swap is designated and qualifies as a fair value hedge. The change in the fair value of the interest rate swap and the offsetting change in the fair value of the underlying debt are reported as components of "Interest expense." The effects on our consolidated financial statements as of and for the years ended December 31, 2023 and 2022 are as follows: Fair value of hedge Location of (Gain) Recognized in Income Statement Loss Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2023 Year Ended December 31, 2023 Current liabilities $ (26) Interest Expense $ 31 $ 409 Non-current liabilities $ (63) Cumulative effect on hedged debt Current debt $ — Non-current debt $ 89 Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2022 Year Ended December 31, 2022 Current liabilities $ (29) Interest Expense $ 6 $ 303 Non-current liabilities $ (86) Cumulative effect on hedged debt Current debt $ 29 Non-current debt $ 86 (d) Counterparty credit risk management NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold. The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit ratings on senior debt were to fall below investment grade. If such an event had occurred as of December 31, 2023, UI would have had to post an aggregate of approximately $46 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $63 million and $97 million as of December 31, 2023 and 2022, respectively. Derivative instruments settlements and collateral payments are included throughout the "Changes in operating assets and liabilities" section of operating activities in the consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of December 31, 2023 is $34 million, for which we have posted collateral.

Leases

Leases	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 50 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the years ended December 31, 2023, 2022 and 2021 were as follows: For the Year Ended December 31, 2023 2022 2021 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 11 $ 12 $ 8 Interest on lease liabilities 3 3 3 Total finance lease cost 14 15 11 Operating lease cost 18 20 14 Short-term lease cost 8 6 4 Variable lease cost 3 3 4 Total lease cost $ 43 $ 44 $ 33 Balance sheet and other information as of December 31, 2023 and 2022 was as follows: As of December 31, 2023 2022 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 195 $ 159 Operating lease liabilities, current 16 13 Operating lease liabilities, long-term 199 161 Total operating lease liabilities $ 215 $ 174 Finance Leases Other assets $ 132 $ 143 Other current liabilities 28 7 Other non-current liabilities 53 80 Total finance lease liabilities $ 81 $ 87 Weighted-average Remaining Lease Term (years) Finance leases 5.6 6.4 Operating leases 20.8 16.9 Weighted-average Discount Rate Finance leases 3.39 % 3.46 % Operating leases 4.19 % 3.69 % For the years ended December 31, 2023, 2022 and 2021 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2023 2022 2021 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16 $ 14 $ 16 Operating cash flows from finance leases $ 3 $ 1 $ 3 Financing cash flows from finance leases $ 6 $ 9 $ 6 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — $ (1) $ — Operating leases $ 55 $ 25 $ 10 As of December 31, 2023, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2024 $ 30 $ 21 2025 8 17 2026 9 17 2027 10 19 2028 19 16 Thereafter 14 257 Total lease payments 90 346 Less: imputed interest (9) (131) Total $ 81 215 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $39 million and $41 million at December 31, 2023 and December 31, 2022, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. During 2022, Renewables elected not to exercise the early buyout option and prospectively adjusted the accounting for the lease, which contains a buyout option at fair value at the end of the lease term. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.
Leases	Leases We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 50 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option. The components of lease cost for the years ended December 31, 2023, 2022 and 2021 were as follows: For the Year Ended December 31, 2023 2022 2021 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 11 $ 12 $ 8 Interest on lease liabilities 3 3 3 Total finance lease cost 14 15 11 Operating lease cost 18 20 14 Short-term lease cost 8 6 4 Variable lease cost 3 3 4 Total lease cost $ 43 $ 44 $ 33 Balance sheet and other information as of December 31, 2023 and 2022 was as follows: As of December 31, 2023 2022 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 195 $ 159 Operating lease liabilities, current 16 13 Operating lease liabilities, long-term 199 161 Total operating lease liabilities $ 215 $ 174 Finance Leases Other assets $ 132 $ 143 Other current liabilities 28 7 Other non-current liabilities 53 80 Total finance lease liabilities $ 81 $ 87 Weighted-average Remaining Lease Term (years) Finance leases 5.6 6.4 Operating leases 20.8 16.9 Weighted-average Discount Rate Finance leases 3.39 % 3.46 % Operating leases 4.19 % 3.69 % For the years ended December 31, 2023, 2022 and 2021 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2023 2022 2021 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16 $ 14 $ 16 Operating cash flows from finance leases $ 3 $ 1 $ 3 Financing cash flows from finance leases $ 6 $ 9 $ 6 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — $ (1) $ — Operating leases $ 55 $ 25 $ 10 As of December 31, 2023, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2024 $ 30 $ 21 2025 8 17 2026 9 17 2027 10 19 2028 19 16 Thereafter 14 257 Total lease payments 90 346 Less: imputed interest (9) (131) Total $ 81 215 Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $39 million and $41 million at December 31, 2023 and December 31, 2022, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. During 2022, Renewables elected not to exercise the early buyout option and prospectively adjusted the accounting for the lease, which contains a buyout option at fair value at the end of the lease term. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility. Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Commitments and Contingent Liabilities We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is probable and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC, pursuant to sections 206 and 306 of the Federal Power Act against several NETOs claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE 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 Service Invoice Dispute On May 4, 2021, Nike USA, Inc. (Nike), the buyer under a virtual PPA with a subsidiary of Renewables, provided notice that it disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations, most notably during Winter Storm Uri in February of 2021. Nike has requested an adjustment to the invoices that would increase the amount payable by approximately $31 million. Renewables has responded that the invoices have been properly calculated in accordance with the provisions of the PPA, 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. Commonwealth Wind and Park City PPAs In October 2022, Commonwealth Wind and Park City Wind announced that they would seek to re-negotiate the price of the certain Power Purchase Agreements, or PPAs, to help mitigate the impacts of inflation, increased interest rates and supply chain disruptions on the projects. On October 21, 2022, Commonwealth Wind filed a motion with the DPU seeking a one-month suspension in the DPU’s proceeding to review the power purchase agreements between Commonwealth Wind and the Massachusetts electric distribution companies, or EDCs, in order to provide an opportunity for Commonwealth Wind, the EDCs, state and regulatory officials, and other stakeholders to evaluate the current economic challenges facing Commonwealth Wind and assess measures that would return the project to economic viability including, but not limited to, certain amendments to the Power Purchase Agreements, or PPAs. In December 2022, Commonwealth Wind filed a motion opposing approval of the PPAs by the DPU and requesting that the proceeding be dismissed. On December 30, 2022, the DPU entered an order denying Commonwealth Wind’s motion and approving the PPAs. On January 30, 2023, Commonwealth Wind appealed the DPU’s December 30th order to the Supreme Judicial Court of Massachusetts. On July 13, 2023, each of the EDCs filed with the DPU a first amendment, termination agreement and release agreed with Commonwealth Wind, providing for an orderly termination of the PPAs, withdrawal of Commonwealth Wind’s appeal, and payment by Commonwealth Wind of a $48 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs in connection with the regulatory approval that is under appeal. The DPU approved the termination agreements on August 2, 2023 and Commonwealth Wind dismissed its appeal of the DPU’s December 30th order. On October 2, 2023, Park City Wind entered into a first amendment, termination agreement and release with each of the Connecticut EDCs, providing for an orderly termination of the Park City Wind PPAs and payment by Park City Wind of an approximately $16 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs. On October 13, 2023, PURA approved the termination agreements. Power, Gas and Other Arrangements Power and Gas Supply Arrangements – Networks NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and the New York Power Authority, are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation. NYSEG, RG&E, SCG, CNG, BGC and MNG (collectively, the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review. The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the U.S. Gulf of Mexico region, in the Appalachia region and in Canada. The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months. Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system. Other arrangements include contractual obligations for property, plant and equipment, material and services on order but not yet delivered at December 31, 2023. Power, Gas and Other Arrangements – Renewables Gas purchase commitments consist of firm transport capacity to fuel the Klamath Cogen and Peaking gas generators. Power purchase commitments include the following: (i) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers, (ii) a 95.6 MW (average) three-year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2022 and expiring in 2024), (iii) fixed priced energy purchases to cover firming & shaping commitments and (iv) fixed price REC purchases to supply merchant REC sales. Power sales commitments include: (i) winter capacity sale of 150 MW through 2042, (ii) fixed price, fixed volume hydro energy sales through 2024, (iii) fixed price, fixed volume power sales off the Klamath Cogen facility, (iv) a seasonal tolling arrangement off the Klamath peaking facility with fixed capacity charges through 2024, (v) fixed price, fixed volume renewable energy credit sales off merchant wind facilities, (vi) sales of merchant wind farm capacity to various ISOs and (vii) sales of ancillary services (e.g., regulation and frequency response, generator imbalance, etc.) to third parties from Renewables’ Balancing Authority. In June 2020, Renewables entered into a Payment In Lieu of Taxes (PILOT) agreement related to two of its projects with Torrance County, New Mexico. The agreement requires PILOT payments to Torrance County through 2049. The total amount of PILOT payments related to the two projects in 2023 was $1 million. Renewables also has easement contracts which are included in the table below under purchases. Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2023 consisted of: Year Purchases Sales (Millions) 2024 $ 1,513 $ 285 2025 246 161 2026 116 58 2027 83 34 2028 51 6 Thereafter 1,005 56 Totals $ 3,014 $ 600 Guarantee Commitments to Third Parties As of December 31, 2023, we had approximately $911 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 22, 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 December 31, 2023, neither we nor our subsidiaries have any liabilities recorded for these instruments. NECEC Commitments

Environmental Liabilities

Environmental Liabilities	12 Months Ended
	Dec. 31, 2023
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; 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 December 31, 2023, 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 December 31, 2023, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $122 million to $218 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 December 31, 2023, no liability was recorded related to these sites and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of both December 31, 2023 and 2022, the liability associated with our MGP sites in Connecticut was $112 million, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates. As of December 31, 2023 and 2022, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $250 million and $289 million, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 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 December 31, 2023 , FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $8 million and $6 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable. English Station On 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 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. As of both December 31, 2023 and 2022, 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 gold eagle fatalities that allegedly occurred at certain Avangrid Renewables facilities that are not covered by an eagle take permit. Avangrid Renewables has responded to the U.S. Fish and Wildlife Service providing information about the relevant eagle taking permit applications and relevant mitigation activity at each facility. We cannot predict the outcome of this preliminary inquiry.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Income Taxes	Income Taxes In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into United States law. The IRA created a new corporate alternative minimum tax (CAMT) of 15% on adjusted financial statement income and an excise tax of 1% on the value of certain stock repurchases. The IRA also contains several additional provisions related to tax incentives for investments in renewable energy production, carbon capture, and other climate actions. The CAMT and other various provisions of the IRA are effective for periods beginning after December 31, 2022. The Company paid $32 million of CAMT in 2023, comprised of an estimated $129 million of gross initial obligation; partially offset by $97 million of tax credit utilization. The Company also established an equivalent $129 million, unlimited lived gross CAMT carryforward asset which will be available in future periods to offset regular income tax that exceeds CAMT. Since early 2020, and in response to regulatory orders received in most but not all of our operating jurisdictions, we began returning to customers both protected and unprotected excess accumulated deferred income tax (ADIT) from the 2017 Tax Act. Such amounts are subject to the terms of those orders while meeting the requirements of normalization for both Average Rate Assumption Method (ARAM) and Reverse South Georgia (RSG) methodologies. Current and deferred taxes charged to expense for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, 2023 2022 2021 (Millions) Current Federal $ 36 $ — $ 6 State (1) 2 4 Current taxes charged to expense 35 2 10 Deferred Federal 62 67 49 State (8) 49 72 Deferred taxes charged to expense 54 116 121 Production tax credits (97) (97) (109) Investment tax credits (1) (1) (1) Total Income Tax (Benefit) Expense $ (9) $ 20 $ 21 The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, 2023 2022 2021 (Millions) Tax expense at federal statutory rate $ 138 $ 176 $ 140 Depreciation and amortization not normalized (27) (20) (19) Investment tax credit amortization (1) (1) (1) Tax return related adjustments (4) 2 — Production tax credits (97) (97) (109) Tax equity financing arrangements 26 13 14 State tax (benefit) expense, net of federal effect (7) 40 61 Excess ADIT amortization (35) (66) (65) Valuation allowance — (35) 21 Other, net (2) 8 (21) Total Income Tax (Benefit) Expense $ (9) $ 20 $ 21 Deferred tax assets and liabilities as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,650 $ 4,504 Unfunded future income taxes 141 129 Federal and state tax credits (986) (942) Federal and state NOL’s (1,308) (1,086) Joint ventures/partnerships 244 210 Nontaxable grant revenue (250) (270) Tax Act - tax on regulatory remeasurement (317) (328) Valuation allowance 82 87 Other 180 (91) Deferred Income Tax Liabilities $ 2,436 $ 2,213 Deferred tax assets $ 2,861 $ 2,717 Deferred tax liabilities 5,297 4,930 Net Accumulated Deferred Income Tax Liabilities $ 2,436 $ 2,213 As of December 31, 2023, we had gross federal tax net operating losses of $4.7 billion, federal PTCs and ITCs, R&D and other federal credits of $948 million, state tax effected net operating losses of $401 million in several jurisdictions and miscellaneous state tax credits of $145 million available to carry forward and reduce future income tax liabilities. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2024. The more significant state net operating losses begin to expire in 2024. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. The valuation allowance for deferred tax assets as of December 31, 2023 and 2022 was $82 million and $87 million, respectively. The $5 million decrease is related to state net operating losses and tax credit carryforwards. The $82 million balance as of December 31, 2023 includes federal net operating loss and tax credit carryforward valuation allowance of $3 million and state net operating loss and state tax credit carryforward valuation allowance of $79 million. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2023, 2022 and 2021 consisted of: Years ended December 31, 2023 2022 2021 (Millions) Beginning Balance $ 127 $ 127 $ 127 Increases for tax positions related to prior years 7 2 3 Increases for tax positions related to current year — 2 — Decreases for tax positions related to prior years (4) (4) (3) Ending Balance $ 130 $ 127 $ 127 Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information. Accruals for interest and penalties on tax reserves were immaterial for the years ended December 31, 2023, 2022 and 2021. If recognized, $109 million of the total gross unrecognized tax benefits would affect the effective tax rate. Within the next twelve months, Avangrid could resolve $83 million of various state uncertainties under appeal, of which, the entire amount if recognized, would reduce the effective tax rate. An estimated range of impact to Avangrid’s earnings related to uncertain tax benefit changes in the next twelve months cannot be made. Avangrid and its subsidiaries, without ARHI, have been audited for the federal tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. Tax years 2010 and forward are open for potential federal adjustments. All New York state returns, which were filed without ARHI, are closed through 2011 and Maine state returns are closed through 2015. All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. All New York combined state returns are closed for adjustment through 2011. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period. As of December 31, 2023, UIL is subject to audit of its federal tax return for years 2014 through its short period 2015. UIL's short period ending in 2015 is open and subject to Connecticut audit. In 2023, Avangrid executed an agreement to transfer the production tax credits generated in 2023 pursuant to the transferability provisions of the Inflation Reduction Act of 2022. Avangrid received cash of $81 million for the transfer of tax credits for the year ended December 31, 2023.

Post-Retirement and Similar Obl

Post-Retirement and Similar Obligations	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Post-Retirement and Similar Obligations	Post-Retirement and Similar Obligations Avangrid and its subsidiaries sponsor a number of retirement benefit plans. The plans include qualified defined benefit pension plans, supplemental non-qualified pension plans, defined contribution plans and other postretirement benefit plans for eligible employees and retirees. Eligibility and benefits vary depending on each plan's design. For example, certain benefits are based on years of service and final average compensation while others may use a cash balance formula that calculates benefits using a percentage of annual compensation. Qualified Retirement Benefit Plans As of December 31, 2023 and 2022, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2023 2022 2023 2022 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 2,452 $ 3,487 $ 284 $ 408 Service cost 6 27 1 2 Interest cost 121 111 14 10 Plan amendments — 1 — — Actuarial loss (gain) 131 (716) 36 (103) Curtailments/Settlements (2) (274) — — Benefits paid (208) (184) (34) (33) Benefit Obligation as of December 31, 2,500 2,452 301 284 Change in plan assets Fair Value of Plan Assets as of January 1, 2,151 3,079 89 127 Actual return on plan assets 204 (584) 12 (22) Employer contributions 14 22 16 17 Settlements (2) (182) — — Benefits paid (208) (184) (34) (33) Fair Value of Plan Assets as of December 31, 2,159 2,151 83 89 Funded Status as of December 31, $ (341) $ (301) $ (218) $ (195) During 2023, the pension and postretirement benefit obligations had actuarial losses of, respectively, $131 million and $36 million, primarily due to losses from discount rate decreases of $112 million and $12 million, respectively. During 2022, the pension and postretirement benefit obligations had actuarial gains of, respectively, $716 million and $103 million, primarily due to gains from discount rate increases of $644 million and $70 million, respectively. The pension benefit obligation had a reduction of $274 million from settlements ($182 million) and curtailments ($92 million). The settlements were lump-sum payments made within the pension plan guidelines at the discretion of the plan participants who opted to retire. The curtailments were driven by a Company decision to freeze pension benefit accruals and contribution credits for Networks non-union employees and transition their retirement benefits to a 401(k) plan. As of December 31, 2023 and 2022, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2023 2022 2023 2022 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (341) (301) (213) (190) Total $ (341) $ (301) $ (218) $ (195) We have determined that Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans. Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2023 and 2022 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2023 2022 2023 2022 (Millions) Net loss (gain) $ 251 $ 181 $ (52) $ (91) Prior service cost (credit) $ 6 $ 7 $ (1) $ (1) Amounts recognized in OCI for ARHI for the years ended December 31, 2023 and 2022, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2023 2022 2023 2022 (Millions) Net loss (gain) $ 11 $ 12 $ (4) $ (6) As of December 31, 2023 and 2022, the projected benefit obligation (PBO) and accumulated benefit obligation (ABO) exceeded the fair value of pension plan assets for all qualified plans. The aggregate PBO and ABO and the fair value of plan assets for our underfunded qualified plans consisted of: PBO in excess of plan assets As of December 31, 2023 2022 (Millions) Projected benefit obligation $ 2,500 $ 2,452 Fair value of plan assets $ 2,159 $ 2,151 ABO in excess of plan assets As of December 31, 2023 2022 (Millions) Accumulated benefit obligation $ 2,479 $ 2,429 Fair value of plan assets $ 2,159 $ 2,151 As of December 31, 2023 and 2022, the accumulated postretirement benefits obligation for all qualified plans exceeded the fair value of plan assets. Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2023, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2023 2022 2021 2023 2022 2021 (Millions) Net Periodic Benefit Cost: Service cost $ 5 $ 26 $ 39 $ 1 $ 2 $ 3 Interest cost 119 109 86 14 10 10 Expected return on plan assets (143) (162) (199) (5) (6) (7) Amortization of prior service cost (benefit) 1 1 2 — (1) (5) Amortization of net loss 3 49 115 (12) (4) 2 Settlement charge — 17 6 — — — Curtailment charge — (32) — — — — Net Periodic Benefit Cost (15) 8 49 (2) 1 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments — (59) — — — — Settlement charge — (17) (6) — — — Net loss (gain) 73 33 (218) 26 (75) (31) Amortization of net loss (3) (49) (115) 12 4 (2) Current year prior service cost (credit) — 1 2 — — 1 Amortization of prior service (cost) benefit (1) (1) (2) — 1 5 Total Other Changes 69 (92) (339) 38 (70) (27) Total Recognized $ 54 $ (84) $ (290) $ 36 $ (69) $ (24) Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2023, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2023 2022 2021 2023 2022 2021 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ 1 $ — $ — $ — Interest cost 2 2 1 — — — Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) — 1 2 (1) (1) (1) Settlement/Curtailment charge 1 1 1 — — — Net Periodic Benefit Cost 2 3 3 (1) (1) (1) Other Changes in plan assets and benefit obligations recognized in OCI: Settlement charge (1) (1) (1) (1) (1) (1) Net loss (gain) — (1) (3) 1 (1) 1 Amortization of net (loss) gain — (1) (2) 1 1 1 Amortization of prior service cost — — — — — — Total Other Changes (1) (3) (6) 1 (1) 1 Total Recognized $ 1 $ — $ (3) $ — $ (2) $ — The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the service cost component in other operating expenses net of capitalized portion and include the components of net periodic benefit cost other than the service cost component in other expense. The weighted-average assumptions used to determine our benefit obligations as of December 31, 2023 and 2022 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2023 2022 2023 2022 Discount rate 4.69 % 5.18 % 4.66 % 5.12 % Rate of compensation increase 2.60 % 2.99 % 3.00 % 3.00 % Interest crediting rate 3.37 % 2.87 % N/A N/A The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit obligations. The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2023, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2023 2022 2021 2023 2022 2021 Discount rate 5.18 % 2.85 % 2.34 % 5.12 % 2.66 % 2.19 % Expected long-term return on plan assets 6.35 % 6.33 % 7.30 % 5.61 % 4.66 % 4.05 % Rate of compensation increase 2.99 % 3.53 % 3.52 % 3.00 % 3.50 % 3.50 % We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 Health care cost trend rate assumed for next year 6.20%/8.60% 5.00%/6.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) 4.50% 4.50% Year that the rate reaches the ultimate trend rate 2032 / 2028 2029 / 2025 Contributions We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. We expect to contribute $28 million and $8 million, respectively, to our pension and other postretirement benefit plans during 2024. Estimated Future Benefit Payments Expected benefit payments as of December 31, 2023 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2024 $ 235 $ 28 $ — 2025 $ 221 $ 28 $ — 2026 $ 216 $ 27 $ — 2027 $ 210 $ 26 $ — 2028 $ 204 $ 25 $ — 2029 - 2033 $ 918 $ 109 $ 2 Non-Qualified Retirement Benefit Plans We also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for these plans, which is included in Other current and Other non-current liabilities on our consolidated balance sheets, was $41 million and $44 million at December 31, 2023 and 2022, respectively. Plan Assets Our pension plan assets are consolidated in one master trust. A consolidated master trust provides for a uniform investment manager lineup and an efficient, cost effective means of allocating income and expenses to each plan. Our primary investment objective is to have a diversified asset allocation policy that mitigates risk and volatility while meeting or exceeding our projected expected return to ensure that current and future benefit obligations are adequately funded. Further diversification and risk mitigation is achieved within each asset class by avoiding significant concentrations in certain markets, utilizing a combination or passive and active investment managers with unique skill and expertise, a systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income and alternative investment markets. Networks and ARHI have established target asset allocation policies with allowable ranges for their pension plan assets within broad categories of asset classes made up of Return-Seeking investments and Liability-Hedging/Fixed Income investments. In 2020, a streamlined investment policy was implemented, which aligned target allocations to the estimated funded status of each specific plan. Return-Seeking assets range from 15%-70% and Liability-Hedging assets range from 30%-85%. Return-Seeking assets include investments in domestic, international and emerging equity, real estate, global asset allocation strategies and hedge funds. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair values of pension plan assets, by asset category, as of December 31, 2023, consisted of: As of December 31, 2023 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 63 $ — $ 63 $ — U.S. government securities 295 295 — — Common stocks 58 58 — — Registered investment companies 106 106 — — Corporate bonds 746 — 746 — Common collective trusts 708 — 708 — Other, principally annuity, fixed income 6 — 6 — $ 1,982 $ 459 $ 1,523 $ — Other investments measured at net asset value 177 Total $ 2,159 The fair values of pension plan assets, by asset category, as of December 31, 2022, consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 51 $ — $ 51 $ — U.S. government securities 252 252 — — Common stocks 57 57 — — Registered investment companies 104 104 — — Corporate bonds 708 — 708 — Preferred stocks 1 1 — — Common collective trusts 472 — 472 — Other, principally annuity, fixed income 33 — 33 — $ 1,678 $ 414 $ 1,264 $ — Other investments measured at net asset value 473 Total $ 2,151 Valuation Techniques We value our pension plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • U.S. government securities – at the closing price reported in the active market in which the security is traded. • Common stocks – at the closing price reported in the active market in which the individual investment is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Preferred stocks – at the closing price reported in the active market in which the individual investment is traded. • Common collective trusts/Registered investment companies – Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2: the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Our postretirement plan assets are consolidated with one trustee in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements. The assets are invested in various asset classes to achieve sufficient diversification and mitigate risk. This is achieved for our VEBA assets by utilizing multiple institutional mutual and money market funds, which provide exposure to different segments of the securities markets. The 401(h) assets are invested alongside the Pension assets they are tied to and share the same asset allocation policy. Approximately 62% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes. In 2020, a streamlined investment policy was implemented for Networks and ARHI that aligned target allocations. Equities range from 49%-69% and Fixed Income assets range from 31-51%. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed Income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. We primarily minimize the risk of large losses through diversification, but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews. Systematic rebalancing within target ranges increases the probability of increasing the projected expected return, while mitigating risk, should any asset categories drift outside their specified ranges. The fair values of other postretirement plan assets, by asset category, as of December 31, 2023 consisted of: As of December 31, 2023 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 2 $ — $ 2 $ — U.S. government securities 1 1 — — Common stocks 1 1 — — Registered investment companies 61 61 — — Corporate bonds 3 — 3 — Common collective trusts 5 — 5 — Other, principally annuity, fixed income 8 — 8 — $ 81 $ 63 $ 18 $ — Other investments measured at net asset value 2 Total $ 83 The fair values of other postretirement plan assets, by asset category, as of December 31, 2022 consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 2 $ — $ 2 $ — U.S. government securities 1 1 — — Registered investment companies 69 69 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 8 — 8 — $ 87 $ 70 $ 17 $ — Other investments measured at net asset value 2 Total $ 89 Valuation Techniques We value our postretirement plan assets as follows: • Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. • U.S. government securities – at the closing price reported in the active market in which the security is traded. • Common stocks and registered investment companies – at the closing price reported in the active market in which the individual investment is traded. • Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings. • Common collective trusts – the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market. • Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings. • Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2023 and 2022. Defined contribution plans We also have defined contribution plans, defined as 401(k)s, for all eligible Avangrid employees. There are various match formulas depending on years of service, age and pension plan closure/freeze date. For the years ended December 31, 2023, 2022 and 2021, the annual contributions we made to these plans was $84 million, $68 million and $58 million, respectively.

