Avangrid (AGR) 10-Q 5 May 20 2020 Q1 Quarterly report Financial data

Cover Page

Cover Page - shares	3 Months Ended
	Mar. 31, 2020	Apr. 30, 2020
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2020
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	629-1200
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	AGR
Security Exchange Name	NYSE
Amendment Flag	false
Document Fiscal Year Focus	2020
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001634997
Current Fiscal Year End Date	--12-31
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding (in shares)		309,005,485

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Income Statement [Abstract]
Operating Revenues	$ 1,789	$ 1,842
Operating Expenses
Purchased power, natural gas and fuel used	475	563
Operations and maintenance	570	553
Depreciation and amortization	251	222
Taxes other than income taxes	166	163
Total Operating Expenses	1,462	1,501
Operating Income	327	341
Other Income and (Expense)
Other expense	(3)	(7)
(Losses) earnings from equity method investments	(6)	1
Interest expense, net of capitalization	(76)	(78)
Income Before Income Tax	242	257
Income tax expense	12	41
Net Income	230	216
Net loss attributable to noncontrolling interests	10	1
Net Income Attributable to Avangrid, Inc.	$ 240	$ 217
Earnings Per Common Share, Basic (in usd per share)	$ 0.78	$ 0.70
Earnings Per Common Share, Diluted (in usd per share)	$ 0.78	$ 0.70
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	309,491,082	309,491,082
Diluted (in shares)	309,623,573	309,712,308

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income	$ 230	$ 216
Other Comprehensive Income (Loss)
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(8.5) and $(10.9), respectively	(23)	(29)
Reclassification to net income of loss on cash flow hedges, net of income taxes of $0.3 and $0.7, respectively	2	2
Other Comprehensive Income (Loss)	(21)	(27)
Comprehensive Income	209	189
Net loss attributable to noncontrolling interests	10	1
Comprehensive Income Attributable to Avangrid, Inc.	$ 219	$ 190

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Statement of Comprehensive Income [Abstract]
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), before Reclassification, Tax	$ 8.5	$ 10.9
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, Tax	$ 0.3	$ 0.7

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Current Assets
Cash and cash equivalents	$ 26	$ 178
Accounts receivable and unbilled revenues, net	1,077	1,082
Accounts receivable from affiliates	4	10
Derivative assets	24	11
Fuel and gas in storage	78	110
Materials and supplies	143	141
Prepayments and other current assets	245	199
Regulatory assets	299	294
Total Current Assets	1,896	2,025
Total Property, Plant and Equipment ($1,447 and $787 related to VIEs, respectively)	25,488	25,218
Operating lease right-of-use assets	67	70
Equity method investments	656	645
Other investments	55	63
Regulatory assets	2,568	2,567
Other Assets
Goodwill	3,119	3,119
Intangible assets	313	314
Derivative assets	85	84
Other	346	311
Total Other Assets	3,863	3,828
Total Assets	34,593	34,416
Current Liabilities
Current portion of debt	726	730
Notes payable	731	560
Notes payable to affiliates	16	0
Interest accrued	77	72
Accounts payable and accrued liabilities	1,064	1,361
Accounts payable to affiliates	13	64
Dividends payable	136	136
Taxes accrued	62	56
Operating lease liabilities	17	12
Derivative liabilities	53	20
Other current liabilities	292	334
Regulatory liabilities	260	242
Total Current Liabilities	3,447	3,587
Regulatory liabilities	3,301	3,281
Other Non-current Liabilities
Deferred income taxes	1,826	1,814
Deferred income	1,256	1,274
Pension and other postretirement	1,079	1,100
Operating lease liabilities	56	65
Derivative liabilities	91	85
Asset retirement obligations	197	190
Environmental remediation costs	327	338
Other	390	380
Total Other Non-current Liabilities	5,222	5,246
Non-current debt	6,715	6,716
Total Non-current Liabilities	15,238	15,243
Total Liabilities	18,685	18,830
Commitments and Contingencies
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,752,140 shares issued; 309,005,485 and 309,005,272 shares outstanding, respectively	3	3
Additional paid in capital	13,667	13,660
Treasury stock	(12)	(12)
Retained earnings	1,784	1,681
Accumulated other comprehensive loss	(116)	(95)
Total Stockholders’ Equity	15,326	15,237
Non-controlling interests	582	349
Total Equity	15,908	15,586
Total Liabilities and Equity	$ 34,593	$ 34,416

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment, VIEs	$ 25,488	$ 25,218
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	500,000,000	500,000,000
Common stock, issued (in shares)	309,752,140	309,752,140
Common stock, outstanding (in shares)	309,005,485	309,005,272
Variable Interest Entity, Primary Beneficiary
Property, Plant and Equipment, VIEs	$ 1,447	$ 787