Equity

Equity	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Equity	Equity As of December 31, 2023 and 2022, we had 103,889 and 108,188 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2023 and 2022, we issued 138,030 and 56,127 shares of common stock, respectively, and released 4,299 and 4,355 shares of common stock held in trust, respectively, each having a par value of $0.01. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of Avangrid, shares of common stock of Avangrid. The purpose of the stock repurchase program is to allow Avangrid to maintain Iberdrola's relative ownership percentage of approximately 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2023, there were no repurchases pursuant to the stock repurchase program. As of December 31, 2023, a total of 997,983 shares have been repurchased in the open market, all of which are included as Avangrid treasury shares. As of December 31, 2023, the total cost of all repurchases, including commissions, was $47 million. Accumulated OCI (Loss) Accumulated OCI (Loss) for the years ended December 31, 2023, 2022 and 2021 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2020 2021 Change As of December 31, 2021 2022 Change As of December 31, 2022 2023 Change As of December 31, 2023 (Millions) Loss (gain) for defined benefit plans, net of income tax expense of $0 for 2021, $3 for 2022 and $0 for 2023 $ 2 $ 14 $ — Amortization of pension cost, net of income tax (benefit) expense of $(1) for 2021, $1 for 2022 and $0 for 2023 (8) 4 (1) Net gain (loss) on pension plans $ (32) $ (6) $ (38) $ 18 $ (20) $ (1) $ (21) Unrealized (loss) gain from equity method investment, net of income tax (benefit) expense of $(3) for 2021, $6 for 2022 and $1 for 2023 (a) $ — $ (9) $ (9) $ 22 $ 13 $ 5 $ 18 Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax (benefit) expense of $(44) for 2021, $0 for 2022 and $6 for 2023 (35) (159) (194) (1) (195) 17 (178) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense of $(3) for 2021, $19 for 2022 and $48 for 2023 (b) (44) 12 (32) 54 22 134 156 Loss on derivatives qualifying as cash flow hedges (79) (147) (226) 53 (173) 151 (22) Accumulated Other Comprehensive Loss $ (111) $ (162) $ (273) $ 93 $ (180) $ 155 $ (25) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share is computed by dividing net income attributable to Avangrid by the weighted-average number of shares of our common stock outstanding. During the years ended December 31, 2023 and 2021, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations for the years ended December 31, 2023 and 2021. The dilutive securities, which consist of performance and restricted units, did result in a change in our earnings per share calculation for the year ended December 31, 2022. The calculations of basic and diluted earnings per share attributable to Avangrid for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of: Years Ended December 31, 2023 2022 2021 (Millions, except for number of shares and per share data) Numerator: Net income attributable to Avangrid $ 786 $ 881 $ 707 Denominator: Weighted average number of shares outstanding - basic 386,810,088 386,727,246 358,086,621 Weighted average number of shares outstanding - diluted 387,164,874 387,215,785 358,578,608 Earnings per share attributable to Avangrid Earnings Per Common Share, Basic $ 2.03 $ 2.28 $ 1.97 Earnings Per Common Share, Diluted $ 2.03 $ 2.27 $ 1.97

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2023
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	Variable Interest Entities We participate in certain partnership arrangements that qualify as 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. On September 9, 2021, we sold an additional TEF interest in Aeolus Wind Power VII, LLC (Aeolus VII) for $131 million. The $8 million difference between the amount received and the $139 million noncontrolling interest recognized was recorded as an adjustment to equity because there was no change in control as a result of the transaction. On November 4, 2021, we sold a TEF interest in Aeolus Wind Power VIII, LLC (Aeolus VIII) for $199 million, of which $8 million was held in escrow until certain conditions were met on August 10, 2022. The two wind farms are the first in a portfolio of companies called Aeolus Wind Power VIII, LLC (Aeolus VIII). On April 29, 2022, we closed on one TEF agreement, receiving $14 million from a tax equity investor related to one solar facility. The solar facility is the first in a portfolio of companies called Solis Solar Power I, LLC (Solis). On June 15, 2022, we closed on one TEF agreement related with Aeolus VIII, receiving the initial funding of $109 million from one tax equity investor. Two newly constructed facilities, one wind farm and one solar facility, became part of Aeolus VIII. On March 31, 2023, we received the second funding of $61 million related to Solis I from one tax equity investor. On November 21, 2023, we received the second funding of $124 million related to Aeolus VIII from one tax equity investor. As of December 31, 2023, the assets and liabilities of the VIEs totaled approximately $2,741 million and $174 million, respectively. As of December 31, 2022, the assets and liabilities of VIEs totaled approximately $2,853 million and $424 million, respectively. At both December 31, 2023 and 2022, 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. Our El Cabo, Patriot, Aeolus VII, Aeolus VIII, and Solis I interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests. See Note 22 - Equity Method Investments for information on our VIEs we do not consolidate.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Grants, Government Incentives and Deferred Income	Grants, Government Incentives and Deferred Income The changes in government grants recorded in deferred income as of December 31, 2023 and 2022 consisted of: (Millions) Government grants - Renewables Other deferred income Total As of December 31, 2021 $ 1,125 $ 5 $ 1,130 Disposals — — — Recognized in income (65) (3) (68) As of December 31, 2022 1,060 2 1,062 Disposals — — — Recognized in income (65) (1) (66) As of December 31, 2023 $ 995 $ 1 $ 996 Within deferred income, we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States Department of Treasury (DOT) provided eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the book to tax basis differences related to the property for income tax purposes within the nontaxable grant revenue deferred income tax liabilities (see Note 16 – Income Taxes). The changes in government grants recorded as a reduction to the related utility plant as of December 31, 2023 and 2022 consisted of: (Millions) Government grants - Networks Total As of December 31, 2021 $ 63 $ 63 Disposals — — Recognized in income (4) (4) As of December 31, 2022 59 59 Disposals — — Recognized in income (5) (5) As of December 31, 2023 $ 54 $ 54 We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grant’s terms and conditions, we are required to repay the grant funds to the government. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2023 and 2022.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2023
Equity Method Investments and Joint Ventures [Abstract]
Equity Method Investment	Equity Method Investments Renewables holds 15% ownership interest in a wind farm located in South Dakota (Tatanka). The investment in Tatanka is accounted for as an equity investment. As of December 31, 2023, and 2022, the carrying value of our Tatanka investment was $22 million and $23 million, respectively. Renewables holds 50% ownership interest in a wind farm and a solar project located in Arizona (Poseidon). The investment in Poseidon is accounted for as an equity investment. As of December 31, 2023 and 2022, the carrying value of our Poseidon investment was $77 million and $87 million, respectively. Renewables holds 20% interest in Coyote Ridge Wind, LLC (Coyote Ridge). The investment in Coyote Ridge is accounted for as an equity investment. As of December 31, 2023 and 2022, the carrying amount of our Coyote Ridge investment was $16 million and $15 million, respectively. Renewables has two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC (Flat Rock I) and the Flat Rock Wind Power II LLC (Flat Rock II) wind farms located in upstate New York. Flat Rock I has a 231 MW capacity and Flat Rock II has a 91 MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. As of December 31, 2023 and 2022, the carrying amount of Flat Rock I was $81 million and $90 million, respectively, and Flat Rock II was $38 million and $42 million, respectively. 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. Consequently, Renewables recognized a pretax gain of $246 million and an after tax gain of $181 million, driven by the increase in the fair value of its acquired interest in the leases and related development activities over its carrying value. The gain is classified in Earnings from equity method investments in the condensed consolidated statement of income for the year ended December 31, 2022. Concurrently with the closing on the construction financing for the Vineyard Wind 1 project, Renewables entered into a credit agreement with certain banks to provide future term loans and letters of credit up to a maximum of approximately $1.2 billion to finance a portion of its share of the cost of Vineyard Wind 1 at the maturity of the Vineyard Wind 1 project construction loan. Any term loans mature by October 15, 2031, subject to certain extension provisions. Renewables also entered into an Equity Contribution Agreement in which Renewables agreed to, among other things, make certain equity contributions to fund certain costs of developing and constructing the Vineyard Wind 1 project in accordance with the credit agreement. In addition, we issued a guaranty up to $827 million for Renewables' equity contributions under the Equity Contribution Agreement. As part of the Vineyard Wind 1 financial close, $152 million of Renewables prior contributions for the Vineyard Wind 1 project were returned in 2021. 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. As of December 31, 2023, Vineyard Wind 1 received the initial funding of $85 million from tax equity investors. 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 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 2023, Renewables made a capital contribution of $287 million to Vineyard Wind 1. As of December 31, 2023 and 2022, the carrying amount of Renewables' investments in Vineyard Wind, which was dissolved in 2022, and Vineyard Wind 1 was $297 million and $9 million, respectively. Networks is a party to a 50-50 joint venture with Clearway Energy, Inc. in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is accounted for as an equity investment. As of December 31, 2023 and 2022, the carrying value of our GenConn investment was $90 million and $94 million, respectively. Networks holds an approximate 20% ownership interest in New York TransCo. Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. On April 8, 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The selected project, New York Energy Solution (NYES), replaces nearly 80-year old transmission assets located in the upper to mid-Hudson Valley with streamlined, modernized technology, to enable surplus clean energy resources in upstate New York and help achieve the State’s energy goals. The total project cost is $600 million plus interconnection costs. New York Transco is subject to regulatory approval of its rates, terms and conditions with the FERC. The investment in New York TransCo is accounted for as an equity investment. As of December 31, 2023 and 2022, the carrying value of our New York TransCo investment was $97 million and $77 million, respectively. None of our joint ventures have any contingent liabilities or capital commitments, except for those disclosed above. Distributions received from equity method investments, excluding the return of capital as part of the Vineyard Wind 1 financial close disclosed above, amounted to $37 million, $41 million and $21 million for the years ended December 31, 2023, 2022 and 2021 respectively, which are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively. In addition, during the years ended December 31, 2023, 2022 and 2021, we received $11 million, $12 million and $11 million of distributions in RECs from our equity method investments. As of December 31, 2023, there was $9 million of undistributed earnings from our equity method investments. Capitalized interest costs related to equity method investments were $2 million, $0 and $6 million for the years ended December 31, 2023, 2022 and 2021, respectively.

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Other Financial Statement Items	Other Financial Statement Items Other income (expense) Other income (expense) for the years ended December 31, 2023, 2022 and 2021 consisted of: Years ended December 31, 2023 2022 2021 (Millions) Allowance for funds used during construction 82 63 88 Carrying costs on regulatory assets 17 16 17 Non-service component of net periodic benefit cost 22 (58) (37) Other 8 9 (8) Total Other Income $ 129 $ 30 $ 60 Accounts receivable and unbilled revenues, net Accounts receivable and unbilled revenues, net as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Trade receivables and unbilled revenues $ 1,749 $ 1,892 Allowance for credit losses (161) (155) Total Accounts receivable and unbilled revenues, net $ 1,588 $ 1,737 The change in the allowance for credit losses as of December 31, 2023 and 2022 consisted of: (Millions) As of December 31, 2020 $ 108 Current period provision 110 Write-off as uncollectible (67) As of December 31, 2021 $ 151 Current period provision 110 Write-off as uncollectible (106) As of December 31, 2022 $ 155 Current period provision 137 Write-off as uncollectible (131) As of December 31, 2023 $ 161 DPA receivable balances were $110 million and $102 million as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, our allowance for credit losses for DPAs was $44 million and $42 million, respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Prepaid other taxes $ 142 $ 136 Broker margin and collateral accounts 165 164 Other pledged deposits 32 12 Prepaid expenses 74 68 Other 16 6 Total $ 429 $ 386 Other current liabilities Other current liabilities as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Advances received $ 236 $ 271 Accrued salaries 184 153 Short-term environmental provisions 40 54 Collateral deposits received 128 68 Pension and other postretirement 6 5 Finance leases 28 7 Other 40 35 Total $ 662 $ 593 Disposition On May 13, 2021, Renewables sold 100% of its ownership interest in two solar projects located in Nevada to Primergy Hot Pot Holdings LLC for total consideration of $35 million and recognized a gain of $11 million, net of tax. The pre-tax gain of $15 million is recorded in "Operating revenues" in our consolidated statements of income. The total consideration includes variable consideration that Renewables could receive based on the achievement of certain regulatory and project development milestones. The transaction was accounted for as an asset sale.

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Segment Information	Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how Avangrid manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments, costs incurred in connection with the COVID-19 pandemic, costs incurred related to the PNMR Merger and other transactions, accelerated depreciation from the repowering of wind farms, and costs incurred in connection with an offshore contract provision. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. Segment information as of and for the year ended December 31, 2023 consisted of: For the Year Ended December 31, 2023 Networks Renewables Other(a) Avangrid Consolidated (Millions) Revenue - external $ 6,850 $ 1,456 $ 3 $ 8,309 Revenue - intersegment 5 — (5) — Depreciation and amortization 694 456 8 1,158 Operating income 996 (45) (21) 930 Earnings (losses) from equity method investments 15 (9) — 6 Interest expense, net of capitalization 287 16 106 409 Income tax expense (benefit) 141 (67) (83) (9) Capital expenditures 2,192 768 12 2,972 Adjusted net income 727 163 (82) 808 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. Segment information as of and for the year ended December 31, 2022 consisted of: For the year ended December 31, 2022 Networks Renewables Other(a) Avangrid Consolidated (Millions) Revenue - external $ 6,781 $ 1,141 $ 1 $ 7,923 Revenue - intersegment 1 — (1) — Depreciation and amortization 660 424 1 1,085 Operating income 901 (36) (13) 852 Earnings (losses) from equity method investments 11 251 — 262 Interest expense, net of capitalization 220 16 67 303 Income tax expense (benefit) 94 (114) 40 20 Capital expenditures 1,803 708 8 2,519 Adjusted net income 628 403 (130) 901 As of December 31, 2022 Property, plant and equipment 20,027 10,950 17 30,994 Equity method investments 171 266 — 437 Total assets $ 28,069 $ 13,553 $ (499) $ 41,123 (a) Includes Corporate and intersegment eliminations. Segment information for the year ended December 31, 2021 consisted of: For the year ended December 31, 2021 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 5,753 $ 1,220 $ 1 $ 6,974 Revenue - intersegment 1 — (1) — Depreciation and amortization 616 397 1 1,014 Operating income 876 26 (7) 895 Earnings (losses) from equity method investments 12 (5) — 7 Interest expense, net of capitalization 217 1 80 298 Income tax expense (benefit) 98 (48) (29) 21 Capital expenditures 2,294 680 2 2,976 Adjusted net income $ 661 $ 170 $ (51) $ 780 (a) Includes Corporate and intersegment eliminations. Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the years ended December 31, 2023, 2022 and 2021 is as follows: Years Ended December 31, 2023 2022 2021 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 808 $ 901 $ 780 Adjustments: Mark-to-market adjustments - Renewables (1) 21 — (53) Impact of COVID-19 (2) — — (34) Merger and other transaction costs (3) (11) (4) (12) Offshore contract provision (4) (40) (24) — Accelerated depreciation from repowering (5) (1) — — Income tax impact of adjustments 8 7 26 Net Income Attributable to Avangrid, Inc. $ 786 $ 881 $ 707 (1) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (2) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (3) Pre-merger and other transaction costs incurred. (4) Costs incurred in connection with an offshore contract provision. (5) Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of: Years Ended December 31, 2023 2022 2021 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ 2 $ (45) $ 1 $ (46) $ — $ (52) Iberdrola Renovables Energia, S.L. $ — $ (8) $ 1 $ (5) $ — $ (10) Iberdrola Financiación, S.A.U. $ — $ (36) $ — $ (12) $ — $ (9) Vineyard Wind 1 $ 12 $ — $ 7 $ — $ 14 $ — Iberdrola Solutions $ — $ — $ — $ — $ 7 $ (39) Other $ — $ (2) $ 1 $ (3) $ 2 $ (3) Related party balances as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 1 $ — $ 1 $ (29) Iberdrola Renovables Energía, S.L. $ 4 $ — $ — $ — Iberdrola Financiación, S.A.U. $ — $ (799) $ — $ (9) Vineyard Wind 1 $ 6 $ (8) $ 3 $ (8) Iberdrola Solutions $ — $ (6) $ — $ (2) Other $ 4 $ — $ 4 $ (1) Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of Avangrid, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 10 for a discussion of the Iberdrola Intragroup Green Loan. Avangrid optimizes its liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of Avangrid and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both December 31, 2023 and 2022 was $0. On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and 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 both December 31, 2023 and 2022, there was no outstanding amount under this credit facility. We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balances of $6 million and $2 million as of December 31, 2023 and 2022, respectively. See Note 22 - Equity Method Investments for more information on transactions with our equity method investees. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Stock-Based Compensation	Stock-Based Compensation The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares). As of December 31, 2023, the total number of shares authorized for stock-based compensation plans was 2,500,000. Performance Stock Units In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes. In March 2022, 46,737 shares of common stock were issued to settle the third and final installment payment under this plan. During 2021 and 2022, 1,336,787 PSUs and 215,235 PSUs, were granted to certain officers and employees of Avangrid with achievement measured based on certain performance and market-based metrics for the 2022 performance period. The PSUs are payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.22 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of Avangrid and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date. The expense is recognized on a straight-line basis over the requisite service period of approximately four years based on expected achievement. 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 first installment was paid in June 2023, and 125,657 shares of common stock were issued in July 2023 to settle this installment payment. During 2023, 1,067,500 PSUs were granted to certain executives of Avangrid with achievement measured based on certain performance and market-based metrics for the 2023 to 2025 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2026, 2027 and 2028. The fair value of the PSUs on the grant date was $25.69 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of Avangrid and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date. The expense is recognized on a straight-line basis over the requisite service period of approximately five years based on expected achievement. Restricted Stock Units In October 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan 8,000 restricted stock units (RSUs) were granted to an officer of Avangrid. The RSUs vested in full in one installment in December 2020. The fair value on the grant date was determined based on a price of $47.59 per share. In March 2021, this RSU grant was settled, net of applicable taxes, by issuing 5,953 shares of common stock. In August 2020, 5,000 RSUs were granted to an officer of Avangrid. The RSUs vest in three equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with Avangrid through the applicable vesting dates. The fair value on the grant date was determined based on a price of $48.99 per share. In February 2021, the first installment of the RSU grant was settled by issuing 1,697 shares of common stock. In October 2021, this RSU grant was cancelled and the remaining unvested RSUs were forfeited. In March 2021, 5,000 RSUs were granted to an officer of Avangrid. The RSUs vest in full in one installment in March 2023, provided that the grantee remains continuously employed with Avangrid through the applicable vesting date. The fair value on the grant date was determined based on a price of $48.83 per share. The RSU grant was settled in March 2023, net of applicable taxes, by issuing 3,642 shares of common stock. In June 2021, 17,500 RSUs were granted to an officer of Avangrid with immediate vesting. The fair value on the grant date was determined based on a price of $53.59 per share. The RSU grant was settled, net of applicable taxes, by issuing 9,390 shares of common stock. In January 2022, 17,500 RSUs were granted to an officer of Avangrid with immediate vesting. The fair value on the grant date was determined based on a price of $48.16 per share. The RSU grant was settled, net of applicable taxes, by issuing 9,390 shares of common stock. In June 2022, 25,000 RSUs were granted to an officer of Avangrid. The RSUs vest in two equal installments in 2023 and 2024, provided that the grantee remains continuously employed with Avangrid through the applicable vesting dates. The fair value on the grant date was determined based on a price of $47.64 per share. The first installment of this RSU grant was settled in January 2023, net of applicable taxes, by issuing 8,690 shares of common stock. The second 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 March 2020, 167,060 Phantom Shares were granted to certain Avangrid executives and employees. These awards will vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In March 2022, $2 million was paid to settle the third and final installment under this plan. In February 2022, 9,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in 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 August 2022, $0.1 million was paid to settle the first installment, and in February and August 2023, in total $0.2 million was paid to settle the second and third installments under this plan. In February 2023, 81,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in three equal installments in 2024, 2025 and 2026 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. As of December 31, 2023 and 2022, the total liability for phantom share units was $2 million and $0, respectively, which is included in other current and non-current liabilities. The total stock-based compensation expense, which is included in "Operations and maintenance" of our consolidated statements of income for the years ended December 31, 2023, 2022 and 2021 was $14 million, $15 million and $18 million, respectively. The total income tax benefits recognized for stock-based compensation arrangements for each of the years ended December 31, 2023, 2022 and 2021, were $4 million, $4 million and $5 million, respectively. A summary of the status of the Avangrid's nonvested PSUs and RSUs as of December 31, 2023, and changes during the fiscal year ended December 31, 2023, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2022 1,084,951 $ 36.55 Granted 1,068,326 $ 29.30 Forfeited (449,876) $ 35.30 Vested (244,110) $ 37.43 Nonvested Balance – December 31, 2023 1,459,291 $ 31.54 As of December 31, 2023, total unrecognized costs for non-vested PSUs, RSUs and Phantom Shares was $27 million. The weighted-average period over which the PSU, RSU and Phantom Shares costs will be recognized is approximately 5.2 years. The weighted-average grant date fair value of PSUs and RSUs granted during the year was $29.30 per share for the year ended December 31, 2023.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2023
Subsequent Events [Abstract]
Subsequent Events	Subsequent Events On February 15, 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 April 1, 2024 to shareholders of record at the close of business on March 1, 2024.