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Cash Flow from Operating Activities:
Net Income	$ 230	$ 216
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	251	222
Regulatory assets/liabilities amortization and carrying cost	18	14
Pension cost	20	25
Earnings from equity method investments	6	(1)
Distributions of earnings received from equity method investments	3	2
Unrealized (gain) loss on marked-to-market derivative contracts	(18)	(3)
Deferred taxes	10	21
Other non-cash items	1	(2)
Changes in operating assets and liabilities:
Current assets	(16)	(43)
Noncurrent assets	(55)	(40)
Current liabilities	(117)	(44)
Noncurrent liabilities	(26)	(52)
Net Cash Provided by Operating Activities	307	315
Cash Flow from Investing Activities:
Capital expenditures	(742)	(425)
Contributions in aid of construction	7	10
Proceeds from sale of assets	6	3
Proceeds from notes receivable from affiliates	2	0
Distributions received from equity method investments	1	2
Other investments and equity method investments, net	(23)	(116)
Net Cash Used in Investing Activities	(749)	(526)
Cash Flow from Financing Activities:
Non-current debt issuances	0	194
Repayments of non-current debt	(3)	(43)
Receipts of other short-term debt, net	187	211
Repayments of financing leases	(1)	(21)
Distributions to noncontrolling interests	(1)	(3)
Contributions from noncontrolling interests	244	3
Dividends paid	(136)	(135)
Net Cash Provided by Financing Activities	290	206
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(152)	(5)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	184	43
Cash, Cash Equivalents and Restricted Cash, End of Period	32	38
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	70	58
Cash paid for income taxes	$ 2	$ 2

Condensed Consolidated Statem_5

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions		Total	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Total Stockholders’ Equity	Non controlling Interests
Balance, beginning of period at Dec. 31, 2018		$ 15,403	$ 3		$ 13,657	$ (12)	$ 1,528	$ (72)	$ 15,104	$ 299
Balance, beginning of period (in shares) at Dec. 31, 2018	[1]		309,005,272
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		216					217		217	(1)
Other comprehensive income (loss), net of tax of $1.9, $3.7, $(6.6), and $(5.8), respectively		(27)						(27)	(27)
Comprehensive income		189
Dividends declared, $0.44/share		(136)					(136)		(136)
Stock-based compensation		1			1				1
Distributions to noncontrolling interests		(3)								(3)
Contributions from noncontrolling interests		3								3
Balance, end of period at Mar. 31, 2019		15,456	$ 3		13,658	(12)	1,620	(111)	15,158	298
Balance, end of period (in shares) at Mar. 31, 2019	[1]		309,005,272
Balance, beginning of period at Dec. 31, 2019		$ 15,586	$ 3		13,660	(12)	1,681	(95)	15,237	349
Balance, beginning of period (in shares) at Dec. 31, 2019		309,005,272	309,005,272	[1]
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		$ 230					240		240	(10)
Other comprehensive income (loss), net of tax of $1.9, $3.7, $(6.6), and $(5.8), respectively		(21)						(21)	(21)
Comprehensive income		209
Dividends declared, $0.44/share		$ (136)					(136)		(136)
Release of common stock held in trust		213
Stock-based compensation		$ 7			7				7
Distributions to noncontrolling interests		(1)								(1)
Contributions from noncontrolling interests		244								244
Balance, end of period at Mar. 31, 2020		$ 15,908	$ 3		$ 13,667	$ (12)	$ 1,784	$ (116)	$ 15,326	$ 582
Balance, end of period (in shares) at Mar. 31, 2020		309,005,485	309,005,485	[1]
[1]	(*) Par value of share amounts is $0.01

Condensed Consolidated Statem_6

Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01	$ 0.01
Other comprehensive income (loss), taxes	$ 10.2	$ 8.2
Dividends declared (in usd per share)	$ 0.44	$ 0.44

Background and Nature of Operat

Background and Nature of Operations	3 Months Ended
	Mar. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Background and Nature of Operations	Background and Nature of Operations Avangrid, Inc., formerly Iberdrola USA, 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 81.5% of the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The accompanying condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 2019 . The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. Intercompany accounts and transactions have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three months ended March 31, 2020 , are not necessarily indicative of the results for the entire fiscal year ending December 31, 2020 .