CONDENSED FINANCIAL INFORMATION

CONDENSED FINANCIAL INFORMATION OF PARENT	12 Months Ended
	Dec. 31, 2023
Condensed Financial Information Disclosure [Abstract]
CONDENSED FINANCIAL INFORMATION OF PARENT	Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF INCOME FOR THE YEARS ENDED December 31, 2023, 2022 AND 2021 Years Ended December 31, 2023 2022 2021 (Millions) Operating Revenues $ — $ — $ — Operating Expenses Operating expense 9 11 19 Taxes other than income taxes 7 (1) (11) Total Operating Expenses 16 10 8 Operating (Loss) Income (16) (10) (8) Other Income Other income 127 49 22 Equity earnings of subsidiaries 837 999 756 Interest expense (248) (117) (93) Income Before Income Tax 700 921 677 Income tax (benefit) expense (86) 40 (30) Net Income $ 786 $ 881 $ 707 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF COMPREHENSIVE INCOME FOR THE YEARS ENDED December 31, 2023, 2022, AND 2021 Years Ended December 31, 2023 2022 2021 (Millions) Net Income $ 786 $ 881 $ 707 Other comprehensive income (loss) of subsidiaries 155 93 (162) Comprehensive Income $ 941 $ 974 $ 545 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT BALANCE SHEETS AS OF December 31, 2023 AND 2022 As of December 31, 2023 2022 (Millions) Assets Current Assets Cash and cash equivalents $ 11 $ 28 Accounts receivable from subsidiaries 416 190 Notes receivable from subsidiaries 1,912 1,440 Prepayments and other current assets 47 17 Total current assets 2,386 1,675 Investments in subsidiaries 22,244 20,588 Other assets Deferred income taxes 452 358 Other 3 3 Total other assets 455 361 Total Assets $ 25,085 $ 22,624 Liabilities Current Liabilities Current portion of debt $ 600 $ — Notes payable 1,331 396 Notes payable to subsidiaries 977 557 Accounts payable and accrued liabilities 1 7 Accounts payable to subsidiaries 2 3 Interest accrued 9 9 Interest accrued subsidiaries 48 9 Dividends payable 170 170 Other current liabilities 30 30 Total current liabilities 3,168 1,181 Derivative liabilities 63 86 Non-current debt 1,406 1,977 Non-current debt with affiliate 800 — Total non-current liabilities 2,269 2,063 Total Liabilities 5,437 3,244 Equity Stockholders' Equity: Common stock 4 3 Additional paid-in capital 17,701 17,694 Treasury stock (47) (47) Retained earnings 2,015 1,910 Accumulated other comprehensive loss (25) (180) Total Equity 19,648 19,380 Total Liabilities and Equity $ 25,085 $ 22,624 See accompanying notes to Schedule I. Schedule I –Financial Statements of Parent AVANGRID, INC. (PARENT) CONDENSED FINANCIAL INFORMATION OF PARENT STATEMENTS OF CASH FLOWS FOR THE YEARS ENDED December 31, 2023, 2022, AND 2021 Years Ended December 31, 2023 2022 2021 (Millions) Net Cash used in Operating Activities $ (298) $ (742) $ (397) Cash Flow from Investing Activities Notes receivable from subsidiaries (116) (14) 130 Investments in subsidiaries (1,263) (1,020) (1,026) Return of capital from investments in subsidiaries 595 664 1,122 Other investments — — 300 Net Cash (used in) provided by Investing Activities (784) (370) 526 Cash Flow from Financing Activities Receipts (repayments) of short-term notes payable from subsidiaries, net 14 1 (186) Receipts (repayments) of short-term notes payable 935 397 (309) Proceeds (repayments) from non-current debt with affiliate 800 — (3,000) Repurchase of common stock — — (33) Issuance of common stock (3) (1) 3,998 Dividends paid (681) (681) (613) Net Cash provided by (used in) Financing Activities 1,065 (284) (143) Net Decrease in Cash and Cash Equivalents (17) (1,396) (14) Cash and Cash Equivalents, Beginning of Year 28 1,424 1,438 Cash and Cash Equivalents, End of Year $ 11 $ 28 $ 1,424 Supplemental Cash Flow Information Cash paid for interest $ 181 $ 86 $ 74 Cash paid (refunded) payment for income taxes $ 21 $ (33) $ (15) See accompanying notes to Schedule I. Avangrid, Inc. (Avangrid) is a holding company and we conduct substantially all of our business through our subsidiaries. Substantially all of our consolidated assets are held by our subsidiaries. Accordingly, our cash flow and ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the distribution or other payment of their earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. Our condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. Our condensed financial statements should be read in conjunction with the consolidated financial statements and notes thereto of Avangrid and subsidiaries (Avangrid Group). Avangrid indirectly or directly owns all of the ownership interests of our significant subsidiaries. Avangrid relies on dividends or loans from our subsidiaries to fund dividends to our primary shareholder. Avangrid’s significant accounting policies are consistent with those of the Avangrid Group. For the purposes of these condensed financial statements, Avangrid’s wholly owned and majority owned subsidiaries are recorded based upon our proportionate share of the subsidiaries net assets. Avangrid files a consolidated federal income tax return that includes the taxable income or loss of all our subsidiaries. Each subsidiary company is treated as a member of the consolidated group and determines its current and deferred taxes separately and settles its current tax liability or benefit each year directly with Avangrid pursuant to a tax sharing agreement between Avangrid and our members. Termination of a Material Definitive Agreement On December 31, 2023, Avangrid sent a notice to PNM Resources, Inc., a New Mexico corporation (PNMR), terminating the previously announced Agreement and Plan of Merger (as amended by the Amendment to Merger Agreement dated January 3, 2022, Amendment No. 2 to the Merger Agreement dated April 12, 2023 and Amendment No. 3 to the Merger Agreement dated June 19, 2023 (Merger Agreement)), pursuant to which NM Green Holdings, Inc. a New Mexico corporation and wholly-owned subsidiary of the corporation (Merger Sub), agreed to merge with and into PNMR (Merger), with PNMR surviving the Merger as a direct wholly-owned subsidiary of Avangrid. A description of the Merger Agreement was included in the Current Reports on Form 8-K filed by Avangrid on October 21, 2020, January 3, 2022, April 12, 2023 and June 20, 2023, and is incorporated herein by reference. The Merger was conditioned, among other things, upon the receipt of certain required regulatory approvals, including the approval of the New Mexico Public Regulation Commission (NMPRC), and provided that the Merger Agreement may be terminated by either Avangrid or PNMR if the closing of the Merger shall not have occurred by 5:00 PM New York City Time on December 31, 2023 (End Date). Because the required approval of the NMPRC was not received by the End Date and the conditions to the closing of the Merger were thus not satisfied by the End Date, Avangrid exercised its right to terminate the Merger Agreement. No termination penalties were incurred by either party in connection with the termination of the Merger Agreement. The Funding Commitment Letter and related side letter agreement terminated automatically upon termination of the Merger Agreement. In light of the termination of the Merger Agreement, on January 8, 2024, Avangrid filed a motion to withdraw from the appeal it and PNMR’s subsidiary, Public Service Company of New Mexico (PNM), had filed with the New Mexico Supreme Court with respect to the NMPRC’s December 8, 2021, order which had rejected the amended stipulated agreement entered into by PNM, Avangrid and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application. As of December 31, 2023, Avangrid share capital consisted of 500,000,000 shares of common stock authorized, 387,872,787 shares issued and 386,770,915 shares outstanding, 81.6% of which are owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $4 million and additional paid in capital of $17,701 million. As of December 31, 2022, Avangrid share capital consisted of 500,000,000 shares of common stock authorized, 387,734,757 shares issued and 386,628,586 shares outstanding, 81.6% of which were owned by Iberdrola, each having a par value of $ $0.01, for a total value of common stock capital of $3 million and additional paid in of $17,694 million. As of December 31, 2023 and 2022, we had 103,889 and 108,188 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2023 and 2022, we issued 138,030 and 56,127 shares of common stock, respectively, and released 4,299 and 4,355 shares of common stock held in trust, respectively, each having a par value of $0.01. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of Avangrid, shares of common stock of Avangrid. The purpose of the stock repurchase program is to allow Avangrid to maintain Iberdrola's target relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2023, there were no repurchases pursuant to the stock repurchase program. As of December 31, 2023, a total of 997,983 shares have been repurchased in the open market, all of which are included as Avangrid treasury shares. As of December 31, 2023, the total cost of all repurchases, including commissions, was $47 million. On February 15, 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 April 1, 2024 to shareholders of record at the close of business on March 1, 2024. In 2017, Avangrid issued $600 million aggregate principal amount of its 3.15% notes maturing in 2024. On May 16, 2019, Avangrid issued $750 million aggregate principal amount of its 3.80% notes maturing in 2029. Proceeds of the offering were used to finance and/or refinance, in whole or in part, one or more eligible renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $743 million. On April 9, 2020, Avangrid issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%. Net proceeds of the offering after the price discount and issuance-related expenses were $744 million. On December 14, 2020, Avangrid and Iberdrola entered into an intra-group loan agreement which provided Avangrid with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid in 2021 with the proceeds of the common share issuance in two private placements. On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan). Cash dividends paid by subsidiary are as follows: Years ended December 31, 2023 2022 2021 (millions) Avangrid Networks $ 595 $ 645 $ 970 Avangrid Renewables $ — $ 19 $ 152 For the years ended December 31, 2023, 2022 and 2021, Avangrid made capital contributions to Networks of $931 million, $986 million and $1,011 million, respectively. During 2023 and 2022, Avangrid recorded a net non-cash contribution and dividend of $122 million and $473 million, respectively, to and from its subsidiaries to zero out their account balances of notes receivable and payable.

Pay vs Performance Disclosure

Pay vs Performance Disclosure - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pay vs Performance Disclosure
Net Income (Loss)	$ 786	$ 881	$ 707

Insider Trading Arrangements

Insider Trading Arrangements	3 Months Ended
	Dec. 31, 2023
Trading Arrangements, by Individual
Rule 10b5-1 Arrangement Adopted	false
Non-Rule 10b5-1 Arrangement Adopted	false
Rule 10b5-1 Arrangement Terminated	false
Non-Rule 10b5-1 Arrangement Terminated	false

Summary of Significant Accoun_2

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Policies)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Principles of consolidation	Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting.
Revenue recognition	Revenue recognitionWe recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of 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 24. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO) or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms (RDMs), other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all or a percentage of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. There are no 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 Costs, Contract Liabilities and Practical Expedient We have contract assets for costs from development success fees, which we paid during a solar farm asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in April 2024 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2023 and 2022, and are presented in "Other non-current assets" on our consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $18 million and $33 million at December 31, 2023 and 2022, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $45 million, $33 million and $22 million as revenue related to contract liabilities for the years ended December 31, 2023, 2022 and 2021, respectively. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.
Regulatory accounting	Regulatory accounting We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets primarily represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
Business combinations and assets acquisitions (disposals)	Business combinations and assets acquisitions (disposals) We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred. In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed.
Noncontrolling interests	Noncontrolling interests Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement.
Equity method investments	Equity method investments We account for joint ventures and other equity investments that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from equity method investments as a reduction in the carrying amount of the investment and not as dividend income. When an equity method investee executes derivative transactions that have cash flow hedge accounting treatment, we recognize our share of the OCI in our consolidated balance sheet. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary.
Goodwill and other intangible assets	Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four
Property, plant and equipment	Property, plant and equipment We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment. We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service. We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation. We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations Structural components 25-40 Rotary components 25-30 Solar power stations 30 Transmission and transport facilities 10-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 10-85 Computer software 1-25 Other Buildings 10-75 Operations offices 4-70 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation was 2.8% of average depreciable property for both 2023 and 2022. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income.
Leases	Leases We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets" and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets" and liabilities in "Other current liabilities" and "Other liabilities." ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on the information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes an option to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans, such as actual amounts paid. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability. We have lease agreements with lease and non-lease components, and account for lease components and associated non-lease components together as a single lease component, for all classes of underlying assets.
Impairment of long-lived assets	Impairment of long-lived assets We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. For the Renewables segment, the property, plant and equipment are grouped on a market hub-basis where we have interdependent revenues. Renewables development projects (e.g., prior to reaching the commercial operation date) are analyzed for impairment at a project level. The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset.
Fair value measurement	Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: • Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. • Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. • Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair value.
Equity investments with readily determinable fair values	Equity investments with readily determinable fair values We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.
Derivatives and hedge accounting	Derivatives and hedge accounting Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met. Certain derivatives that hedge specific cash flows that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. Certain interest rate derivatives that hedge a liability (i.e. debt) that qualify and are designated for hedge accounting are classified as fair value hedges. Changes in the fair value of interest rate derivatives designated as a fair value hedge and the offsetting changes in the fair value of the underlying hedged exposure (i.e. debt) are recorded in Interest expense. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI. Renewables classifies certain contracts for the purchase and sale of both gas and electricity as derivatives, in accordance with the applicable accounting standards. Renewables may also have gains or losses from certain contracts, that are not designated as cash flow hedges, including those entered into for proprietary trading purposes, which it generally classifies as derivative revenue. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.
Cash and cash equivalents	Cash and cash equivalents Cash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows.
Trade receivables and unbilled revenues, net of allowance for credit losses	Trade receivables and unbilled revenues, net of allowance for credit losses We record trade receivables at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain trade receivables and payables related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services and energy management are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets. Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. As required by their state regulatory commissions, the affected utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. We consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts.
Variable interest entities	Variable interest entities An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20). We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors.
Debentures, bonds and bank borrowings	Debentures, bonds and bank borrowings We record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets.
Inventory	Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.” We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.” In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.”
Government grants and Deferred income	Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses. (t ) Deferred income Apart from government grants, we occasionally receive payments from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such payments on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.
Asset retirement obligations	Asset retirement obligations We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. We record AROs for the decommissioning of the wind and solar farms and thermal facilities. Projected removal costs are based on engineering estimates which are updated on an annual basis based on the relevant inflation and discount rate factors. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations.
Environmental remediation liability	Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis.
Post-employment and other employee benefits	Post-employment and other employee benefits We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. If a plan meets settlement or curtailment criteria, we recognize a regulatory asset or liability if these costs are probable of recovery from ratepayers. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period.
Income taxes	Income taxes We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established regulatory assets and liabilities for the net revenue requirements to be recovered from or refunded to customers for the related future tax expense or benefit associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. We consider the effect of the corporate alternative minimum tax system in determining the need for a valuation allowance for deferred taxes. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets. We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Our policy is to recognize interest and penalties related to unrecognized tax benefits within “Interest expense, net of capitalization” in our consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Federal production tax credits (PTCs) applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in deferred income tax expense with a corresponding reduction in deferred income tax liabilities. Subsequent sales of PTCs under transferability rules are currently recognized with an offset to deferred taxes, with any difference between the sale price and the carrying value of the PTC adjusted to deferred income tax expense. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.
Stock-based compensation	Stock-based compensationStock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier.
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued But Not Yet Adopted	Adoption of New Accounting Pronouncements (a) 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. We adopted the new disclosure requirements pursuant to this guidance on January 1, 2024. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements not yet adopted that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) 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.
Use of Estimates and Assumptions	Use of Estimates and Assumptions The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for credit losses and unbilled revenues; (2) asset impairments, including goodwill and projects under development; (3) investments in equity instruments; (4) depreciable lives of assets; (5) income tax valuation allowances; (6) uncertain tax positions; (7) reserves for professional, workers’ compensation and comprehensive general insurance liability risks; (8) contingency and litigation reserves; (9) fair value measurements; (10) earnings sharing mechanisms; (11) environmental remediation liabilities; (12) AROs; (13) pension and other postretirement employee benefits and (14) noncontrolling interest balances derived from HLBV (hypothetical liquidation at book value) accounting. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates we use in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates.
Union collective bargaining agreements	Union collective bargaining agreements

Summary of Significant Accoun_3

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2023
Accounting Policies [Abstract]
Schedule of Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations Structural components 25-40 Rotary components 25-30 Solar power stations 30 Transmission and transport facilities 10-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 10-85 Computer software 1-25 Other Buildings 10-75 Operations offices 4-70 Property, plant and equipment as of December 31, 2023, consisted of: As of December 31, 2023 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 19,729 $ 14,620 $ 34,349 Natural gas transportation, distribution and other 5,751 14 5,765 Other common operating property — 341 341 Total Property, Plant and Equipment in Service 25,480 14,975 40,455 Total accumulated depreciation (6,742) (5,737) (12,479) Total Net Property, Plant and Equipment in Service 18,738 9,238 27,976 Construction work in progress 2,902 1,979 4,881 Total Property, Plant and Equipment $ 21,640 $ 11,217 $ 32,857 Property, plant and equipment as of December 31, 2022, consisted of: As of December 31, 2022 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 18,634 $ 14,096 $ 32,730 Natural gas transportation, distribution and other 5,392 14 5,406 Other common operating property — 317 317 Total Property, Plant and Equipment in Service 24,026 14,427 38,453 Total accumulated depreciation (6,277) (5,265) (11,542) Total Net Property, Plant and Equipment in Service 17,749 9,162 26,911 Construction work in progress 2,225 1,858 4,083 Total Property, Plant and Equipment $ 19,974 $ 11,020 $ 30,994

Revenue (Tables)

Revenue (Tables)	12 Months Ended
	Dec. 31, 2023
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2023, 2022 and 2021 are as follows: Year Ended December 31, 2023 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,962 $ — $ — $ 4,962 Regulated operations – natural gas 1,617 — — 1,617 Nonregulated operations – wind — 817 — 817 Nonregulated operations – solar — 46 — 46 Nonregulated operations – thermal — 180 — 180 Other (a) 76 (52) (2) 22 Revenue from contracts with customers 6,655 991 (2) 7,644 Leasing revenue 9 — — 9 Derivative revenue — 450 — 450 Alternative revenue programs 137 — — 137 Other revenue 54 15 — 69 Total operating revenues $ 6,855 $ 1,456 $ (2) $ 8,309 Year Ended December 31, 2022 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,610 $ — $ — $ 4,610 Regulated operations – natural gas 1,931 — — 1,931 Nonregulated operations – wind — 947 — 947 Nonregulated operations – solar — 36 — 36 Nonregulated operations – thermal — 96 — 96 Other (a) 117 48 — 165 Revenue from contracts with customers 6,658 1,127 — 7,785 Leasing revenue 8 — — 8 Derivative revenue — 4 — 4 Alternative revenue programs 68 — — 68 Other revenue 48 10 — 58 Total operating revenues $ 6,782 $ 1,141 $ — $ 7,923 Year Ended December 31, 2021 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 4,015 $ — $ — $ 4,015 Regulated operations – natural gas 1,516 — — 1,516 Nonregulated operations – wind — 1,028 — 1028 Nonregulated operations – solar — 20 — 20 Nonregulated operations – thermal — 63 — 63 Other (a) 67 84 — 151 Revenue from contracts with customers 5,598 1,195 — 6,793 Leasing revenue 7 — — 7 Derivative revenue — 3 — 3 Alternative revenue programs 115 — — 115 Other revenue 34 22 — 56 Total operating revenues $ 5,754 $ 1,220 $ — $ 6,974 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations	As of December 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of December 31, 2023 2024 2025 2026 2027 2028 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ — $ — $ — $ — $ — $ 1 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 69 67 34 13 1 2 186 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 89 28 10 7 5 54 193 Total operating revenues $ 159 $ 95 $ 44 $ 20 $ 6 $ 56 $ 380

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Regulated Operations [Abstract]
Schedule of Regulatory Assets	Regulatory assets as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Pension and other post-retirement benefits $ 445 $ 365 Pension and other post-retirement benefits cost deferrals 58 93 Storm costs 868 671 Rate adjustment mechanism 24 41 Revenue decoupling mechanism 86 52 Contracts for differences 38 56 Hardship programs 23 33 Deferred purchased gas 16 56 Environmental remediation costs 240 248 Debt premium 58 64 Unamortized losses on reacquired debt 17 19 Unfunded future income taxes 578 492 Federal tax depreciation normalization adjustment 130 137 Asset retirement obligation 19 20 Deferred meter replacement costs 59 55 COVID-19 cost recovery and late payment surcharge 12 17 Low income arrears forgiveness 55 31 Excess generation service charge 52 24 System Expansion 22 21 Non-bypassable charge 103 14 Hedges losses 34 13 Rate change levelization 60 — Value of distributed energy resources 49 36 Uncollectible reserve 104 — New York make-whole provision 96 — Other 283 210 Total regulatory assets 3,529 2,768 Less: current portion 718 447 Total non-current regulatory assets $ 2,811 $ 2,321
Schedule of Regulatory Liabilities	Regulatory liabilities as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Energy efficiency portfolio standard $ 15 $ 30 Gas supply charge and deferred natural gas cost 8 15 Pension and other post-retirement benefits cost deferrals 89 117 Carrying costs on deferred income tax bonus depreciation 3 9 Carrying costs on deferred income tax - Mixed Services 263(a) 2 3 2017 Tax Act 1,190 1,232 Accrued removal obligations 1,139 1,178 Positive benefit adjustment 9 16 Deferred property tax 21 17 Net plant reconciliation 23 11 Debt rate reconciliation 18 32 Rate refund – FERC ROE proceeding 39 36 Transmission congestion contracts 26 31 Merger-related rate credits 8 10 Accumulated deferred investment tax credits 21 22 Asset retirement obligation 19 18 Middletown/Norwalk local transmission network service collections 16 17 Non-firm margin sharing credits 34 27 Non by-passable charges 9 76 Transmission revenue reconciliation mechanism 57 75 Other 209 297 Total regulatory liabilities 2,955 3,269 Less: current portion 261 354 Total non-current regulatory liabilities $ 2,694 $ 2,915

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2023
Goodwill and Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Networks $ 2,747 $ 2,747 Renewables 372 372 Total $ 3,119 $ 3,119
Schedule of Intangible Assets Acquired and Developed	Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2023 and 2022: As of December 31, 2023 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 587 $ (325) $ 262 Other 48 (26) 22 Total Intangible Assets $ 635 $ (351) $ 284 As of December 31, 2022 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 590 $ (313) $ 277 Other 22 (18) 4 Total Intangible Assets $ 612 $ (331) $ 281
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2023, to be as follows: Year ending December 31, Amount (Millions) 2024 $ 15 2025 $ 14 2026 $ 14 2027 $ 13 2028 $ 12

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2023
Property, Plant and Equipment [Abstract]
Schedule of Property, Plant and Equipment	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Plant Combined cycle plants 35-75 Hydroelectric power stations 45-90 Wind power stations Structural components 25-40 Rotary components 25-30 Solar power stations 30 Transmission and transport facilities 10-80 Distribution facilities 4-80 Equipment Conventional meters and measuring devices 10-85 Computer software 1-25 Other Buildings 10-75 Operations offices 4-70 Property, plant and equipment as of December 31, 2023, consisted of: As of December 31, 2023 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 19,729 $ 14,620 $ 34,349 Natural gas transportation, distribution and other 5,751 14 5,765 Other common operating property — 341 341 Total Property, Plant and Equipment in Service 25,480 14,975 40,455 Total accumulated depreciation (6,742) (5,737) (12,479) Total Net Property, Plant and Equipment in Service 18,738 9,238 27,976 Construction work in progress 2,902 1,979 4,881 Total Property, Plant and Equipment $ 21,640 $ 11,217 $ 32,857 Property, plant and equipment as of December 31, 2022, consisted of: As of December 31, 2022 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 18,634 $ 14,096 $ 32,730 Natural gas transportation, distribution and other 5,392 14 5,406 Other common operating property — 317 317 Total Property, Plant and Equipment in Service 24,026 14,427 38,453 Total accumulated depreciation (6,277) (5,265) (11,542) Total Net Property, Plant and Equipment in Service 17,749 9,162 26,911 Construction work in progress 2,225 1,858 4,083 Total Property, Plant and Equipment $ 19,974 $ 11,020 $ 30,994

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
Asset Retirement Obligation Disclosure [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2023 and 2022 consisted of: (Millions) As of December 31, 2021 $ 253 Liabilities settled during the year (1) Liabilities incurred during the year 13 Accretion expense 14 Revisions in estimated cash flows (a) (6) As of December 31, 2022 $ 273 Liabilities settled during the year (1) Liabilities incurred during the year 12 Accretion expense 15 Revisions in estimated cash flows (a) 7 As of December 31, 2023 $ 306 (a) Represents an increase (decrease) in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities.

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2023
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long-term debt as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 Maturity Dates Balances Interest Rates Balances Interest Rates (Millions) First mortgage bonds - fixed (a) 2025-2053 $ 3,316 1.85%-8.00% $ 2,882 1.85%-8.00% Unsecured pollution control notes - fixed 2024-2034 545 1.40%-4.00% 545 1.40%-4.00% Intragroup Green Loan 2033 800 5.45% — Other various non-current debt - fixed 2024-2052 5,988 1.95%-6.66% 5,276 1.95%-6.66% Unamortized debt issuance costs and discount (53) (76) Total Debt including with affiliate 10,596 8,627 Less: debt due within one year, included in current liabilities 612 412 Total Non-current Debt including with affiliate $ 9,984 $ 8,215 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $8,906 million. 2023 Long-Term Debt Issuances Company Issue Date Type Amount (Millions) Interest rate Maturity NYSEG 7/3/2023 Tax Exempt Bond $ 100 4.00% 2034 UI 10/2/2023 Tax Exempt Bond $ 64 4.50% 2033 NYSEG 8/8/2023 Green 144A Bond $ 350 5.65% 2028 NYSEG 8/8/2023 Green 144A Bond $ 400 5.85% 2033 RG&E 12/13/2023 Green Private Bond $ 100 5.62% 2028 RG&E 12/13/2023 Green Private Bond $ 25 5.89% 2034 RG&E 12/13/2023 Green Private Bond $ 50 5.99% 2036 RG&E 12/13/2023 Green Private Bond $ 75 6.22% 2053 CMP 12/13/2023 Green Private Bond $ 55 5.65% 2029 CMP 12/13/2023 Green Private Bond $ 70 6.04% 2038 UI 12/13/2023 Green Private Bond $ 156 6.09% 2034 UI 12/13/2023 Green Private Bond $ 34 6.29% 2038 CNG 12/13/2023 Private Bond $ 36 6.20% 2032 CNG 12/13/2023 Private Bond $ 19 6.49% 2038 SCG 12/13/2023 Private Bond $ 30 6.04% 2034 SCG 12/13/2023 Private Bond $ 30 6.24% 2038 Corporate 7/19/2023 Intragroup Green Loan $ 800 5.45% 2033
Schedule of Maturities and Repayments of Long-term Debt	Long-term debt maturities, including sinking fund obligations, due over the next five years consist of: 2024 2025 2026 2027 2028 Total (Millions) $ 612 $ 1,107 $ 660 $ 484 $ 716 $ 3,579

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2023
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other 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) As of December 31, 2022 Level 1 Level 2 Level 3 Netting Total (Millions) Equity and other investments with readily determinable fair values $ 35 $ 13 $ — $ — $ 48 Derivative assets Derivative financial instruments - power $ 37 $ 55 $ 165 $ (177) $ 80 Derivative financial instruments - gas 1 47 — (45) 3 Contracts for differences — — 1 — 1 Derivative financial instruments – Other — 116 — — 116 Total $ 38 $ 218 $ 166 $ (222) $ 200 Derivative liabilities Derivative financial instruments - power $ (46) $ (350) $ (93) $ 364 $ (125) Derivative financial instruments - gas (4) (26) — 30 — Contracts for differences — — (57) — (57) Derivative financial instruments – Other — (115) — — (115) Total $ (50) $ (491) $ (150) $ 394 $ (297)
Schedule of Reconciliation of Changes in Fair Value Based on Level 3 Inputs	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2023, 2022 and 2021 consisted of: (Millions) 2023 2022 2021 Fair value as of January 1, $ 16 $ (69) $ 13 Gains for the year recognized in operating revenues 10 108 21 Losses for the year recognized in operating revenues (22) (30) (34) Total gains or losses for the period recognized in operating revenues (12) 78 (13) Gains recognized in OCI 7 2 2 Losses recognized in OCI (8) (57) (52) Total gains or losses recognized in OCI (1) (55) (50) Net change recognized in regulatory assets and liabilities 18 17 13 Purchases 90 10 (17) Settlements (87) 8 (13) Transfers out of Level 3 (a) 12 27 (2) Fair value as of December 31, $ 36 $ 16 $ (69) (Losses) 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 $ (12) $ 78 $ (13) (a) Transfers out of Level 3 were the result of increased observability of market data.
Schedule of Level 3 Fair Value Measurement	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2023. Index Avg. Max. Min. NYMEX ($/MMBtu) $ 4.44 $ 9.86 $ 1.99 AECO ($/MMBtu) $ 3.11 $ 10.80 $ 1.00 Ameren ($/MWh) $ 53.73 $ 225.62 $ 20.92 COB ($/MWh) $ 81.30 $ 400.10 $ 10.85 ComEd ($/MWh) $ 48.92 $ 222.49 $ 16.77 ERCOT S hub ($/MWh) $ 50.77 $ 320.63 $ 16.85 Mid C ($/MWh) $ 78.47 $ 400.10 $ 7.85 AEP-DAYTON hub ($/MWh) $ 54.53 $ 229.75 $ 22.50 PJM W hub ($/MWh) $ 57.22 $ 227.60 $ 21.61 Range at Unobservable Input December 31, 2023 Risk of non-performance 0.42% - 0.52% Discount rate 3.84% - 4.01% Forward pricing ($ per KW-month) $2.00 - $2.61

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2023
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Consolidated Balance Sheet and Amounts	The tables below present Networks' derivative positions as of December 31, 2023 and 2022, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets: As of December 31, 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) As of December 31, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 30 $ 8 $ 30 $ 7 Derivative liabilities (30) (7) (58) (50) — 1 (28) (43) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral — 1 (28) (43) Cash collateral receivable — — 11 2 Total derivatives as presented in the balance sheet $ — $ 1 $ (17) $ (41) The tables below present Renewables' derivative positions as of December 31, 2023 and 2022, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets: As of December 31, 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) As of December 31, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 121 $ 63 $ 79 $ 4 Derivative liabilities (61) (40) (103) (7) 60 23 (24) (3) Designated as hedging instruments Derivative assets — 116 — 1 Derivative liabilities — — (168) (89) — 116 (168) (88) Total derivatives before offset of cash collateral 60 139 (192) (91) Cash collateral receivable — — 105 54 Total derivatives as presented in the balance sheet $ 60 $ 139 $ (87) $ (37)
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 5.7 Natural gas purchase contracts (Dth) 10.7 9.6 The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (MWh/Dth in Millions) Wholesale electricity purchase contracts 1 2 Wholesale electricity sales contracts 6 7 Natural gas and other fuel purchase contracts 21 15 Financial power contracts 4 6 Basis swaps - purchases 24 22 Basis swaps - sales 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 December 31, 2023 and 2022 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2023, 2022 and 2021 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of For the Year Ended December 31, December 31, 2023 Electricity Natural Gas 2023 Electricity Natural Gas Regulatory assets $ 22 $ 12 Purchased power, natural gas and fuel used $ 102 $ 15 Regulatory liabilities $ — $ — December 31, 2022 2022 Regulatory assets $ 9 $ 4 Purchased power, natural gas and fuel used $ (127) $ (16) Regulatory liabilities $ — $ — 2021 Purchased power, natural gas and fuel used $ (23) $ (11) The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2023, 2022 and 2021, respectively, were as follows: Years Ended December 31, 2023 2022 2021 (Millions) Derivative Assets $ — $ (1) $ — Derivative Liabilities $ 18 $ 18 $ 13
Schedule of Derivative Instruments, Gain (Loss)	The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 4 $ 409 Commodity contracts — Purchased power, natural gas and fuel used — 2,429 Total $ — $ 4 2022 Interest rate contracts $ — Interest expense $ 4 $ 303 Commodity contracts 2 Purchased power, natural gas and fuel used (3) 2,456 Foreign currency exchange contracts — — Total $ 2 $ 1 2021 Interest rate contracts $ — Interest expense $ 4 $ 298 Commodity contracts 2 Purchased power, natural gas and fuel used (1) 1,719 Foreign currency exchange contracts (5) — Total $ (3) $ 3 (a) Changes in accumulated OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ 122 Interest Expense $ — $ 409 Commodity contracts $ 17 Operating revenues $ 169 $ 8,309 Total $ 139 $ 169 2022 Interest rate contracts $ 116 Interest Expense $ — $ 303 Commodity contracts $ (178) Operating revenues $ 59 $ 7,923 $ (62) $ 59 2021 Interest rate contracts $ (58) Interest Expense $ — $ 298 Commodity contracts $ (142) Operating revenues $ (3) $ 6,974 $ (200) $ (3) (a) Changes in OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2023 Interest rate contracts $ — Interest expense $ 9 $ 409 2022 Interest rate contracts $ — Interest expense $ 9 $ 303 2021 Interest rate contracts $ — Interest expense $ 9 $ 298 (a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029.
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables' activities as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (Millions) Wholesale electricity purchase contracts $ 29 $ 149 Wholesale electricity sales contracts 14 (200) Natural gas and other fuel purchase contracts 4 2 Financial power contracts 17 8 Total $ 64 $ (41)
Schedule of Effects of Trading and Non-Trading Derivatives	The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2023, 2022 and 2021 consisted of: Year Ended December 31, 2023 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (8) $ (5) Wholesale electricity sales contracts 71 67 Financial power contracts (5) 41 Financial and natural gas contracts — 10 Total gain included in operating revenues $ 58 $ 113 $ 8,309 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (109) Financial and natural gas contracts — (41) Total loss included in purchased power, natural gas and fuel used $ — $ (150) $ 2,429 Total Gain (Loss) $ 58 $ (37) Year Ended December 31, 2022 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 9 $ 6 Wholesale electricity sales contracts 1 (63) Financial power contracts 1 (52) Financial and natural gas contracts 1 (6) Total gain (loss) included in operating revenues $ 12 $ (115) $ 7,923 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 98 Financial and natural gas contracts — 5 Total gain included in purchased power, natural gas and fuel used $ — $ 103 $ 2,456 Total Gain (Loss) $ 12 $ (12) Year Ended December 31, 2021 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ (1) Wholesale electricity sales contracts (2) (33) Financial power contracts 4 (42) Financial and natural gas contracts (1) (25) Total gain (loss) included in operating revenues $ 2 $ (101) $ 6,974 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 32 Financial and natural gas contracts — 12 Total gain included in purchased power, natural gas and fuel used $ — $ 44 $ 1,719 Total Gain (Loss) $ 2 $ (57)
Schedule of Fair Value Hedging Instruments	The effects on our consolidated financial statements as of and for the years ended December 31, 2023 and 2022 are as follows: Fair value of hedge Location of (Gain) Recognized in Income Statement Loss Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2023 Year Ended December 31, 2023 Current liabilities $ (26) Interest Expense $ 31 $ 409 Non-current liabilities $ (63) Cumulative effect on hedged debt Current debt $ — Non-current debt $ 89 Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement (Millions) As of December 31, 2022 Year Ended December 31, 2022 Current liabilities $ (29) Interest Expense $ 6 $ 303 Non-current liabilities $ (86) Cumulative effect on hedged debt Current debt $ 29 Non-current debt $ 86

Leases (Tables)

Leases (Tables)	12 Months Ended
	Dec. 31, 2023
Leases [Abstract]
Schedule of Lease, Cost	The components of lease cost for the years ended December 31, 2023, 2022 and 2021 were as follows: For the Year Ended December 31, 2023 2022 2021 (Millions) Lease cost Finance lease cost Amortization of right-of-use assets $ 11 $ 12 $ 8 Interest on lease liabilities 3 3 3 Total finance lease cost 14 15 11 Operating lease cost 18 20 14 Short-term lease cost 8 6 4 Variable lease cost 3 3 4 Total lease cost $ 43 $ 44 $ 33 For the years ended December 31, 2023, 2022 and 2021 supplemental cash flow information related to leases was as follows: For the Year Ended December 31, 2023 2022 2021 (Millions) Cash paid for amounts included in the measurement of lease liabilities: Operating cash flows from operating leases $ 16 $ 14 $ 16 Operating cash flows from finance leases $ 3 $ 1 $ 3 Financing cash flows from finance leases $ 6 $ 9 $ 6 Right-of-use assets obtained in exchange for lease obligations: Finance leases $ — $ (1) $ — Operating leases $ 55 $ 25 $ 10
Schedule of Assets And Liabilities, Lessee	Balance sheet and other information as of December 31, 2023 and 2022 was as follows: As of December 31, 2023 2022 (Millions, except lease term and discount rate) Operating Leases Operating lease right-of-use assets $ 195 $ 159 Operating lease liabilities, current 16 13 Operating lease liabilities, long-term 199 161 Total operating lease liabilities $ 215 $ 174 Finance Leases Other assets $ 132 $ 143 Other current liabilities 28 7 Other non-current liabilities 53 80 Total finance lease liabilities $ 81 $ 87 Weighted-average Remaining Lease Term (years) Finance leases 5.6 6.4 Operating leases 20.8 16.9 Weighted-average Discount Rate Finance leases 3.39 % 3.46 % Operating leases 4.19 % 3.69 %
Schedule of Finance Lease Maturity	As of December 31, 2023, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2024 $ 30 $ 21 2025 8 17 2026 9 17 2027 10 19 2028 19 16 Thereafter 14 257 Total lease payments 90 346 Less: imputed interest (9) (131) Total $ 81 215
Schedule of Operating Lease Maturity	As of December 31, 2023, maturities of lease liabilities were as follows: Finance Leases Operating Leases (Millions) Year ending December 31, 2024 $ 30 $ 21 2025 8 17 2026 9 17 2027 10 19 2028 19 16 Thereafter 14 257 Total lease payments 90 346 Less: imputed interest (9) (131) Total $ 81 215

Commitments and Contingent Li_2

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2023
Commitments and Contingencies Disclosure [Abstract]
Schedule of Forward Purchase and Sales Commitment Arrangement	Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2023 consisted of: Year Purchases Sales (Millions) 2024 $ 1,513 $ 285 2025 246 161 2026 116 58 2027 83 34 2028 51 6 Thereafter 1,005 56 Totals $ 3,014 $ 600

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2023
Income Tax Disclosure [Abstract]
Schedule of Current and Deferred Taxes Charged to (Benefit) Expense	Current and deferred taxes charged to expense for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, 2023 2022 2021 (Millions) Current Federal $ 36 $ — $ 6 State (1) 2 4 Current taxes charged to expense 35 2 10 Deferred Federal 62 67 49 State (8) 49 72 Deferred taxes charged to expense 54 116 121 Production tax credits (97) (97) (109) Investment tax credits (1) (1) (1) Total Income Tax (Benefit) Expense $ (9) $ 20 $ 21
Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate	The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2023, 2022 and 2021 consisted of: Years Ended December 31, 2023 2022 2021 (Millions) Tax expense at federal statutory rate $ 138 $ 176 $ 140 Depreciation and amortization not normalized (27) (20) (19) Investment tax credit amortization (1) (1) (1) Tax return related adjustments (4) 2 — Production tax credits (97) (97) (109) Tax equity financing arrangements 26 13 14 State tax (benefit) expense, net of federal effect (7) 40 61 Excess ADIT amortization (35) (66) (65) Valuation allowance — (35) 21 Other, net (2) 8 (21) Total Income Tax (Benefit) Expense $ (9) $ 20 $ 21
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Deferred Income Tax Liabilities (Assets) Property related $ 4,650 $ 4,504 Unfunded future income taxes 141 129 Federal and state tax credits (986) (942) Federal and state NOL’s (1,308) (1,086) Joint ventures/partnerships 244 210 Nontaxable grant revenue (250) (270) Tax Act - tax on regulatory remeasurement (317) (328) Valuation allowance 82 87 Other 180 (91) Deferred Income Tax Liabilities $ 2,436 $ 2,213 Deferred tax assets $ 2,861 $ 2,717 Deferred tax liabilities 5,297 4,930 Net Accumulated Deferred Income Tax Liabilities $ 2,436 $ 2,213
Schedule of Reconciliation of Unrecognized Income Tax Benefits	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2023, 2022 and 2021 consisted of: Years ended December 31, 2023 2022 2021 (Millions) Beginning Balance $ 127 $ 127 $ 127 Increases for tax positions related to prior years 7 2 3 Increases for tax positions related to current year — 2 — Decreases for tax positions related to prior years (4) (4) (3) Ending Balance $ 130 $ 127 $ 127

Post-Retirement and Similar O_2

Post-Retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2023
Retirement Benefits [Abstract]
Schedule of Obligations and Funded Status	As of December 31, 2023 and 2022, our obligations and funded status consisted of: Pension Benefits Postretirement Benefits As of December 31, 2023 2022 2023 2022 (Millions) Change in benefit obligation Benefit Obligation as of January 1, $ 2,452 $ 3,487 $ 284 $ 408 Service cost 6 27 1 2 Interest cost 121 111 14 10 Plan amendments — 1 — — Actuarial loss (gain) 131 (716) 36 (103) Curtailments/Settlements (2) (274) — — Benefits paid (208) (184) (34) (33) Benefit Obligation as of December 31, 2,500 2,452 301 284 Change in plan assets Fair Value of Plan Assets as of January 1, 2,151 3,079 89 127 Actual return on plan assets 204 (584) 12 (22) Employer contributions 14 22 16 17 Settlements (2) (182) — — Benefits paid (208) (184) (34) (33) Fair Value of Plan Assets as of December 31, 2,159 2,151 83 89 Funded Status as of December 31, $ (341) $ (301) $ (218) $ (195)
Schedule of Amounts Recognized in Balance Sheet	As of December 31, 2023 and 2022, funded status amounts recognized on our consolidated balance sheets consisted of: Pension Benefits Postretirement Benefits As of December 31, 2023 2022 2023 2022 (Millions) Current liabilities $ — $ — $ (5) $ (5) Non-current liabilities (341) (301) (213) (190) Total $ (341) $ (301) $ (218) $ (195)
Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations	Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2023 and 2022 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2023 2022 2023 2022 (Millions) Net loss (gain) $ 251 $ 181 $ (52) $ (91) Prior service cost (credit) $ 6 $ 7 $ (1) $ (1) Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2023, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2023 2022 2021 2023 2022 2021 (Millions) Net Periodic Benefit Cost: Service cost $ 5 $ 26 $ 39 $ 1 $ 2 $ 3 Interest cost 119 109 86 14 10 10 Expected return on plan assets (143) (162) (199) (5) (6) (7) Amortization of prior service cost (benefit) 1 1 2 — (1) (5) Amortization of net loss 3 49 115 (12) (4) 2 Settlement charge — 17 6 — — — Curtailment charge — (32) — — — — Net Periodic Benefit Cost (15) 8 49 (2) 1 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Curtailments — (59) — — — — Settlement charge — (17) (6) — — — Net loss (gain) 73 33 (218) 26 (75) (31) Amortization of net loss (3) (49) (115) 12 4 (2) Current year prior service cost (credit) — 1 2 — — 1 Amortization of prior service (cost) benefit (1) (1) (2) — 1 5 Total Other Changes 69 (92) (339) 38 (70) (27) Total Recognized $ 54 $ (84) $ (290) $ 36 $ (69) $ (24) Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2023, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits For the years ended December 31, 2023 2022 2021 2023 2022 2021 (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ 1 $ 1 $ — $ — $ — Interest cost 2 2 1 — — — Expected return on plan assets (2) (2) (2) — — — Amortization of net loss (gain) — 1 2 (1) (1) (1) Settlement/Curtailment charge 1 1 1 — — — Net Periodic Benefit Cost 2 3 3 (1) (1) (1) Other Changes in plan assets and benefit obligations recognized in OCI: Settlement charge (1) (1) (1) (1) (1) (1) Net loss (gain) — (1) (3) 1 (1) 1 Amortization of net (loss) gain — (1) (2) 1 1 1 Amortization of prior service cost — — — — — — Total Other Changes (1) (3) (6) 1 (1) 1 Total Recognized $ 1 $ — $ (3) $ — $ (2) $ —
Schedule of Amounts Recognized in OCI	Amounts recognized in OCI for ARHI for the years ended December 31, 2023 and 2022, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2023 2022 2023 2022 (Millions) Net loss (gain) $ 11 $ 12 $ (4) $ (6)
Schedule of Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans	The aggregate PBO and ABO and the fair value of plan assets for our underfunded qualified plans consisted of: PBO in excess of plan assets As of December 31, 2023 2022 (Millions) Projected benefit obligation $ 2,500 $ 2,452 Fair value of plan assets $ 2,159 $ 2,151 ABO in excess of plan assets As of December 31, 2023 2022 (Millions) Accumulated benefit obligation $ 2,479 $ 2,429 Fair value of plan assets $ 2,159 $ 2,151
Schedule of Weighted Average Assumptions Used to Determine Benefit Obligations and Net periodic Benefit Cost	The weighted-average assumptions used to determine our benefit obligations as of December 31, 2023 and 2022 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2023 2022 2023 2022 Discount rate 4.69 % 5.18 % 4.66 % 5.12 % Rate of compensation increase 2.60 % 2.99 % 3.00 % 3.00 % Interest crediting rate 3.37 % 2.87 % N/A N/A The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2023, 2022 and 2021 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2023 2022 2021 2023 2022 2021 Discount rate 5.18 % 2.85 % 2.34 % 5.12 % 2.66 % 2.19 % Expected long-term return on plan assets 6.35 % 6.33 % 7.30 % 5.61 % 4.66 % 4.05 % Rate of compensation increase 2.99 % 3.53 % 3.52 % 3.00 % 3.50 % 3.50 %
Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations	Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 Health care cost trend rate assumed for next year 6.20%/8.60% 5.00%/6.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) 4.50% 4.50% Year that the rate reaches the ultimate trend rate 2032 / 2028 2029 / 2025
Schedule of Expected Future Benefits Payments	Expected benefit payments as of December 31, 2023 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2024 $ 235 $ 28 $ — 2025 $ 221 $ 28 $ — 2026 $ 216 $ 27 $ — 2027 $ 210 $ 26 $ — 2028 $ 204 $ 25 $ — 2029 - 2033 $ 918 $ 109 $ 2
Schedule of Fair Values of Pension Plan Assets, by Asset Category	The fair values of pension plan assets, by asset category, as of December 31, 2023, consisted of: As of December 31, 2023 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 63 $ — $ 63 $ — U.S. government securities 295 295 — — Common stocks 58 58 — — Registered investment companies 106 106 — — Corporate bonds 746 — 746 — Common collective trusts 708 — 708 — Other, principally annuity, fixed income 6 — 6 — $ 1,982 $ 459 $ 1,523 $ — Other investments measured at net asset value 177 Total $ 2,159 The fair values of pension plan assets, by asset category, as of December 31, 2022, consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 51 $ — $ 51 $ — U.S. government securities 252 252 — — Common stocks 57 57 — — Registered investment companies 104 104 — — Corporate bonds 708 — 708 — Preferred stocks 1 1 — — Common collective trusts 472 — 472 — Other, principally annuity, fixed income 33 — 33 — $ 1,678 $ 414 $ 1,264 $ — Other investments measured at net asset value 473 Total $ 2,151
Schedule of Fair Value of Other Post-Retirement Plan Assets, by Asset Category	The fair values of other postretirement plan assets, by asset category, as of December 31, 2023 consisted of: As of December 31, 2023 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 2 $ — $ 2 $ — U.S. government securities 1 1 — — Common stocks 1 1 — — Registered investment companies 61 61 — — Corporate bonds 3 — 3 — Common collective trusts 5 — 5 — Other, principally annuity, fixed income 8 — 8 — $ 81 $ 63 $ 18 $ — Other investments measured at net asset value 2 Total $ 83 The fair values of other postretirement plan assets, by asset category, as of December 31, 2022 consisted of: As of December 31, 2022 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 2 $ — $ 2 $ — U.S. government securities 1 1 — — Registered investment companies 69 69 — — Corporate bonds 3 — 3 — Common collective trusts 4 — 4 — Other, principally annuity, fixed income 8 — 8 — $ 87 $ 70 $ 17 $ — Other investments measured at net asset value 2 Total $ 89

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2023
Equity [Abstract]
Schedule of Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) for the years ended December 31, 2023, 2022 and 2021 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2020 2021 Change As of December 31, 2021 2022 Change As of December 31, 2022 2023 Change As of December 31, 2023 (Millions) Loss (gain) for defined benefit plans, net of income tax expense of $0 for 2021, $3 for 2022 and $0 for 2023 $ 2 $ 14 $ — Amortization of pension cost, net of income tax (benefit) expense of $(1) for 2021, $1 for 2022 and $0 for 2023 (8) 4 (1) Net gain (loss) on pension plans $ (32) $ (6) $ (38) $ 18 $ (20) $ (1) $ (21) Unrealized (loss) gain from equity method investment, net of income tax (benefit) expense of $(3) for 2021, $6 for 2022 and $1 for 2023 (a) $ — $ (9) $ (9) $ 22 $ 13 $ 5 $ 18 Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax (benefit) expense of $(44) for 2021, $0 for 2022 and $6 for 2023 (35) (159) (194) (1) (195) 17 (178) Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense of $(3) for 2021, $19 for 2022 and $48 for 2023 (b) (44) 12 (32) 54 22 134 156 Loss on derivatives qualifying as cash flow hedges (79) (147) (226) 53 (173) 151 (22) Accumulated Other Comprehensive Loss $ (111) $ (162) $ (273) $ 93 $ (180) $ 155 $ (25) (a) Foreign currency and interest rate contracts. (b) Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2023
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to Avangrid for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of: Years Ended December 31, 2023 2022 2021 (Millions, except for number of shares and per share data) Numerator: Net income attributable to Avangrid $ 786 $ 881 $ 707 Denominator: Weighted average number of shares outstanding - basic 386,810,088 386,727,246 358,086,621 Weighted average number of shares outstanding - diluted 387,164,874 387,215,785 358,578,608 Earnings per share attributable to Avangrid Earnings Per Common Share, Basic $ 2.03 $ 2.28 $ 1.97 Earnings Per Common Share, Diluted $ 2.03 $ 2.27 $ 1.97

Grants, Government Incentives_2

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2023
Other Liabilities Disclosure [Abstract]
Schedule of Government Grants Activities	The changes in government grants recorded in deferred income as of December 31, 2023 and 2022 consisted of: (Millions) Government grants - Renewables Other deferred income Total As of December 31, 2021 $ 1,125 $ 5 $ 1,130 Disposals — — — Recognized in income (65) (3) (68) As of December 31, 2022 1,060 2 1,062 Disposals — — — Recognized in income (65) (1) (66) As of December 31, 2023 $ 995 $ 1 $ 996 The changes in government grants recorded as a reduction to the related utility plant as of December 31, 2023 and 2022 consisted of: (Millions) Government grants - Networks Total As of December 31, 2021 $ 63 $ 63 Disposals — — Recognized in income (4) (4) As of December 31, 2022 59 59 Disposals — — Recognized in income (5) (5) As of December 31, 2023 $ 54 $ 54

Other Financial Statement Items

Other Financial Statement Items (Tables)	12 Months Ended
	Dec. 31, 2023
Balance Sheet Related Disclosures [Abstract]
Schedule of Other Income and (Expense)	Other income (expense) for the years ended December 31, 2023, 2022 and 2021 consisted of: Years ended December 31, 2023 2022 2021 (Millions) Allowance for funds used during construction 82 63 88 Carrying costs on regulatory assets 17 16 17 Non-service component of net periodic benefit cost 22 (58) (37) Other 8 9 (8) Total Other Income $ 129 $ 30 $ 60
Schedule of Accounts Receivable and Change in Allowance For Bad Debts	Accounts receivable and unbilled revenues, net as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Trade receivables and unbilled revenues $ 1,749 $ 1,892 Allowance for credit losses (161) (155) Total Accounts receivable and unbilled revenues, net $ 1,588 $ 1,737 The change in the allowance for credit losses as of December 31, 2023 and 2022 consisted of: (Millions) As of December 31, 2020 $ 108 Current period provision 110 Write-off as uncollectible (67) As of December 31, 2021 $ 151 Current period provision 110 Write-off as uncollectible (106) As of December 31, 2022 $ 155 Current period provision 137 Write-off as uncollectible (131) As of December 31, 2023 $ 161
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Prepaid other taxes $ 142 $ 136 Broker margin and collateral accounts 165 164 Other pledged deposits 32 12 Prepaid expenses 74 68 Other 16 6 Total $ 429 $ 386
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2023 and 2022 consisted of: As of December 31, 2023 2022 (Millions) Advances received $ 236 $ 271 Accrued salaries 184 153 Short-term environmental provisions 40 54 Collateral deposits received 128 68 Pension and other postretirement 6 5 Finance leases 28 7 Other 40 35 Total $ 662 $ 593

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2023
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the year ended December 31, 2023 consisted of: For the Year Ended December 31, 2023 Networks Renewables Other(a) Avangrid Consolidated (Millions) Revenue - external $ 6,850 $ 1,456 $ 3 $ 8,309 Revenue - intersegment 5 — (5) — Depreciation and amortization 694 456 8 1,158 Operating income 996 (45) (21) 930 Earnings (losses) from equity method investments 15 (9) — 6 Interest expense, net of capitalization 287 16 106 409 Income tax expense (benefit) 141 (67) (83) (9) Capital expenditures 2,192 768 12 2,972 Adjusted net income 727 163 (82) 808 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. Segment information as of and for the year ended December 31, 2022 consisted of: For the year ended December 31, 2022 Networks Renewables Other(a) Avangrid Consolidated (Millions) Revenue - external $ 6,781 $ 1,141 $ 1 $ 7,923 Revenue - intersegment 1 — (1) — Depreciation and amortization 660 424 1 1,085 Operating income 901 (36) (13) 852 Earnings (losses) from equity method investments 11 251 — 262 Interest expense, net of capitalization 220 16 67 303 Income tax expense (benefit) 94 (114) 40 20 Capital expenditures 1,803 708 8 2,519 Adjusted net income 628 403 (130) 901 As of December 31, 2022 Property, plant and equipment 20,027 10,950 17 30,994 Equity method investments 171 266 — 437 Total assets $ 28,069 $ 13,553 $ (499) $ 41,123 (a) Includes Corporate and intersegment eliminations. Segment information for the year ended December 31, 2021 consisted of: For the year ended December 31, 2021 Networks Renewables Other (a) Avangrid Consolidated (Millions) Revenue - external $ 5,753 $ 1,220 $ 1 $ 6,974 Revenue - intersegment 1 — (1) — Depreciation and amortization 616 397 1 1,014 Operating income 876 26 (7) 895 Earnings (losses) from equity method investments 12 (5) — 7 Interest expense, net of capitalization 217 1 80 298 Income tax expense (benefit) 98 (48) (29) 21 Capital expenditures 2,294 680 2 2,976 Adjusted net income $ 661 $ 170 $ (51) $ 780 (a) Includes Corporate and intersegment eliminations.
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the years ended December 31, 2023, 2022 and 2021 is as follows: Years Ended December 31, 2023 2022 2021 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 808 $ 901 $ 780 Adjustments: Mark-to-market adjustments - Renewables (1) 21 — (53) Impact of COVID-19 (2) — — (34) Merger and other transaction costs (3) (11) (4) (12) Offshore contract provision (4) (40) (24) — Accelerated depreciation from repowering (5) (1) — — Income tax impact of adjustments 8 7 26 Net Income Attributable to Avangrid, Inc. $ 786 $ 881 $ 707 (1) Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas. (2) Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions. (3) Pre-merger and other transaction costs incurred. (4) Costs incurred in connection with an offshore contract provision. (5) Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2023
Related Party Transactions [Abstract]
Schedule of Related Party Transactions and Balances	Related party transactions for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of: Years Ended December 31, 2023 2022 2021 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola, S.A. $ 2 $ (45) $ 1 $ (46) $ — $ (52) Iberdrola Renovables Energia, S.L. $ — $ (8) $ 1 $ (5) $ — $ (10) Iberdrola Financiación, S.A.U. $ — $ (36) $ — $ (12) $ — $ (9) Vineyard Wind 1 $ 12 $ — $ 7 $ — $ 14 $ — Iberdrola Solutions $ — $ — $ — $ — $ 7 $ (39) Other $ — $ (2) $ 1 $ (3) $ 2 $ (3) Related party balances as of December 31, 2023 and 2022, respectively, consisted of: As of December 31, 2023 2022 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 1 $ — $ 1 $ (29) Iberdrola Renovables Energía, S.L. $ 4 $ — $ — $ — Iberdrola Financiación, S.A.U. $ — $ (799) $ — $ (9) Vineyard Wind 1 $ 6 $ (8) $ 3 $ (8) Iberdrola Solutions $ — $ (6) $ — $ (2) Other $ 4 $ — $ 4 $ (1)

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2023
Share-Based Payment Arrangement [Abstract]
Schedule of Nonvested PSUs	A summary of the status of the Avangrid's nonvested PSUs and RSUs as of December 31, 2023, and changes during the fiscal year ended December 31, 2023, is presented below: Number of PSUs and RSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2022 1,084,951 $ 36.55 Granted 1,068,326 $ 29.30 Forfeited (449,876) $ 35.30 Vested (244,110) $ 37.43 Nonvested Balance – December 31, 2023 1,459,291 $ 31.54

Background and Nature of Oper_2

Background and Nature of Operations (Details) - Avangrid	Dec. 31, 2023
Iberdrola S.A.
Noncontrolling Interest [Line Items]
Percentage of equity owned by parent	81.60%
Various Shareholders
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners	14.70%

Summary of Significant Accoun_4

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Line Items]
Composite rate	2.80%	2.80%
Average remaining service period	10 years
Expected return on plan assets, period	5 years
Unionized Employees Concentration Risk | Employees covered by a collective bargaining agreement
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	45.80%
Unionized Employees Concentration Risk | Agreements which will expire within the coming year
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	24.10%
Min.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	4 years
Max.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	40 years

Summary of Significant Accoun_5

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Property, Plant and Equipment (Details)	Dec. 31, 2023
Solar power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years
Min. | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	35 years
Min. | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	45 years
Min. | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	10 years
Min. | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	4 years
Min. | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	10 years
Min. | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	1 year
Min. | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	10 years
Min. | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	4 years
Min. | Structural Components
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Rotary Components
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Max. | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	90 years
Max. | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	85 years
Max. | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Max. | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	70 years
Max. | Structural Components
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Max. | Rotary Components
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years

Revenue - Additional Informatio

Revenue - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Contract assets	$ 9	$ 9
Contract liabilities	18	33
Contract liabilities, revenue recognized	45	33	$ 22
Accounts receivable related to contracts with customers	1,441	1,622
Unbilled contracts receivable	$ 426	$ 541
Min. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	6 months
Max. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	2 years
Networks
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	1 year
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term	15 years

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 7,644	$ 7,785	$ 6,793
Leasing revenue	9	8	7
Derivative revenue	450	4	3
Alternative revenue programs	137	68	115
Other revenue	69	58	56
Total operating revenues	8,309	7,923	6,974
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(2)	0	0
Leasing revenue	0	0	0
Derivative revenue	0	0	0
Alternative revenue programs	0	0	0
Other revenue	0	0	0
Total operating revenues	(2)	0	0
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,962	4,610	4,015
Regulated operations – electricity | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,617	1,931	1,516
Regulated operations – natural gas | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	817	947	1,028
Nonregulated operations – wind | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	46	36	20
Nonregulated operations – solar | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	180	96	63
Nonregulated operations – thermal | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	22	165	151
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	(2)	0	0
Networks
Segment Reporting Information [Line Items]
Total operating revenues	6,855	6,782	5,754
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	6,655	6,658	5,598
Leasing revenue	9	8	7
Derivative revenue	0	0	0
Alternative revenue programs	137	68	115
Other revenue	54	48	34
Total operating revenues	6,850	6,781	5,753
Networks | Regulated operations – electricity | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,962	4,610	4,015
Networks | Regulated operations – natural gas | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,617	1,931	1,516
Networks | Nonregulated operations – wind | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – solar | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – thermal | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Other | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	76	117	67
Renewables
Segment Reporting Information [Line Items]
Total operating revenues	1,456	1,141	1,220
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	991	1,127	1,195
Leasing revenue	0	0	0
Derivative revenue	450	4	3
Alternative revenue programs	0	0	0
Other revenue	15	10	22
Total operating revenues	1,456	1,141	1,220
Renewables | Regulated operations – electricity | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Regulated operations – natural gas | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Nonregulated operations – wind | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	817	947	1,028
Renewables | Nonregulated operations – solar | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	46	36	20
Renewables | Nonregulated operations – thermal | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	180	96	63
Renewables | Other | Operating Segments
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ (52)	$ 48	$ 84

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Dec. 31, 2023 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 380
Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	1
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	186
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	193
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 159
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 69
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 89
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 95
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]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 67
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	$ 28
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	$ 44
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]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 34
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 10
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 20
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]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 13
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 7
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 6
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]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Revenue expected to be recognized on multiyear 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]: 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]: 2029-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 56
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 2
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2029-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 54
Remaining performance obligation, period

Industry Regulation - Electrici

Industry Regulation - Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts (Details)	Dec. 31, 2023 company
Networks
Public Utilities, General Disclosures [Line Items]
Number of regulated utility company	8

Industry Regulation - CMP Distr

Industry Regulation - CMP Distribution Rate Case (Details) - USD ($) $ in Thousands					1 Months Ended
	May 31, 2023	Nov. 19, 2020	Mar. 01, 2020	Feb. 19, 2020	Sep. 30, 2021
Public Utilities, General Disclosures [Line Items]
Equity ratio		50%
Central Maine Power
Public Utilities, General Disclosures [Line Items]
Public utilities, approved revenue increase	$ 16,750			$ 17,000
Delivery Rate Increase %				7%
Distribution tariff rate increased based on ROE				9.25%
Distribution tariff rate increased based on equity capital				50%
ROE reduction			1%
Proposed distribution tariff rate decrease based on return on equity			8.25%
Customer service performance period					18 months
Approved return on equity	9.35%
Equity ratio	50%
Equity ratio for earnings sharing	50%
Public utilities, earnings sharing percentage calculation basis	0.0100
Maximum penalty per year for failure to meet specified service quality indicator target	$ 8,800

Industry Regulation - NYSEG and

Industry Regulation - NYSEG and RG&E Rate Plans (Details) - USD ($) $ in Millions			12 Months Ended
	Jun. 14, 2023	Nov. 19, 2020	Dec. 31, 2023	Dec. 31, 2022
Public Utilities, General Disclosures [Line Items]
Equity ratio		50%
Regulatory assets			$ 3,529	$ 2,768
Deferred storm costs, amortization period	10 years
NYDPS
Public Utilities, General Disclosures [Line Items]
Approved return on equity		8.80%
Equity ratio		48%
NYSEG | Super Storm Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 52.3
NYSEG | Non-Super Storm Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 96.6
Depreciation amortization period	7 years
NYSEG | Electricity
Public Utilities, General Disclosures [Line Items]
Approved return on equity			9.20%
Equity ratio			48%
Public utilities, recovery of Major Storm costs	$ 371
NYSEG | Natural Gas
Public Utilities, General Disclosures [Line Items]
Approved return on equity			9.20%
Equity ratio			48%
RG&E | Non-Super Storm Costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 19.6
Depreciation amortization period	2 years
RG&E | Electricity
Public Utilities, General Disclosures [Line Items]
Approved return on equity			9.20%
Equity ratio			48%
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%
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%
Percentage of service provider's portion used to reduce outstanding storm-related regulatory asset deferral balance			50%
Capital investment amount projected	$ 634

Industry Regulation - UI, CNG,

Industry Regulation - UI, CNG, SCG and BGC Rate Plans (Details) - USD ($) $ in Millions										12 Months Ended
	Nov. 03, 2023	Aug. 25, 2023	Jul. 21, 2023	Sep. 09, 2022	Jun. 24, 2022	Nov. 19, 2020	Jan. 01, 2019	Jan. 01, 2018	Jan. 01, 2017	Dec. 31, 2023
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%
Equity ratio						50%
BGC
Public Utilities, General Disclosures [Line Items]
Distribution revenue requirement					$ 5.6
Public utilities, requested return on equity, percentage					9.70%
Percentage of earnings customers received					54%
PURA
Public Utilities, General Disclosures [Line Items]
Distribution revenue requirement		$ 23
Public utilities, requested return on equity, percentage			8.80%
Percentage of earnings customers received			50%
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%
PURA | UI
Public Utilities, General Disclosures [Line Items]
New distribution rate schedule, period									3 years
Approved return on equity		8.63%							9.10%
Equity ratio		50%							50%
Public utilities regulatory authority distribution rate									50%
Approved debt capital structure, percentage		50%
PURA | UI | Year 1
Public Utilities, General Disclosures [Line Items]
Distribution revenue requirement				$ 91
Interim rate increase, amount				54
PURA | UI | Year 2
Public Utilities, General Disclosures [Line Items]
Distribution revenue requirement				20
PURA | UI | Year 3
Public Utilities, General Disclosures [Line Items]
Distribution revenue requirement				$ 19
PURA | SCG
Public Utilities, General Disclosures [Line Items]
Approved return on equity								9.25%
Equity ratio								52%
Distribution revenue requirement	$ 40.6
PURA | CNG
Public Utilities, General Disclosures [Line Items]
Approved return on equity							9.30%
Distribution revenue requirement	$ 19.8
PURA | CNG | Year 1
Public Utilities, General Disclosures [Line Items]
Approved return on equity							54%
PURA | CNG | Year 2
Public Utilities, General Disclosures [Line Items]
Approved return on equity							54.50%
PURA | CNG | Year 3
Public Utilities, General Disclosures [Line Items]
Approved return on equity							55%

Industry Regulation - REV (Deta

Industry Regulation - REV (Details)	12 Months Ended
	Dec. 31, 2017 performanceMetric	Jul. 16, 2020 USD ($)
Public Utilities, General Disclosures [Line Items]
Number of CDG performance metrics | performanceMetric	6
Direct Current Fast Charger incentive program, approved amount		$ 700,000,000
NYSEG and RG&E
Public Utilities, General Disclosures [Line Items]
Integrated Energy Data Resource platform, combined cost cap amount		12,000,000
Direct Current Fast Charger incentive program, approved amount		$ 118,000,000

Industry Regulation - Power Tax

Industry Regulation - Power Tax Audits (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Jan. 21, 2020
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 3,529	$ 2,768
Federal tax depreciation normalization adjustment
Public Utilities, General Disclosures [Line Items]
Regulatory assets	$ 130	$ 137
Power Tax | CMP
Public Utilities, General Disclosures [Line Items]
Depreciation amortization period			32 years 6 months

Industry Regulation - Minimum E

Industry Regulation - Minimum Equity Requirements for Regulated Subsidiaries (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Regulated Operations [Abstract]
Number of average months used to set rate	13 months
Equity ratio requirement, percentage below the ratio used to set rates	3%
Restricted net assets	$ 6,860

Industry Regulation - New Renew

Industry Regulation - New Renewable Source Generation (Details) MWh in Thousands, $ in Millions

1 Months Ended

12 Months Ended

24 Months Ended

Aug. 17, 2023 MW

Dec. 09, 2019 USD ($) MWh process

Sep. 10, 2018 USD ($)

Aug. 03, 2017 MW

Sep. 22, 2016 MW

Mar. 31, 2010 USD ($) MW

Oct. 31, 2021 contract

Dec. 31, 2020 contract

Oct. 31, 2018 agreement MW

Dec. 31, 2023 USD ($)

Dec. 31, 2020 MW

Dec. 31, 2019 MWh project

Dec. 31, 2023 USD ($) contract

Public Utilities, General Disclosures [Line Items]

UI terminated contracts | contract

8

Number of remaining projects with existing contracts | project

3

Maine Public Utility Commission

Public Utilities, General Disclosures [Line Items]

Number of competitive solicitation processes to procure | process

2

Competitive solicitation processes to procure, amount of energy as percentage of retail electricity sales

14%

Competitive solicitation processes to procure, amount of energy (in MWh) | MWh

1,715

Maine Public Utility Commission | Min.

Public Utilities, General Disclosures [Line Items]

Competitive solicitation processes to procure, amount of energy as percentage of retail electricity sales must acquire

7%

Maine Public Utility Commission | Max.

Public Utilities, General Disclosures [Line Items]

Competitive solicitation processes to procure, amount of energy as percentage of retail electricity sales must acquire

10%

UI

Public Utilities, General Disclosures [Line Items]

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

$ 200

$ 200

Period of purchase commitment

21 years

Solicitation period

6 years

Maximum annual commitment level obligation after year six | $

$ 14

14

Additional maximum annual commitment | $

$ 64

$ 64

Number of power purchase agreements | agreement

5

Proposed off shore wind capacity (in MW) | MW

50

Number of projects | project

11

PPA capacity (in MWH) | MWh

12,000

Vineyard Wind 1

Public Utilities, General Disclosures [Line Items]

Proposed off shore wind capacity (in MW) | MW

804

CMP

Public Utilities, General Disclosures [Line Items]

Number of contracts executed | contract

6

13

Number of contracts terminated | contract

6

CMP | Evergreen Wind Power III, LLC

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase Obligation, Amount Per Year | $

$ 7

CMP | Maine Wood Pellets

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

CMP | Georges River Energy

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

CMP | Pittsfield Solar

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

CMP | Dirigo Solar, LLC

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase Obligation, Amount Per Year | $

$ 4

CMP | Maine Aqua Ventus I GP LLC

Public Utilities, General Disclosures [Line Items]

Period of purchase commitment

20 years

Purchase Obligation, Amount Per Year | $

$ 12

Evergreen Wind Power III, LLC

Public Utilities, General Disclosures [Line Items]

Wind farm capacity (in MW) | MW

60

Maine Wood Pellets

Public Utilities, General Disclosures [Line Items]

Wind farm capacity (in MW) | MW

7.1

Georges River Energy

Public Utilities, General Disclosures [Line Items]

Wind farm capacity (in MW) | MW

7.5

Pittsfield Solar

Public Utilities, General Disclosures [Line Items]

Wind farm capacity (in MW) | MW

9.9

Industry Regulation - Connectic

Industry Regulation - Connecticut Energy Legislation (Details)	Jun. 23, 2021 USD ($)	Jun. 30, 2021 USD ($) hour
Regulated Operations [Abstract]
Energy legislation settlement agreement, contribution amount	$ 5,000,000
Energy legislation settlement agreement, customers rate credits provided	50,000,000
Energy legislation settlement agreement, customers rate credits collected in rate adjustment mechanism	$ 52,000,000
Energy legislation settlement agreement, customers rate credits provided, period	22 months
Energy legislation, customer compensation and reimbursement provisions, power outage hours benchmark (more than) | hour		96
Energy legislation, customer compensation and reimbursement provisions, customer payment per day		$ 25
Energy legislation, customer compensation and reimbursement provisions, food and medicine reimbursement		$ 250

Industry Regulation - PURA Inve

Industry Regulation - 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
UI
Public Utilities, General Disclosures [Line Items]
ROE reduction			0.15%

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Regulatory Assets Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Regulatory Assets [Line Items]
Unrecorded regulatory assets	$ 1,249
Unfunded future income tax expense collection period	46 years
Min.
Regulatory Assets [Line Items]
Regulatory assets recovery period	6 months
Max.
Regulatory Assets [Line Items]
Regulatory assets recovery period	30 months
Central Maine Power
Regulatory Assets [Line Items]
Deferred income tax recovery period	32 years 6 months

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Schedule of Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Regulatory Assets [Line Items]
Total regulatory assets	$ 3,529	$ 2,768
Less: current portion	718	447
Regulatory assets	2,811	2,321
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	445	365
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	58	93
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	868	671
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	24	41
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	86	52
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	38	56
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	23	33
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	16	56
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	240	248
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	58	64
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	17	19
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	578	492
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	130	137
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	19	20
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	59	55
COVID-19 cost recovery and late payment surcharge
Regulatory Assets [Line Items]
Total regulatory assets	12	17
Low income arrears forgiveness
Regulatory Assets [Line Items]
Total regulatory assets	55	31
Excess generation service charge
Regulatory Assets [Line Items]
Total regulatory assets	52	24
System Expansion
Regulatory Assets [Line Items]
Total regulatory assets	22	21
Non-bypassable charge
Regulatory Assets [Line Items]
Total regulatory assets	103	14
Hedges losses
Regulatory Assets [Line Items]
Total regulatory assets	34	13
Rate change levelization
Regulatory Assets [Line Items]
Total regulatory assets	60	0
Value of distributed energy resources
Regulatory Assets [Line Items]
Total regulatory assets	49	36
Uncollectible reserve
Regulatory Assets [Line Items]
Total regulatory assets	104	0
New York make-whole provision
Regulatory Assets [Line Items]
Total regulatory assets	96	0
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 283	$ 210

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 2,955	$ 3,269
Less: current portion	261	354
Total non-current regulatory liabilities	2,694	2,915
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	30
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	8	15
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	89	117
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	3	9
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	3
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,190	1,232
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,139	1,178
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	16
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	21	17
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	11
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	32
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	39	36
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	26	31
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	8	10
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	21	22
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	19	18
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	17
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	34	27
Non by-passable charges
Regulatory Liabilities [Line Items]
Total regulatory liabilities	9	76
Transmission revenue reconciliation mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	57	75
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 209	$ 297

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Regulatory Liabilities Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
UIL Holdings
Regulatory Liabilities [Line Items]
Business combination merger related rate credits	$ 2	$ 2

Goodwill and Intangible Asset_2

Goodwill and Intangible Assets - Schedule of Goodwill by Reportable Segment (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Goodwill [Line Items]
Goodwill	$ 3,119	$ 3,119
Networks
Goodwill [Line Items]
Goodwill	2,747	2,747
Renewables
Goodwill [Line Items]
Goodwill	$ 372	$ 372

Goodwill and Intangible Asset_3

Goodwill and Intangible Assets - Additional Information (Details)		12 Months Ended
	Dec. 16, 2015 USD ($)	Dec. 31, 2023 USD ($) reportingUnit	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2002 USD ($)	Dec. 31, 2000 USD ($)
Goodwill [Line Items]
Impairment of goodwill		$ 0	$ 0
Amortization expense		$ 15,000,000	$ 14,000,000	$ 13,000,000
Maine Reporting Unit
Goodwill [Line Items]
Goodwill						$ 325,000,000
New York Reporting Unit
Goodwill [Line Items]
Goodwill					$ 654,000,000
UIL Reporting Unit
Goodwill [Line Items]
Goodwill	$ 1,768,000,000
Networks
Goodwill [Line Items]
Number of reporting units | reportingUnit		3

Goodwill and Intangible Asset_4

Goodwill and Intangible Assets - Summary of Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 635	$ 612
Accumulated Amortization	(351)	(331)
Net Carrying Amount	284	281
Wind development
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	587	590
Accumulated Amortization	(325)	(313)
Net Carrying Amount	262	277
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	48	22
Accumulated Amortization	(26)	(18)
Net Carrying Amount	$ 22	$ 4

Goodwill and Intangible Asset_5

Goodwill and Intangible Assets - Schedule of Amortization Expense (Details) $ in Millions	Dec. 31, 2023 USD ($)
Year ending December 31,
2024	$ 15
2025	14
2026	14
2027	13
2028	$ 12

Property, Plant and Equipment -

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 40,455	$ 38,453
Total accumulated depreciation	(12,479)	(11,542)
Total Net Property, Plant and Equipment in Service	27,976	26,911
Construction work in progress	4,881	4,083
Total Property, Plant and Equipment	32,857	30,994
Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	34,349	32,730
Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,765	5,406
Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	341	317
Regulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	25,480	24,026
Total accumulated depreciation	(6,742)	(6,277)
Total Net Property, Plant and Equipment in Service	18,738	17,749
Construction work in progress	2,902	2,225
Total Property, Plant and Equipment	21,640	19,974
Regulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	19,729	18,634
Regulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,751	5,392
Regulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	0	0
Nonregulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	14,975	14,427
Total accumulated depreciation	(5,737)	(5,265)
Total Net Property, Plant and Equipment in Service	9,238	9,162
Construction work in progress	1,979	1,858
Total Property, Plant and Equipment	11,217	11,020
Nonregulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	14,620	14,096
Nonregulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	14	14
Nonregulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 341	$ 317

Property, Plant and Equipment_2

Property, Plant and Equipment - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Property, Plant and Equipment [Abstract]
Interest costs capitalized	$ 115	$ 53	$ 33
Accrued liabilities for property, plant and equipment additions	653	481	297
Tangible asset impairment charges	6	11	20
Depreciation	$ 1,143	$ 1,071	$ 1,001

Asset Retirement Obligations -

Asset Retirement Obligations - Reconciliation of ARO (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 273	$ 253
Liabilities settled during the year	(1)	(1)
Liabilities incurred during the year	12	13
Accretion expense	15	14
Revisions in estimated cash flows	7	(6)
Ending Balance	$ 306	$ 273

Asset Retirement Obligations _2

Asset Retirement Obligations - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted cash	$ 3	$ 3

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Debt Instrument [Line Items]
Unamortized debt issuance costs and discount	$ (53)	$ (76)
Total Debt including with affiliate	10,596	8,627
Less: debt due within one year, included in current liabilities	612	412
Total Non-current Debt including with affiliate	9,984	8,215
First mortgage bonds - fixed
Debt Instrument [Line Items]
Long-term debt	3,316	$ 2,882
Bond pledged as collateral	$ 8,906
First mortgage bonds - fixed | Min.
Debt Instrument [Line Items]
Interest rate	1.85%	1.85%
First mortgage bonds - fixed | Max.
Debt Instrument [Line Items]
Interest rate	8%	8%
Unsecured pollution control notes - fixed
Debt Instrument [Line Items]
Long-term debt	$ 545	$ 545
Unsecured pollution control notes - fixed | Min.
Debt Instrument [Line Items]
Interest rate	1.40%	1.40%
Unsecured pollution control notes - fixed | Max.
Debt Instrument [Line Items]
Interest rate	4%	4%
Intragroup Green Loan
Debt Instrument [Line Items]
Long-term debt	$ 800	$ 0
Interest rate	5.45%
Other various non-current debt - fixed
Debt Instrument [Line Items]
Long-term debt	$ 5,988	$ 5,276
Other various non-current debt - fixed | Min.
Debt Instrument [Line Items]
Interest rate	1.95%	1.95%
Other various non-current debt - fixed | Max.
Debt Instrument [Line Items]
Interest rate	6.66%	6.66%

Debt - 2023 Long-Term Debt Issu

Debt - 2023 Long-Term Debt Issuance (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 13, 2023	Oct. 02, 2023	Aug. 08, 2023	Jul. 19, 2023	Jul. 03, 2023
Tax Exempt Bond | NYSEG | 4.00% Tax Exempt Bond Due 2034
Debt Instrument [Line Items]
Debt instrument principal amount						$ 100
Interest rate						4%
Tax Exempt Bond | UI | 4.50% Tax Exempt Bond Due 2033
Debt Instrument [Line Items]
Debt instrument principal amount			$ 64
Interest rate			4.50%
Green 144A Bond | NYSEG | 5.65% Green Public Bond Due 2028
Debt Instrument [Line Items]
Debt instrument principal amount				$ 350
Interest rate				5.65%
Green 144A Bond | NYSEG | 5.85% Green Public Bond Due 2033
Debt Instrument [Line Items]
Debt instrument principal amount				$ 400
Interest rate				5.85%
Green Private Bond | UI | 6.09% Green Private Bond Due 2034
Debt Instrument [Line Items]
Debt instrument principal amount		$ 156
Interest rate		6.09%
Green Private Bond | UI | 6.29% Green Private Bond Due 2038
Debt Instrument [Line Items]
Debt instrument principal amount		$ 34
Interest rate		6.29%
Green Private Bond | RG&E | 5.62% Green Private Bond Due 2028
Debt Instrument [Line Items]
Debt instrument principal amount		$ 100
Interest rate		5.62%
Green Private Bond | RG&E | 5.89% Green Private Bond Due 2034
Debt Instrument [Line Items]
Debt instrument principal amount		$ 25
Interest rate		5.89%
Green Private Bond | RG&E | 5.99% Green Private Bond Due 2036
Debt Instrument [Line Items]
Debt instrument principal amount		$ 50
Interest rate		5.99%
Green Private Bond | RG&E | 6.22% Green Private Bond Due 2053
Debt Instrument [Line Items]
Debt instrument principal amount		$ 75
Interest rate		6.22%
Green Private Bond | CMP | 5.65% Green Private Bond Due 2029
Debt Instrument [Line Items]
Debt instrument principal amount		$ 55
Interest rate		5.65%
Green Private Bond | CMP | 6.04% Green Private Bond Due 2038
Debt Instrument [Line Items]
Debt instrument principal amount		$ 70
Interest rate		6.04%
Private Bond | CNG | 6.20% Private Bond Due 2032
Debt Instrument [Line Items]
Debt instrument principal amount		$ 36
Interest rate		6.20%
Private Bond | CNG | 6.49% Private Bond Due 2038
Debt Instrument [Line Items]
Debt instrument principal amount		$ 19
Interest rate		6.49%
Private Bond | SCG | 6.04% 2 Private Bond Due 2034
Debt Instrument [Line Items]
Debt instrument principal amount		$ 30
Interest rate		6.04%
Private Bond | SCG | 6.24% Private Bond Due 2038
Debt Instrument [Line Items]
Debt instrument principal amount		$ 30
Interest rate		6.24%
Intragroup Green Loan
Debt Instrument [Line Items]
Interest rate	5.45%
Intragroup Green Loan | 5.45% Intragroup Green Loan Due 2033
Debt Instrument [Line Items]
Debt instrument principal amount					$ 800
Interest rate					5.45%

Debt - Schedule of Long-term _2

Debt - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2023 USD ($)
Debt Disclosure [Abstract]
2024	$ 612
2025	1,107
2026	660
2027	484
2028	716
Total	$ 3,579

Debt - Additional Information (

Debt - Additional Information (Details)		12 Months Ended
	Nov. 23, 2021 USD ($)	Dec. 31, 2023 USD ($)	Jul. 19, 2023 USD ($)	Jun. 18, 2023 USD ($)	Dec. 31, 2022 USD ($)	Nov. 22, 2021 USD ($)
Debt Instrument [Line Items]
Estimated fair value of debt		$ 10,266,000,000			$ 7,991,000,000
Commercial paper		1,332,000,000			397,000,000
Notes payable under supplier financing arrangements		0			$ 171,000,000
Supplier finance program, obligation, confirmed amount		4,000,000
Payment of notes payable		$ 175,000,000
Supplier financing arrangement, weighted average interest rate					5.48%
Supplier Finance Program, Obligation, Statement of Financial Position [Extensible Enumeration]		Notes payable			Notes payable
Nonrelated Party
Debt Instrument [Line Items]
Notes payable		$ 1,347,000,000			$ 566,000,000
Related Party
Debt Instrument [Line Items]
Notes payable		$ 13,000,000			2,000,000
Related Party | Iberdrola Financiacion S A U
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity			$ 750,000,000	$ 500,000,000
Credit facility fees percentage		0.225%
Credit facility amount drawn		$ 0			0
Commercial Paper
Debt Instrument [Line Items]
Weighted-average interest rate		5.65%
Subordinated Debt | Intragroup Green Loan
Debt Instrument [Line Items]
Debt instrument principal amount			$ 800,000,000
Weighted-average interest rate			5.45%
AVANGRID Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 3,575,000,000
Debt covenant, ratio of consolidated debt to consolidated total capitalization	0.65
Line of credit borrowing outstanding		0			$ 0
Line of credit facility, current borrowing capacity		2,233,000,000
AVANGRID Credit Facility | Min.
Debt Instrument [Line Items]
Credit facility fees percentage	0.10%
AVANGRID Credit Facility | Max.
Debt Instrument [Line Items]
Credit facility fees percentage	0.225%
AVANGRID Credit Facility | Commercial Paper
Debt Instrument [Line Items]
Commercial paper		$ 2,000,000,000
AVANGRID Credit Facility Sublimit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 2,500,000,000					$ 1,500,000,000

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Restricted cash	$ 393	$ 413
Restricted Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 3	$ 3
RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of electric load obligations using contracts for a NYISO location	70%
NYSEG and RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of natural gas load obligations hedged	55%

Fair Value of Financial Instr_4

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	$ 45	$ 48
Netting adjustment	(81)	(222)
Derivative assets	230	200
Netting adjustment	172	394
Derivative liabilities	(175)	(297)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(69)	(177)
Derivative assets	102	80
Netting adjustment	135	364
Derivative liabilities	(43)	(125)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(12)	(45)
Derivative assets	5	3
Netting adjustment	37	30
Derivative liabilities	(1)	0
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	1	1
Netting adjustment	0	0
Derivative liabilities	(39)	(57)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	122	116
Netting adjustment	0	0
Derivative liabilities	(92)	(115)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	29	35
Derivative assets, before netting	15	38
Derivative liabilities, before netting	(49)	(50)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	15	37
Derivative liabilities, before netting	(37)	(46)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	1
Derivative liabilities, before netting	(12)	(4)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 1 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	16	13
Derivative assets, before netting	181	218
Derivative liabilities, before netting	(219)	(491)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	42	55
Derivative liabilities, before netting	(101)	(350)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	17	47
Derivative liabilities, before netting	(26)	(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	122	116
Derivative liabilities, before netting	(92)	(115)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	0	0
Derivative assets, before netting	115	166
Derivative liabilities, before netting	(79)	(150)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	114	165
Derivative liabilities, before netting	(40)	(93)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	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	(39)	(57)
Level 3 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	$ 0	$ 0

Fair Value of Financial Instr_5

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value as of January 1,	$ 16	$ (69)	$ 13
Gains for the year recognized in operating revenues	10	108	21
Losses for the year recognized in operating revenues	$ (22)	$ (30)	$ (34)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Unobservable Input Reconciliation, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating Revenues	Operating Revenues	Operating Revenues
Total gains or losses for the period recognized in operating revenues	$ (12)	$ 78	$ (13)
Gains recognized in OCI	7	2	2
Losses recognized in OCI	(8)	(57)	(52)
Total gains or losses recognized in OCI	$ (1)	$ (55)	$ (50)
Fair Value, Recurring Basis Unobservable Input Reconciliation, Net Derivative Asset (Liability), Gain (Loss), Statement Of Other Comprehensive Income, Extensible List Not Disclosed Flag	Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes of $6, $0 and $(44), respectively	Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes of $6, $0 and $(44), respectively	Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes of $6, $0 and $(44), respectively
Net change recognized in regulatory assets and liabilities	$ 18	$ 17	$ 13
Purchases	90	10	(17)
Settlements	(87)	8	(13)
Transfers out of Level 3	12	27	(2)
Fair value as of December 31,	36	16	(69)
(Losses) 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	$ (12)	$ 78	$ (13)
Fair Value, Net Derivative Asset (Liability), Recurring Basis, Still Held, Unrealized Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating Revenues	Operating Revenues	Operating Revenues

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price	Dec. 31, 2023 $ / MWh $ / MMBTU
NYMEX | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	4.44
NYMEX | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	9.86
NYMEX | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	1.99
AECO | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	3.11
AECO | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	10.80
AECO | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	1
Ameren | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	53.73
Ameren | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	225.62
Ameren | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	20.92
COB | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	81.30
COB | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	400.10
COB | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	10.85
ComEd | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	48.92
ComEd | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	222.49
ComEd | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	16.77
ERCOT S hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	50.77
ERCOT S hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	320.63
ERCOT S hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	16.85
Mid C | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	78.47
Mid C | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	400.10
Mid C | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	7.85
AEP-DAYTON hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	54.53
AEP-DAYTON hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	229.75
AEP-DAYTON hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	22.50
PJM W hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	57.22
PJM W hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	227.60
PJM W hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	21.61

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details) - Contracts for differences - Level 3	Dec. 31, 2023 $ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	0.0042
Min. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	0.0384
Min. | Forward pricing
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	2
Max. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	0.0052
Max. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	0.0401
Max. | Forward pricing
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Derivative measurement input	2.61

Derivative Instruments and He_3

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	$ 230	$ 200
Derivative liabilities	(175)	(297)
Cash collateral (payable) receivable, asset	(63)	(97)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	1	0
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	1	0
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	13	30
Derivative liabilities	(12)	(30)
Derivative assets	1	0
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative assets	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	0	1
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	0	1
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	8
Derivative liabilities	(3)	(7)
Derivative assets	0	1
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative assets	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(45)	(28)
Cash collateral (payable) receivable, liability	27	11
Total derivatives as presented in the balance sheet	(18)	(17)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	12	30
Derivative liabilities	(57)	(58)
Derivative liabilities	(45)	(28)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative liabilities	0	0
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(29)	(43)
Cash collateral (payable) receivable, liability	7	2
Total derivatives as presented in the balance sheet	(22)	(41)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	7
Derivative liabilities	(32)	(50)
Derivative liabilities	(29)	(43)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative liabilities	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	67	60
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	67	60
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	53	121
Derivative liabilities	0	(61)
Derivative assets	53	60
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	15	0
Derivative liabilities	(1)	0
Derivative assets	14	0
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	162	139
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	162	139
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	52	63
Derivative liabilities	(3)	(40)
Derivative assets	49	23
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	113	116
Derivative liabilities	0	0
Derivative assets	113	116
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(60)	(192)
Cash collateral (payable) receivable, liability	43	105
Total derivatives as presented in the balance sheet	(17)	(87)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	53	79
Derivative liabilities	(73)	(103)
Derivative liabilities	(20)	(24)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	7	0
Derivative liabilities	(47)	(168)
Derivative liabilities	(40)	(168)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(39)	(91)
Cash collateral (payable) receivable, liability	13	54
Total derivatives as presented in the balance sheet	(26)	(37)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	4
Derivative liabilities	(4)	(7)
Derivative liabilities	(3)	(3)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	1
Derivative liabilities	(37)	(89)
Derivative liabilities	$ (36)	$ (88)

Derivative Instruments and He_4

Derivative Instruments and Hedging - Net Notional Volume (Details) MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) MWh MMBTU	Dec. 31, 2022 USD ($) MMBTU MWh
Networks | Wholesale electricity purchase contracts (MWh) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	5.6	5.7
Networks | Natural gas purchase contracts (Dth) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	10.7	9.6
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value | $	$ 64	$ (41)
Renewables | Wholesale electricity purchase contracts (MWh) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	1	2
Derivative assets (liabilities), fair value | $	$ 29	$ 149
Renewables | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	6	7
Derivative assets (liabilities), fair value | $	$ 14	$ (200)
Renewables | Natural gas and other fuel purchase contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	21	15
Derivative assets (liabilities), fair value | $	$ 4	$ 2
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	4	6
Derivative assets (liabilities), fair value | $	$ 17	$ 8
Renewables | Basis Swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	24	22
Renewables | Basis Swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	1	0

Derivative Instruments and He_5

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain (loss) on derivatives	$ 0	$ (1)	$ 0
Derivative Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain (loss) on derivatives	18	18	13
Electricity
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	102	(127)	(23)
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	22	9
Electricity | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	0
Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	15	(16)	$ (11)
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	12	4
Natural Gas | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ 0	$ 0

Derivative Instruments and He_6

Derivative Instruments and Hedging - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 USD ($) instrument	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Sep. 15, 2021 USD ($)	Jul. 15, 2021 USD ($)	May 27, 2021 USD ($)	Jun. 20, 2019 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 3,529,000,000	$ 2,768,000,000
Regulatory liabilities	2,955,000,000	3,269,000,000
(Loss) gain recognized in OCI on derivatives	139,000,000	(62,000,000)
Derivative assets	162,000,000	140,000,000
Derivative liability	175,000,000	297,000,000
Derivative collateral obligation to be paid in decrease in credit rating below investment grade	46,000,000
Cash collateral pledged	63,000,000	97,000,000
Collateral already posted, aggregate fair value	$ 34,000,000
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of instruments held | instrument	2
Derivative liability	$ 39,000,000	57,000,000
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	(9,000,000)	(9,000,000)	$ (9,000,000)
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	9,000,000	9,000,000	9,000,000
Cash Flow Hedging | Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	(29,000,000)	(38,000,000)
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	(9,000,000)
Fair Value Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability					$ 750,000,000
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	2,000,000	(3,000,000)
Loss (Gain) Reclassified from Accumulated OCI into Income	4,000,000	1,000,000	3,000,000
Networks | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	4,000,000	4,000,000	4,000,000
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Forward contract to hedge foreign currency exchange risk							$ 100,000,000
(Loss) gain recognized in OCI on derivatives	(4,000,000)	(4,000,000)	(4,000,000)
Expected amortization of discontinued cash flow hedges, next fiscal year	(4,000,000)
Cash flow hedge gain (loss) to be reclassified within twelve months	(5,000,000)
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	39,000,000	43,000,000
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives			(200,000,000)
Loss (Gain) Reclassified from Accumulated OCI into Income	169,000,000	59,000,000	(3,000,000)
Renewables | Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	122,000,000	116,000,000	(58,000,000)
Loss (Gain) Reclassified from Accumulated OCI into Income	0	0	$ 0
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	(41,000,000)
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount				$ 956,000,000		$ 935,000,000
Derivative assets	$ 122,000,000	116,000,000
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	20%
Derivative assets	$ 1,000,000	1,000,000
Regulatory assets	38,000,000	56,000,000
Derivative liabilities	39,000,000	57,000,000
Regulatory liabilities	$ 0	0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	80%
Derivative assets	$ 0	0
Derivative liabilities	$ 38,000,000	$ 55,000,000

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging relationships on OCI and Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	$ 139	$ (62)
Interest expense	409	303	$ 298
Purchased power, natural gas and fuel used	2,429	2,456	1,719
Operating revenues	8,309	7,923	6,974
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	2	(3)
Loss (Gain) Reclassified from Accumulated OCI into Income	4	1	3
Operating revenues	6,855	6,782	5,754
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives			(200)
Loss (Gain) Reclassified from Accumulated OCI into Income	169	59	(3)
Operating revenues	1,456	1,141	1,220
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	9	9	9
Interest rate contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	4	4	4
Interest rate contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	122	116	(58)
Loss (Gain) Reclassified from Accumulated OCI into Income	0	0	0
Interest expense	409	303	298
Commodity contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	0	2	2
Loss (Gain) Reclassified from Accumulated OCI into Income	0	(3)	(1)
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives	17	(178)	(142)
Loss (Gain) Reclassified from Accumulated OCI into Income	169	59	(3)
Operating revenues	$ 8,309	7,923	6,974
Foreign currency exchange contracts | Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) gain recognized in OCI on derivatives		$ 0	$ (5)

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 64	$ (41)
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	17	8
Long | Wholesale electricity purchase contracts (MWh)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	29	149
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	4	2
Short | Wholesale electricity purchase contracts (MWh)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 14	$ (200)

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non Trading Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Operating revenues	$ 8,309	$ 7,923	$ 6,974
Purchased power, natural gas and fuel used	2,429	2,456	1,719
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,456	1,141	1,220
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	58	12	2
Renewables | Trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 58	$ 12	$ 2
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Trading | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 0	$ 0	$ 0
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Long | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ (8)	$ 9	$ 1
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Long | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Trading | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	71	1	(2)
Renewables | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(5)	1	4
Renewables | Trading | Financial and natural gas contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	1	(1)
Renewables | Trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(37)	(12)	(57)
Operating revenues	8,309	7,923	6,974
Purchased power, natural gas and fuel used	2,429	2,456	1,719
Renewables | Non-trading | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 113	$ (115)	$ (101)
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Operating revenues	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Non-trading | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ (150)	$ 103	$ 44
Derivative, Gain (Loss), Statement of Income or Comprehensive Income [Extensible Enumeration]	Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used	Operating revenues, Purchased power, natural gas and fuel used
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Long | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ (5)	$ 6	$ (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]
Total Gain (Loss)	(109)	98	32
Renewables | Non-trading | Wholesale electricity purchase contracts (MWh) | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	67	(63)	(33)
Renewables | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	41	(52)	(42)
Renewables | Non-trading | Financial and natural gas contracts | Operating Revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	10	(6)	(25)
Renewables | Non-trading | Financial and natural gas contracts | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ (41)	$ 5	$ 12

Derivative Instruments and H_10

Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Recognized in Income Statement	$ 31	$ 6
Current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(26)	(29)
Non-current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(63)	(86)
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	0	29
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	89	86
Fair Value Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Year to date total per Income Statement	$ 409	$ 303

Leases - Narrative (Details)

Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Lessee, Lease, Description [Line Items]
Renewal term	40 years
Finance lease liabilities	$ 81	$ 87
Renewables
Lessee, Lease, Description [Line Items]
Finance lease liabilities	$ 39	$ 41
Finance lease term	15 years
Early buyout option term	10 years
Renewables | Generation Facility
Lessee, Lease, Description [Line Items]
Useful life of facility	25 years
Min.
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Max.
Lessee, Lease, Description [Line Items]
Remaining lease term	50 years

Leases - Lease Cost (Details)

Leases - Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Finance lease cost
Amortization of right-of-use assets	$ 11	$ 12	$ 8
Interest on lease liabilities	3	3	3
Total finance lease cost	14	15	11
Operating lease cost	18	20	14
Short-term lease cost	8	6	4
Variable lease cost	3	3	4
Total lease cost	$ 43	$ 44	$ 33

Leases - Supplemental Balance S

Leases - Supplemental Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Operating Leases
Operating lease right-of-use assets	$ 195	$ 159
Operating lease liabilities, current	16	13
Operating lease liabilities, long-term	199	161
Total operating lease liabilities	215	174
Finance Leases
Other assets	$ 132	$ 143
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other	Other
Other current liabilities	$ 28	$ 7
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Other non-current liabilities	$ 53	$ 80
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Total finance lease liabilities	$ 81	$ 87
Weighted-average Remaining Lease Term (years)
Finance leases	5 years 7 months 6 days	6 years 4 months 24 days
Operating leases	20 years 9 months 18 days	16 years 10 months 24 days
Weighted-average Discount Rate
Finance leases	3.39%	3.46%
Operating leases	4.19%	3.69%

Leases - Supplemental Cash Flow

Leases - Supplemental Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 16	$ 14	$ 16
Operating cash flows from finance leases	3	1	3
Financing cash flows from finance leases	6	9	6
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	0	(1)	0
Operating leases	$ 55	$ 25	$ 10

Leases - Lease Maturities (Deta

Leases - Lease Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Finance Leases
2024	$ 30
2025	8
2026	9
2027	10
2028	19
Thereafter	14
Total lease payments	90
Less: imputed interest	(9)
Total	81	$ 87
Operating Leases
2024	21
2025	17
2026	17
2027	19
2028	16
Thereafter	257
Total lease payments	346
Less: imputed interest	(131)
Total	$ 215	$ 174

Commitments and Contingent Li_3

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

1 Months Ended

12 Months Ended

36 Months Ended

Oct. 02, 2023 USD ($)

Jul. 13, 2023 USD ($)

Apr. 29, 2016

Jul. 31, 2014

Dec. 26, 2012

Sep. 30, 2011

Jun. 30, 2020 project

Dec. 31, 2023 USD ($) MW

Dec. 31, 2023 USD ($)

Jun. 16, 2023 USD ($)

May 04, 2021 USD ($)

Jan. 04, 2021 USD ($)

Loss Contingencies [Line Items]

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

2

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

$ 1

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

$ 911

$ 911

Future payments committed

$ 90

NECEC commitment, payment during period

$ 10

Power purchase commitments | Hydro Capacity And Energy

Loss Contingencies [Line Items]

Power purchase commitment | MW

95.6

Period of purchase commitment

3 years

Power Sales Commitments | Hydro Capacity And Energy

Loss Contingencies [Line Items]

Power purchase commitment | MW

150

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

$ 31

Commonwealth Wind and Park City PPAs

Loss Contingencies [Line Items]

Termination payment

$ 16

$ 48

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Requested return on equity base percentage

9.20%

Unfavorable Regulatory Action | Complaint II

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.70%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.84%

Unfavorable Regulatory Action | Complaint IV

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.61%

Unfavorable Regulatory Action | Complaint IV | Max.

Loss Contingencies [Line Items]

Requested return on equity base percentage

11.24%

Commitments and Contingent Li_4

Commitments and Contingent Liabilities - Schedule of Forward Purchases and Sales Commitments Under Power, Gas, and Other Arrangements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($)
Purchases
2024	$ 1,513
2025	246
2026	116
2027	83
2028	51
Thereafter	1,005
Totals	3,014
Sales
2024	285
2025	161
2026	58
2027	34
2028	6
Thereafter	56
Totals	$ 600

Environmental Liabilities (Deta

Environmental Liabilities (Details)	12 Months Ended			89 Months Ended
	Dec. 31, 2023 USD ($) site	Dec. 31, 2011 site	Dec. 31, 2008 site	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)	Aug. 04, 2016 USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	24
Number of 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, 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			19,000,000	$ 19,000,000
Environmental liabilities, cost of investigation and remediation | $						$ 30,000,000
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	16
Number of sites where gas was manufactured in the past	6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	2
Number of sites where gas was manufactured in the past	0
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with liability recorded	6
Number of sites where gas was manufactured in the past	2
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	5
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 6,000,000			6,000,000
New York Voluntary Cleanup Programs
Environmental Exit Cost [Line Items]
Number of sites note expected to incur additional liabilities	18
Number of sites where gas was manufactured in the past	39
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 10,000,000			10,000,000
Another Ten Sites | Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	15,000,000			15,000,000
Another Ten Sites | Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 22,000,000			22,000,000
Sites With Individual NYSDEC Orders Of Consent
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past	2
Maines Voluntary Response Action Programs
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past	2
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 112,000,000			112,000,000	112,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	122,000,000			122,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	218,000,000			218,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	0			0
Inactive Manufactured Gas Plants
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	250,000,000			250,000,000	$ 289,000,000
Inactive Manufactured Gas Plants | FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute			2
NYSEG | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	8,000,000			8,000,000
RG&E | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 6,000,000			$ 6,000,000

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Income Taxes [Line Items]
Corporate alternative minimum tax, payment amount	$ 32
Corporate alternative minimum tax, gross initial obligation amount	129
Corporate alternative minimum tax, credit utilization amount	97
Corporate alternative minimum tax, carryforward asset, amount	129
Deferred tax assets, valuation allowance	82	$ 87
Decrease of validation allowance	5
Unrecognized tax benefits that would impact effective tax rate	109
Unrecognized tax benefits, various state uncertainties under appear expected to resolve within next twelve months, that would Impact effective tax rate	83
Production tax credits transfer agreement, cash received	81
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	4,700
Operating loss and tax credit carryforward, valuation allowance	3
Federal | Renewable Energy and Investment
Income Taxes [Line Items]
Tax credit carry forward	948
State
Income Taxes [Line Items]
Net operating loss carry forwards	401
Tax credit carry forward	145
Operating loss and tax credit carryforward, valuation allowance	$ 79

Income Taxes - Schedule of Curr

Income Taxes - Schedule of Current and Deferred Taxes Charged to (Benefit) Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Current
Federal	$ 36	$ 0	$ 6
State	(1)	2	4
Current taxes charged to expense	35	2	10
Deferred
Federal	62	67	49
State	(8)	49	72
Deferred taxes charged to expense	54	116	121
Production tax credits	(97)	(97)	(109)
Investment tax credits	(1)	(1)	(1)
Total Income Tax (Benefit) Expense	$ (9)	$ 20	$ 21

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 138	$ 176	$ 140
Depreciation and amortization not normalized	(27)	(20)	(19)
Investment tax credit amortization	(1)	(1)	(1)
Tax return related adjustments	(4)	2	0
Production tax credits	(97)	(97)	(109)
Tax equity financing arrangements	26	13	14
State tax (benefit) expense, net of federal effect	(7)	40	61
Excess ADIT amortization	(35)	(66)	(65)
Valuation allowance	0	(35)	21
Other, net	(2)	8	(21)
Total Income Tax (Benefit) Expense	$ (9)	$ 20	$ 21

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Deferred Income Tax Liabilities (Assets)
Property related	$ 4,650	$ 4,504
Unfunded future income taxes	141	129
Federal and state tax credits	(986)	(942)
Federal and state NOL’s	(1,308)	(1,086)
Joint ventures/partnerships	244	210
Nontaxable grant revenue	(250)	(270)
Tax Act - tax on regulatory remeasurement	(317)	(328)
Valuation allowance	82	87
Other	180
Other		(91)
Deferred tax assets	2,861	2,717
Deferred Tax Liabilities, Gross	5,297	4,930
Deferred Tax Liabilities, Net	$ 2,436	$ 2,213

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning Balance	$ 127	$ 127	$ 127
Increases for tax positions related to prior years	7	2	3
Increases for tax positions related to current year	0	2	0
Decreases for tax positions related to prior years	(4)	(4)	(3)
Ending Balance	$ 130	$ 127	$ 127

Post-Retirement and Similar O_3

Post-Retirement and Similar Obligations - Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	$ 2,452	$ 3,487
Service cost	6	27
Interest cost	121	111
Plan amendments	0	1
Actuarial loss (gain)	131	(716)
Curtailments/Settlements	(2)	(274)
Benefits paid	(208)	(184)
Benefit Obligation as of December 31,	2,500	2,452
Change in plan assets
Fair Value of Plan Assets as of January 1,	2,151	3,079
Actual return on plan assets	204	(584)
Employer contributions	14	22
Settlements	(2)	(182)
Benefits paid	(208)	(184)
Fair Value of Plan Assets as of December 31,	2,159	2,151
Funded Status as of December 31,	(341)	(301)
Postretirement Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	284	408
Service cost	1	2
Interest cost	14	10
Plan amendments	0	0
Actuarial loss (gain)	36	(103)
Curtailments/Settlements	0	0
Benefits paid	(34)	(33)
Benefit Obligation as of December 31,	301	284
Change in plan assets
Fair Value of Plan Assets as of January 1,	89	127
Actual return on plan assets	12	(22)
Employer contributions	16	17
Settlements	0	0
Benefits paid	(34)	(33)
Fair Value of Plan Assets as of December 31,	83	89
Funded Status as of December 31,	$ (218)	$ (195)

Post-Retirement and Similar O_4

Post-Retirement and Similar Obligations - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2023 USD ($) trust	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Amortization period	10 years
Other current and other non-current liabilities	$ 41	$ 44
Annual contributions made	84	68	$ 58
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	131	(716)
Actuarial gains (losses) due to change in discount rates	(112)	644
Reduction of benefit obligation from settlement and curtailment	2	274
Settlements		182
Curtailments		92
Expected contribution for pension benefit plans during next fiscal year	28
Other current and other non-current liabilities	$ 341	301
Plan assets, number of trust | trust	1
Pension Benefits | Return-Seeking assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	15%
Pension Benefits | Return-Seeking assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	70%
Pension Benefits | Liability-Hedging assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	30%
Pension Benefits | Liability-Hedging assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	85%
Pension Benefits | Equity Securities | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation				49%
Pension Benefits | Equity Securities | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation				69%
Pension Benefits | Fixed Income Investments | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation				31%
Pension Benefits | Fixed Income Investments | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation				51%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	$ 36	(103)
Actuarial gains (losses) due to change in discount rates	(12)	70
Reduction of benefit obligation from settlement and curtailment	0	0
Expected contribution for pension benefit plans during next fiscal year	8
Other current and other non-current liabilities	$ 218	$ 195
Plan assets, number of trust | trust	1
Postretirement Benefits | VEBA and 401(h) arrangements
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	62%

Post-Retirement and Similar O_5

Post-Retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Total	$ (41)	$ (44)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	0	0
Non-current liabilities	(341)	(301)
Total	(341)	(301)
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(213)	(190)
Total	$ (218)	$ (195)

Post-Retirement and Similar O_6

Post-Retirement and Similar Obligations - Summary of Recognized as Regulatory Assets or Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 251	$ 181
Prior service cost (credit)	6	7
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	(52)	(91)
Prior service cost (credit)	$ (1)	$ (1)

Post-Retirement and Similar O_7

Post-Retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 11	$ 12
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ (4)	$ (6)

Post-Retirement and Similar O_8

Post-Retirement and Similar Obligations - Schedule of Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Retirement Benefits [Abstract]
Projected benefit obligation	$ 2,500	$ 2,452
Fair value of plan assets	2,159	2,151
Accumulated benefit obligation	2,479	2,429
Fair value of plan assets	$ 2,159	$ 2,151

Post-Retirement and Similar O_9

Post-Retirement and Similar Obligations - Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations Recognized (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Net Periodic Benefit Cost:
Service cost	$ 6	$ 27
Interest cost	121	111
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	11	12
Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	1	2
Interest cost	14	10
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	(4)	(6)
Networks | Pension Benefits
Net Periodic Benefit Cost:
Service cost	5	26	$ 39
Interest cost	119	109	86
Expected return on plan assets	(143)	(162)	(199)
Amortization of prior service cost (benefit)	1	1	2
Amortization of net loss	3	49	115
Settlement/Curtailment charge	0	17	6
Curtailment charge	0	(32)	0
Net Periodic Benefit Cost	(15)	8	49
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	0	(59)	0
Settlement charge	0	(17)	(6)
Net loss (gain)	73	33	(218)
Amortization of net loss	(3)	(49)	(115)
Current year prior service cost (credit)	0	1	2
Amortization of prior service (cost) benefit	(1)	(1)	(2)
Net loss (gain)	69	(92)	(339)
Total Recognized	54	(84)	(290)
Networks | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	1	2	3
Interest cost	14	10	10
Expected return on plan assets	(5)	(6)	(7)
Amortization of prior service cost (benefit)	0	(1)	(5)
Amortization of net loss	(12)	(4)	2
Settlement/Curtailment charge	0	0	0
Curtailment charge	0	0	0
Net Periodic Benefit Cost	(2)	1	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	0	0	0
Settlement charge	0	0	0
Net loss (gain)	26	(75)	(31)
Amortization of net loss	12	4	(2)
Current year prior service cost (credit)	0	0	1
Amortization of prior service (cost) benefit	0	1	5
Net loss (gain)	38	(70)	(27)
Total Recognized	36	(69)	(24)
ARHI | Pension Benefits
Net Periodic Benefit Cost:
Service cost	1	1	1
Interest cost	2	2	1
Expected return on plan assets	(2)	(2)	(2)
Amortization of net loss	0	1	2
Settlement/Curtailment charge	1	1	1
Net Periodic Benefit Cost	2	3	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlement charge	(1)	(1)	(1)
Net loss (gain)	0	(1)	(3)
Amortization of net loss	0	(1)	(2)
Amortization of prior service (cost) benefit	0	0	0
Net loss (gain)	(1)	(3)	(6)
Total Recognized	1	0	(3)
ARHI | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	0	0	0
Interest cost	0	0	0
Expected return on plan assets	0	0	0
Amortization of net loss	(1)	(1)	(1)
Settlement/Curtailment charge	0	0	0
Net Periodic Benefit Cost	(1)	(1)	(1)
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlement charge	(1)	(1)	(1)
Net loss (gain)	1	(1)	1
Amortization of net loss	1	1	1
Amortization of prior service (cost) benefit	0	0	0
Net loss (gain)	1	(1)	1
Total Recognized	$ 0	$ (2)	$ 0

Post-Retirement and Similar _10

Post-Retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Details)	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	4.69%	5.18%
Rate of compensation increase - benefit obligations	2.60%	2.99%
Interest crediting rate	3.37%	2.87%
Discount rate - net periodic benefit	5.18%	2.85%	2.34%
Expected long-term return on plan assets	6.35%	6.33%	7.30%
Rate of compensation increase - net periodic benefit	2.99%	3.53%	3.52%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	4.66%	5.12%
Rate of compensation increase - benefit obligations	3%	3%
Discount rate - net periodic benefit	5.12%	2.66%	2.19%
Expected long-term return on plan assets	5.61%	4.66%	4.05%
Rate of compensation increase - net periodic benefit	3%	3.50%	3.50%

Post-Retirement and Similar _11

Post-Retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Details)	Dec. 31, 2023	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
Min.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	6.20%	5%
Max.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	8.60%	6.50%

Post-Retirement and Similar _12

Post-Retirement and Similar Obligations - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2023 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	$ 235
2025	221
2026	216
2027	210
2028	204
2029 - 2033	918
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2024	28
2025	28
2026	27
2027	26
2028	25
2029 - 2033	109
Medicare Act Subsidy Receipts
Defined Benefit Plan Disclosure [Line Items]
2024	0
2025	0
2026	0
2027	0
2028	0
2029 - 2033	$ 2

Post-Retirement and Similar _13

Post-Retirement and Similar Obligations - Fair Values of Pension Plan Assets by Asset Category (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 2,159	$ 2,151	$ 3,079
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,982	1,678
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	63	51
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	295	252
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	58	57
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	106	104
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	746	708
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		1
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	708	472
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	6	33
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	459	414
Pension Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	295	252
Pension Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	58	57
Pension Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	106	104
Pension Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		1
Pension Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,523	1,264
Pension Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	63	51
Pension Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	746	708
Pension Benefits | Level 2 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		0
Pension Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	708	472
Pension Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	6	33
Pension Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount		0
Pension Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	177	473
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	83	89	$ 127
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	81	87
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	2	2
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	61	69
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	3
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	4
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	8	8
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	63	70
Postretirement Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Postretirement Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	61	69
Postretirement Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	18	17
Postretirement Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	2	2
Postretirement Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	3
Postretirement Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	4
Postretirement Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	8	8
Postretirement Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 2	$ 2

Equity - Additional Information

Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Class of Stock [Line Items]
Common stock held in trust (in shares)	103,889	108,188
Release of common stock held in trust (in shares)	4,299	4,355
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01
Number of shares repurchased during period (in shares)	0
Treasury shares (in shares)	997,983
Repurchases of common stock	$ 47	$ 47
Convertible Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares outstanding (in shares)	0	0
Common Stock
Class of Stock [Line Items]
Issuance of common stock (in shares)	138,030	56,127
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent	81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	$ 20,342	$ 19,961	$ 15,826
Change	155	93	(162)
Balance at end of period	20,676	20,342	19,961
Loss (gain) for defined benefit plans, income taxes	0	3	0
Amortization of pension cost, income taxes	0	1	(1)
Unrealized (loss) gain from equity method investment, income tax (benefit) expense	1	6	(3)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax (benefit) expense	6	0	(44)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense	48	19	(3)
Loss (gain) for defined benefit plans, net of income tax expense
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period
Change	0	14	2
Balance at end of period
Amortization of pension cost, net of income tax (benefit) expense
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period
Change	(1)	4	(8)
Balance at end of period
Net gain (loss) on pension plans
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(20)	(38)	(32)
Change	(1)	18	(6)
Balance at end of period	(21)	(20)	(38)
Unrealized (loss) gain from equity method investment, net of income tax (benefit) expense
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	13	(9)	0
Change	5	22	(9)
Balance at end of period	18	13	(9)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax (benefit) expense
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(195)	(194)	(35)
Change	17	(1)	(159)
Balance at end of period	(178)	(195)	(194)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	22	(32)	(44)
Change	134	54	12
Balance at end of period	156	22	(32)
Loss on derivatives qualifying as cash flow hedges
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(173)	(226)	(79)
Change	151	53	(147)
Balance at end of period	(22)	(173)	(226)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(180)	(273)	(111)
Change	155	93	(162)
Balance at end of period	$ (25)	$ (180)	$ (273)

Earnings Per Share (Details)

Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Numerator:
Net income attributable to Avangrid, Basic	$ 786	$ 881	$ 707
Net income attributable to Avangrid, Diluted	$ 786	$ 881	$ 707
Denominator:
Weighted average number of shares outstanding - basic (in shares)	386,810,088	386,727,246	358,086,621
Weighted average number of shares outstanding - diluted (in shares)	387,164,874	387,215,785	358,578,608
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic (in dollars per share)	$ 2.03	$ 2.28	$ 1.97
Earnings Per Common Share, Diluted (in dollars per share)	$ 2.03	$ 2.27	$ 1.97

Variable Interest Entities (Det

Variable Interest Entities (Details) - USD ($) $ in Millions							1 Months Ended
	Nov. 21, 2023	Aug. 10, 2022	Jun. 15, 2022	Apr. 29, 2022	Nov. 04, 2021	Sep. 09, 2021	Mar. 31, 2023	Dec. 31, 2023	Dec. 31, 2022
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)								$ 43,989	$ 41,123
Liabilities of variable interest entities (VIEs)								23,313	20,781
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)								2,741	2,853
Liabilities of variable interest entities (VIEs)								$ 174	$ 424
Aeolus VII
Variable Interest Entity [Line Items]
TEF agreement, consideration received from sale of TEF interest						$ 131
TEF agreement, difference between amount received and noncontrolling interest recognized						8
TEF agreement, noncontrolling interest recognized from sale of TEF interest						$ 139
Aeolus VIII
Variable Interest Entity [Line Items]
TEF agreement, consideration received from sale of TEF interest					$ 199
TEF agreement, consideration received from sale of TEF interest, held in escrow		$ 8
TEF agreement, investment amount received from tax equity investor	$ 124		$ 109
Solis I
Variable Interest Entity [Line Items]
TEF agreement, investment amount received from tax equity investor				$ 14			$ 61

Grants, Government Incentives_3

Grants, Government Incentives and Deferred Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022
Recorded In Deferred Income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	$ 1,062	$ 1,130
Disposals	0	0
Recognized in income	(66)	(68)
Balance at end of period	996	1,062
Recorded As Reduction To Related Utility Plant
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	59	63
Disposals	0	0
Recognized in income	(5)	(4)
Balance at end of period	54	59
Government grants - Renewables | Renewables | Recorded In Deferred Income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	1,060	1,125
Disposals	0	0
Recognized in income	(65)	(65)
Balance at end of period	995	1,060
Government grants - Renewables | Networks | Recorded As Reduction To Related Utility Plant
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	59	63
Disposals	0	0
Recognized in income	(5)	(4)
Balance at end of period	54	59
Other deferred income | Recorded In Deferred Income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	2	5
Disposals	0	0
Recognized in income	(1)	(3)
Balance at end of period	$ 1	$ 2

Equity Method Investments (Deta

Equity Method Investments (Details) $ in Millions		2 Months Ended	12 Months Ended
	Jan. 10, 2022 USD ($)	Dec. 31, 2023 USD ($) jointVenture plant	Dec. 31, 2023 USD ($) jointVenture plant MW	Dec. 31, 2022 USD ($)	Dec. 31, 2021 USD ($) a easement	Oct. 24, 2023 USD ($)	Sep. 15, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 718	$ 718	$ 437
Distribution of earnings from equity method investments			37	41	$ 21
Equity method investment, distributions received in RECs			11	12	11
Undistributed earnings from equity method investees		$ 9	9
Capitalized interest costs			$ 2	0	$ 6
South Dokata Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		15%	15%
Equity method investments		$ 22	$ 22	23
Arizona Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		50%	50%
Equity method investments		$ 77	$ 77	87
Coyote Ridge Wind LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		20%	20%
Equity method investments		$ 16	$ 16	15
Horizon Wind Energy LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		50%	50%
Number of joint ventures | jointVenture		2	2
Flat Rock Wind Power LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 81	$ 81	90
Leased are transmission capacity (in MW) | MW			231
Flat Rock Wind Power II LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments		38	$ 38	$ 42
Leased are transmission capacity (in MW) | MW			91
Vineyard Wind 1
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage	50%			50%	50%
Equity method investments		297	$ 297	$ 9
Number of easements | easement					2
TEF agreement, amount expected from tax equity investors in installments		1,100	1,100			$ 1,200
TEF agreement, amount received from tax equity investors		85
TEF agreement, total indemnified amount		$ 43	43
Equity method investment, capital contribution			$ 287
Vineyard Wind 1 | Lease Area 501
Schedule of Equity Method Investments [Line Items]
Area of land | a					166,886
Vineyard Wind 1 | Lease Area 522
Schedule of Equity Method Investments [Line Items]
Area of land | a					132,370
Joint Venture With CIP
Schedule of Equity Method Investments [Line Items]
Amount of guaranty issued							$ 827
Amount contributed to acquire easement contract, returned					$ 152
Joint Venture With CIP | Letter of Credit
Schedule of Equity Method Investments [Line Items]
Credit facility maximum borrowing capacity							$ 1,200
Joint Venture With CIP | Renewables
Schedule of Equity Method Investments [Line Items]
Joint venture restructuring agreement, payment amount	$ 168
Joint venture restructuring agreement, pretax gain recognized	246
Joint venture restructuring agreement, after tax gain recognized	$ 181
Clearway Energy, Inc
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		50%	50%
Equity method investments		$ 90	$ 90	94
Number of peaking generation plants | plant		2	2
New York TransCo.
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage		20%	20%
Equity method investments		$ 97	$ 97	$ 77
Leased are transmission capacity (in MW) | MW			3,200
Amount funded to date			$ 600

Other Financial Statement Ite_2

Other Financial Statement Items - Schedule of Other Income and (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Allowance for funds used during construction	$ 82	$ 63	$ 88
Carrying costs on regulatory assets	$ 17	$ 16	$ 17
Defined Benefit Plan, Net Periodic Benefit Cost (Credit) Excluding Service Cost, Statement of Income or Comprehensive Income [Extensible Enumeration]	Total Other Income	Total Other Income	Total Other Income
Non-service component of net periodic benefit cost	$ 22	$ (58)	$ (37)
Other	8	9	(8)
Total Other Income	$ 129	$ 30	$ 60

Other Financial Statement Ite_3

Other Financial Statement Items - Schedule of Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Balance Sheet Information [Line Items]
Allowance for credit losses	$ (161)	$ (155)	$ (151)	$ (108)
Nonrelated Party
Supplemental Balance Sheet Information [Line Items]
Trade receivables and unbilled revenues	1,749	1,892
Allowance for credit losses	(161)	(155)
Total Accounts receivable and unbilled revenues, net	$ 1,588	$ 1,737

Other Financial Statement Ite_4

Other Financial Statement Items - Schedule of Change in Allowance For Bad Debts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 155	$ 151	$ 108
Current period provision	137	110	110
Write-off as uncollectible	(131)	(106)	(67)
Ending balance	$ 161	$ 155	$ 151

Other Financial Statement Ite_5

Other Financial Statement Items - Additional Information (Details) $ in Millions	May 13, 2021 USD ($) project	Dec. 31, 2023 USD ($)	Dec. 31, 2022 USD ($)
Sale of Business | Solar Projects In Nevada
Accounts, Notes, Loans and Financing Receivable [Line Items]
Percentage disposed	100%
Number of projects disposed | project	2
Consideration from disposition	$ 35
Gain on disposal, net of tax	11
Pre-tax gain on disposal	$ 15
Deferred Payment Arrangements
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable		$ 110	$ 102
Allowance for credit losses		$ 44	$ 42

Other Financial Statement Ite_6

Other Financial Statement Items - Schedule of Prepayments and Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Balance Sheet Related Disclosures [Abstract]
Prepaid other taxes	$ 142	$ 136
Broker margin and collateral accounts	165	164
Other pledged deposits	32	12
Prepaid expenses	74	68
Other	16	6
Total	$ 429	$ 386

Other Financial Statement Ite_7

Other Financial Statement Items - Schedule of Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Payables and Accruals [Abstract]
Advances received	$ 236	$ 271
Accrued salaries	184	153
Short-term environmental provisions	40	54
Collateral deposits received	128	68
Pension and other postretirement	6	5
Finance leases	28	7
Other	40	35
Total	$ 662	$ 593

Segment Information - Additiona

Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2023 segment
Segment Reporting Information [Line Items]
Number of reportable segments	2
Networks
Segment Reporting Information [Line Items]
Number of reportable segments	1
Number of operating segments	9

Segment Information - By Segmen

Segment Information - By Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting Information [Line Items]
Operating Revenues	$ 8,309	$ 7,923	$ 6,974
Depreciation and amortization	1,158	1,085	1,014
Operating income	930	852	895
Earnings (losses) from equity method investments	6	262	7
Interest expense, net of capitalization	409	303	298
Income tax expense (benefit)	(9)	20	21
Capital expenditures	2,972	2,519	2,976
Adjusted net income	808	901	780
Property, plant and equipment	32,857	30,994
Equity method investments	718	437
Total assets	43,989	41,123
Other
Segment Reporting Information [Line Items]
Operating Revenues	3	1	1
Depreciation and amortization	8	1	1
Operating income	(21)	(13)	(7)
Earnings (losses) from equity method investments	0	0	0
Interest expense, net of capitalization	106	67	80
Income tax expense (benefit)	(83)	40	(29)
Capital expenditures	12	8	2
Adjusted net income	(82)	(130)	(51)
Property, plant and equipment	12	17
Equity method investments	0	0
Total assets	(962)	(499)
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	(5)	(1)	(1)
Networks
Segment Reporting Information [Line Items]
Operating Revenues	6,855	6,782	5,754
Networks | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	5	1	1
Networks | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	6,850	6,781	5,753
Depreciation and amortization	694	660	616
Operating income	996	901	876
Earnings (losses) from equity method investments	15	11	12
Interest expense, net of capitalization	287	220	217
Income tax expense (benefit)	141	94	98
Capital expenditures	2,192	1,803	2,294
Adjusted net income	727	628	661
Property, plant and equipment	21,692	20,027
Equity method investments	186	171
Total assets	30,413	28,069
Renewables
Segment Reporting Information [Line Items]
Operating Revenues	1,456	1,141	1,220
Renewables | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	0	0	0
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	1,456	1,141	1,220
Depreciation and amortization	456	424	397
Operating income	(45)	(36)	26
Earnings (losses) from equity method investments	(9)	251	(5)
Interest expense, net of capitalization	16	16	1
Income tax expense (benefit)	(67)	(114)	(48)
Capital expenditures	768	708	680
Adjusted net income	163	403	$ 170
Property, plant and equipment	11,153	10,950
Equity method investments	532	266
Total assets	$ 14,538	$ 13,553

Segment Information - Reconcili

Segment Information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 808	$ 901	$ 780
Adjustments:
Mark-to-market adjustments - Renewables	21	0	(53)
Impact of COVID-19	0	0	(34)
Merger and other transaction costs	(11)	(4)	(12)
Offshore contract provision	(40)	(24)	0
Accelerated depreciation from repowering	(1)	0	0
Income tax impact of adjustments	8	7	26
Net Income Attributable to Avangrid, Inc.	$ 786	$ 881	$ 707

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Iberdrola, S.A. | Sales
Related Party Transaction [Line Items]
Related party transaction, amount	$ 2	$ 1	$ 0
Iberdrola, S.A. | Purchases
Related Party Transaction [Line Items]
Related party transaction, amount	(45)	(46)	(52)
Iberdrola Renovables Energia, S.L. | Sales
Related Party Transaction [Line Items]
Related party transaction, amount	0	1	0
Iberdrola Renovables Energia, S.L. | Purchases
Related Party Transaction [Line Items]
Related party transaction, amount	(8)	(5)	(10)
Iberdrola Financiación, S.A.U. | Sales
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	0
Iberdrola Financiación, S.A.U. | Purchases
Related Party Transaction [Line Items]
Related party transaction, amount	(36)	(12)	(9)
Vineyard Wind 1 | Sales
Related Party Transaction [Line Items]
Related party transaction, amount	12	7	14
Vineyard Wind 1 | Purchases
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	0
Iberdrola Solutions | Sales
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	7
Iberdrola Solutions | Purchases
Related Party Transaction [Line Items]
Related party transaction, amount	0	0	(39)
Other | Sales
Related Party Transaction [Line Items]
Related party transaction, amount	0	1	2
Other | Purchases
Related Party Transaction [Line Items]
Related party transaction, amount	$ (2)	$ (3)	$ (3)

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - Related Party - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022
Related Party Transaction [Line Items]
Owed By	$ 11	$ 5
Owed To	0	(39)
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	1	1
Owed To	0	(29)
Iberdrola Renovables Energia, S.L.
Related Party Transaction [Line Items]
Owed By	4	0
Owed To	0	0
Iberdrola Financiación, S.A.U.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(799)	(9)
Vineyard Wind 1
Related Party Transaction [Line Items]
Owed By	6	3
Owed To	(8)	(8)
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(6)	(2)
Other
Related Party Transaction [Line Items]
Owed By	4	4
Owed To	$ 0	$ (1)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2023	Jul. 19, 2023	Jun. 18, 2023	Dec. 31, 2022
Related Party
Related Party Transaction [Line Items]
Deposit balance	$ 0			$ 0
Notes payable	13,000,000			2,000,000
Related Party | Iberdrola Solutions, LLC
Related Party Transaction [Line Items]
Notes payable	$ 6,000,000			2,000,000
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%
Credit facility, amount outstanding	$ 0			$ 0
Affiliated Entity
Related Party Transaction [Line Items]
Asset impairment charges	$ 0

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Details) $ / shares in Units, $ in Millions	1 Months Ended																		7 Months Ended	12 Months Ended
	Jan. 31, 2024 shares	Jul. 31, 2023 shares	Mar. 31, 2023 installment shares	Feb. 28, 2023 installment shares	Jan. 31, 2023 shares	Aug. 31, 2022 USD ($)	Jun. 30, 2022 installment $ / shares shares	Mar. 31, 2022 USD ($) shares	Feb. 28, 2022 installment shares	Jan. 31, 2022 $ / shares shares	Jun. 30, 2021 $ / shares shares	Mar. 31, 2021 installment $ / shares shares	Feb. 28, 2021 shares	Dec. 31, 2020 installment	Aug. 31, 2020 installment $ / shares shares	Mar. 31, 2020 installment shares	Feb. 29, 2020 installment shares	Oct. 31, 2018 $ / shares shares	Aug. 31, 2023 USD ($)	Dec. 31, 2023 USD ($) installment $ / shares shares	Dec. 31, 2022 USD ($) installment $ / shares shares	Dec. 31, 2021 USD ($) shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for stock-based compensation plans (in shares)																				2,500,000
Number of shares granted (in shares)																				1,068,326
Number of vesting installments | installment																					3
Grant date fair value (in dollars per share) | $ / shares																				$ 31.54	$ 36.55
Share-based payment award grant date fair value (in dollars per share) | $ / shares																				$ 29.30
Stock-based compensation expense | $																				$ 14	$ 15	$ 18
Income tax benefit recognized for stock-based compensation arrangements | $																				4	$ 4	$ 5
Unrecognized cost for non-vested PSUs | $																				$ 27
Recognition of PSU costs, weighted-average period																				5 years 2 months 12 days
Performance Shares Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)			677,752														208,268			1,067,500	215,235	1,336,787
Number of vesting installments | installment																	3
Number of shares issued (in shares)		125,657						46,737
Share-based payment award options requisite service period																				5 years	4 years
Number of vesting installments | installment			3																	3
Grant date fair value (in dollars per share) | $ / shares																				$ 25.69	$ 36.22
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)							25,000			17,500	17,500	5,000			5,000			8,000
Number of vesting installments | installment							2					1		1	3
Number of shares issued (in shares)			3,642		8,690					9,390	9,390	5,953	1,697
Grant date fair value (in dollars per share) | $ / shares							$ 47.64			$ 48.16	$ 53.59	$ 48.83			$ 48.99
Share-based payment award grant date fair value (in dollars per share) | $ / shares																		$ 47.59
Restricted Stock Units (RSUs) | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued (in shares)	9,034
Phantom Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)				81,000					9,000							167,060
Number of vesting installments | installment				3					4							3
Cash used to settle award | $						$ 0.1		$ 2											$ 0.2
Share based compensation liability | $																				$ 2	$ 0

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Nonvested PSUs and RSUs (Details)	12 Months Ended
	Dec. 31, 2023 $ / shares shares
Number of PSUs and RSUs
Nonvested Balance – beginning of year (in shares) | shares	1,084,951
Granted (in shares) | shares	1,068,326
Forfeited (in shares) | shares	(449,876)
Vested (in shares) | shares	(244,110)
Nonvested Balance – end of year (in shares) | shares	1,459,291
Weighted Average Grant Date Fair Value
Nonvested Balance – beginning of year (in dollars per share) | $ / shares	$ 36.55
Granted (in dollars per share) | $ / shares	29.30
Forfeited (in dollars per share) | $ / shares	35.30
Vested (in dollars per share) | $ / shares	37.43
Nonvested Balance – end of year (in dollars per share) | $ / shares	$ 31.54

Subsequent Events (Details)

Subsequent Events (Details) - $ / shares		12 Months Ended
	Feb. 15, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Subsequent Event [Line Items]
Dividends declared (in dollars per share)		$ 1.76	$ 1.76	$ 1.76
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share)	$ 0.44

CONDENSED FINANCIAL INFORMATI_2

CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Income Statements, Captions [Line Items]
Operating Revenues	$ 8,309	$ 7,923	$ 6,974
Operating Expenses
Taxes other than income taxes	683	658	640
Total Operating Expenses	7,379	7,071	6,079
Operating Income	930	852	895
Other Income
Other income	129	30	60
Interest expense	(409)	(303)	(298)
Income Before Income Tax	656	841	664
Income tax expense (benefit)	(9)	20	21
Net Income Attributable to Avangrid, Inc.	786	881	707
AVANGRID
Condensed Income Statements, Captions [Line Items]
Operating Revenues	0	0	0
Operating Expenses
Operating expense	9	11	19
Taxes other than income taxes	7	(1)	(11)
Total Operating Expenses	16	10	8
Operating Income	(16)	(10)	(8)
Other Income
Other income	127	49	22
Equity earnings of subsidiaries	837	999	756
Interest expense	(248)	(117)	(93)
Income Before Income Tax	700	921	677
Income tax expense (benefit)	(86)	40	(30)
Net Income Attributable to Avangrid, Inc.	$ 786	$ 881	$ 707

CONDENSED FINANCIAL INFORMATI_3

CONDENSED FINANCIAL INFORMATION OF PARENT - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Statement of Income Captions [Line Items]
Net Income	$ 786	$ 881	$ 707
Comprehensive Income Attributable to Avangrid, Inc.	941	974	545
AVANGRID
Condensed Statement of Income Captions [Line Items]
Net Income	786	881	707
Other comprehensive income (loss) of subsidiaries	155	93	(162)
Comprehensive Income Attributable to Avangrid, Inc.	$ 941	$ 974	$ 545

CONDENSED FINANCIAL INFORMATI_4

CONDENSED FINANCIAL INFORMATION OF PARENT - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 91	$ 69
Prepayments and other current assets	429	386
Total Current Assets	3,404	3,210
Other assets
Other	393	413
Total Other Assets	3,958	3,953
Total Assets	43,989	41,123
Current Liabilities
Accounts payable and accrued liabilities	1,924	2,007
Interest accrued subsidiaries	104	66
Dividends payable	170	170
Other current liabilities	662	593
Total Current Liabilities	5,239	4,416
Derivative liabilities	111	164
Total Non-current Liabilities	18,074	16,365
Total Liabilities	23,313	20,781
Stockholders' Equity:
Common stock	4	3
Additional paid-in capital	17,701	17,694
Treasury stock	(47)	(47)
Retained earnings	2,015	1,910
Accumulated other comprehensive loss	(25)	(180)
Total Equity	20,676	20,342	$ 19,961	$ 15,826
Total Liabilities and Equity	43,989	41,123
Related Party
Current Assets
Accounts receivable from affiliates	11	5
Notes receivable from affiliates	4	3
Current Liabilities
Notes payable	13	2
Accounts payable to subsidiaries	0	39
Non-current debt	800	8
Nonrelated Party
Current Assets
Accounts receivable from affiliates	1,588	1,737
Current Liabilities
Notes payable	1,347	566
Non-current debt	9,184	8,215
AVANGRID
Current Assets
Cash and cash equivalents	11	28
Prepayments and other current assets	47	17
Total Current Assets	2,386	1,675
Investments in subsidiaries	22,244	20,588
Other assets
Deferred income taxes	452	358
Other	3	3
Total Other Assets	455	361
Total Assets	25,085	22,624
Current Liabilities
Current portion of debt	600	0
Accounts payable and accrued liabilities	1	7
Dividends payable	170	170
Other current liabilities	30	30
Total Current Liabilities	3,168	1,181
Derivative liabilities	63	86
Total Non-current Liabilities	2,269	2,063
Total Liabilities	5,437	3,244
Stockholders' Equity:
Common stock	4	3
Additional paid-in capital	17,701	17,694
Treasury stock	(47)	(47)
Retained earnings	2,015	1,910
Accumulated other comprehensive loss	(25)	(180)
Total Equity	19,648	19,380
Total Liabilities and Equity	25,085	22,624
AVANGRID | Related Party
Current Assets
Accounts receivable from affiliates	416	190
Notes receivable from affiliates	1,912	1,440
Current Liabilities
Notes payable	977	557
Accounts payable to subsidiaries	2	3
Interest accrued subsidiaries	48	9
Non-current debt	800	0
AVANGRID | Nonrelated Party
Current Liabilities
Notes payable	1,331	396
Interest accrued subsidiaries	9	9
Non-current debt	$ 1,406	$ 1,977

CONDENSED FINANCIAL INFORMATI_5

CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	$ 919	$ 1,035	$ 1,561
Cash Flow from Investing Activities
Net Cash Used in Investing Activities	(3,099)	(2,548)	(2,440)
Cash Flow from Financing Activities
Repurchase of common stock	0	0	(33)
Dividends paid	(681)	(681)	(613)
Net Cash Provided by Financing Activities	2,202	108	889
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	22	(1,405)	10
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	72	1,477	1,467
Cash, Cash Equivalents and Restricted Cash, End of Year	94	72	1,477
Supplemental Cash Flow Information
Cash paid for interest	338	273	279
Cash paid (refunded) payment for income taxes	(40)	15	2
AVANGRID
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	(298)	(742)	(397)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	(116)	(14)	130
Investments in subsidiaries	(1,263)	(1,020)	(1,026)
Return of capital from investments in subsidiaries	595	664	1,122
Other investments	0	0	300
Net Cash Used in Investing Activities	(784)	(370)	526
Cash Flow from Financing Activities
Receipts (repayments) of short-term notes payable from subsidiaries, net	14	1	(186)
Receipts (repayments) of short-term notes payable	935	397	(309)
Proceeds (repayments) from non-current debt with affiliate	800	0	(3,000)
Repurchase of common stock	0	0	(33)
Issuance of common stock	(3)	(1)	3,998
Dividends paid	(681)	(681)	(613)
Net Cash Provided by Financing Activities	1,065	(284)	(143)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	(17)	(1,396)	(14)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	28	1,424	1,438
Cash, Cash Equivalents and Restricted Cash, End of Year	11	28	1,424
Supplemental Cash Flow Information
Cash paid for interest	181	86	74
Cash paid (refunded) payment for income taxes	$ 21	$ (33)	$ (15)

CONDENSED FINANCIAL INFORMATI_6

CONDENSED FINANCIAL INFORMATION OF PARENT - Common Stock (Details) - USD ($) $ / shares in Units, $ in Millions		12 Months Ended
	Feb. 15, 2024	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Business Acquisition [Line Items]
Common stock, authorized (in shares)		500,000,000	500,000,000
Common stock issued (in shares)		387,872,787	387,734,757
Common stock, outstanding (in shares)		386,770,915	386,628,586
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01	$ 0.01
Common stock		$ 4	$ 3
Additional paid-in capital		$ 17,701	$ 17,694
Release of common stock held in trust (in shares)		4,299	4,355
Number of shares repurchased during period (in shares)		0
Treasury shares (in shares)		997,983
Treasury stock		$ 47	$ 47
Dividends declared (in dollars per share)		$ 1.76	$ 1.76	$ 1.76
Subsequent Event
Business Acquisition [Line Items]
Dividends declared (in dollars per share)	$ 0.44
Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)		0	0
Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)		138,030	56,127
AVANGRID
Business Acquisition [Line Items]
Common stock, authorized (in shares)		500,000,000	500,000,000
Common stock issued (in shares)		387,872,787	387,734,757
Common stock, outstanding (in shares)		386,770,915	386,628,586
Common stock, par value (in dollars per share)		$ 0.01	$ 0.01
Common stock		$ 4	$ 3
Additional paid-in capital		$ 17,701	$ 17,694
Common stock held in trust (in shares)		103,889	108,188
Release of common stock held in trust (in shares)		4,299	4,355
Number of shares repurchased during period (in shares)		0
Treasury shares (in shares)		997,983
Treasury stock		$ 47	$ 47
AVANGRID | Subsequent Event
Business Acquisition [Line Items]
Dividends declared (in dollars per share)	$ 0.44
AVANGRID | Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)		0	0
AVANGRID | Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)		138,030	56,127
Iberdrola Renewables Holding, Inc
Business Acquisition [Line Items]
Percentage of equity owned by parent		81.50%
Iberdrola Renewables Holding, Inc | AVANGRID
Business Acquisition [Line Items]
Percentage of equity owned by parent		81.60%	81.60%
Target ownership percentage by Parent		81.50%

CONDENSED FINANCIAL INFORMATI_7

CONDENSED FINANCIAL INFORMATION OF PARENT - Long-Term Debt (Details)	Apr. 09, 2020 USD ($)	May 16, 2019 USD ($)	Jul. 19, 2023 USD ($)	Dec. 31, 2021 placement	Dec. 14, 2020 USD ($)	Dec. 31, 2017 USD ($)
Intragroup Green Loan | Subordinated Debt
Debt Instrument [Line Items]
Debt instrument principal amount			$ 800,000,000
Weighted-average interest rate			5.45%
AVANGRID | 3.15% Notes due 2024
Debt Instrument [Line Items]
Debt instrument principal amount						$ 600,000,000
Interest rate						3.15%
AVANGRID | 3.80% Notes due 2029
Debt Instrument [Line Items]
Debt instrument principal amount		$ 750,000,000
Interest rate		3.80%
Proceeds from non-current debt		$ 743,000,000
AVANGRID | Unsecured Notes Maturing in 2025
Debt Instrument [Line Items]
Debt instrument principal amount	$ 750,000,000
Interest rate	3.20%
Proceeds from non-current debt	$ 744,000,000
AVANGRID | Iberdrola Loan | Subordinated Debt
Debt Instrument [Line Items]
Debt instrument principal amount					$ 3,000,000,000
Sale of stock, number of placements | placement				2

CONDENSED FINANCIAL INFORMATI_8

CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Summary (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Avangrid Networks
Cash Dividend [Line Items]
Cash dividends paid	$ 595	$ 645	$ 970
Avangrid Renewables
Cash Dividend [Line Items]
Cash dividends paid	$ 0	$ 19	$ 152

CONDENSED FINANCIAL INFORMATI_9

CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Additional Information (Details) - AVANGRID - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2023	Dec. 31, 2022	Dec. 31, 2021
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 1,263	$ 1,020	$ 1,026
Non cash contribution/dividend recorded by parent company	122	473
UI
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 931	$ 986	$ 1,011