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Significant Accounting Policies and New Accounting Pronouncements	Significant Accounting Policies and New Accounting Pronouncements The new accounting pronouncements that we have adopted as of January 1, 2020, and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2019, except for those described below resulting from the adoption of new authoritative accounting guidance issued by Financial Accounting Standards Board (FASB). Goodwill 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 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 of first performing 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 that 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. Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain accounts receivable and payable 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. Accounts receivable include amounts due under Deferred Payment Arrangements (DPAs). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as short term. We establish our allowance for credit losses, including for unbilled revenue, 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. Due to our adoption of Accounting Standards Codification (ASC) 326 effective January 1, 2020, we now also 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 accounts receivable. We write off amounts when we have exhausted reasonable collection efforts. Adoption of New Accounting Pronouncements (a) Measurement of credit losses on financial instruments, amendments and updates The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments (ASC 326). The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The FASB subsequently issued various updates to ASC 326 to clarify transition and scope requirements, make narrow-scope codification improvements, including in March 2020, and corrections and provide targeted transition relief. We adopted the amendments effective January 1, 2020, including the narrow-scope improvements issued in March 2020, and recorded a cumulative-effect adjustment of $1 million to retained earnings at the beginning of the period of adoption, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. (b) Simplifying the test for goodwill impairment In January 2017, the FASB issued amendments to simplify the test for goodwill impairment, which are required for public entities and certain other entities that have goodwill reported in their financial statements. The amendments simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test, which requires the valuation of assets acquired and liabilities assumed using business combination accounting guidance. Under the new guidance, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Also, an entity should consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. Certain requirements are eliminated for any reporting unit with a zero or negative carrying amount; therefore, the same impairment assessment applies to all reporting units. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we will apply the amendments on a prospective basis. (c) Changes to the disclosure requirements for fair value measurement and defined benefit plans In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans. The amendments concerning fair value measurement remove, modify and add certain disclosure requirements in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. We adopted the amendments effective January 1, 2020, with no material effect to our disclosures. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively. The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. The amendments change annual disclosures requirements, including removal of disclosures that are no longer considered cost beneficial, adding certain new relevant disclosures and clarifying specific requirements of disclosures concerning information for defined benefit pension plans. We adopted the amendments effective January 1, 2020, and they will not materially affect the disclosures for our fiscal year ending December 31, 2020. As required, our application will be on a retrospective basis. (d) Targeted improvements to related party guidance for VIEs In October 2018, the FASB issued amendments that affect reporting entities that are required to determine whether they should consolidate a legal entity under the consolidation guidance applicable to VIEs. The targeted improvements specifically applicable to public business entities clarify that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. (e) Clarifying guidance for certain collaborative arrangements with respect to revenue recognition The FASB issued amendments in November 2018 to clarify the interaction between the guidance for certain collaborative arrangements and the guidance applicable to ASC 606. A collaborative arrangement is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. The targeted improvements clarify that certain transactions between collaborative arrangement participants are within the scope of ASC 606 and thus subject to all of its guidance. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we retrospectively applied the amendments to the date of our initial application of ASC 606. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2019, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements. (a) Simplifying the accounting for income taxes In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes , eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. The amendments are effective for public business entities for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued, with adoption of all amendments in the same period. Application is on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment aspect. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows. (b) Facilitation of the effects of reference rate reform on financial reporting In March 2020, the FASB issued amendments to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.

Revenue

Revenue	3 Months Ended
	Mar. 31, 2020
Revenue from Contract with Customer [Abstract]
Revenue	Revenue We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about reportable segments, refer to Note 13. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts, with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. 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. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to Federal Energy Regulatory Commission (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. 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, other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs. 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 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. 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. Other Other, which does not represent a segment, includes miscellaneous Corporate revenues and intersegment eliminations. Contract Costs and Contract Liabilities We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid for during the solar asset development period in 2018, and will amortize ratably into expense over the 15 -year life of the power purchase agreement (PPA), expected to commence in December 2021 upon commercial operation. We also have a contract asset for costs incurred to cancel a PPA, which we will amortize over the 10 -year contract period of the replacement PPA that will commence upon completion of the project. Contract assets totaled $12 million at both March 31, 2020 and December 31, 2019 , and are presented in "Other non-current assets" on our condensed consolidated balance sheets. We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years . TCC contract liabilities totaled $5 million and $10 million at March 31, 2020 and December 31, 2019 , respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $5 million as revenue during both the three months ended March 31, 2020 and 2019. Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2020 and 2019 are as follows: Three Months Ended March 31, 2020 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 873 $ — $ — $ 873 Regulated operations – natural gas 507 — — 507 Nonregulated operations – wind — 211 — 211 Nonregulated operations – solar — 4 — 4 Nonregulated operations – thermal — 10 — 10 Other(a) 19 28 — 47 Revenue from contracts with customers 1,399 253 — 1,652 Leasing revenue 1 — — 1 Derivative revenue — 70 — 70 Alternative revenue programs 56 — — 56 Other revenue 5 5 — 10 Total operating revenues $ 1,461 $ 328 $ — $ 1,789 Three Months Ended March 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 913 $ — $ — $ 913 Regulated operations – natural gas 625 — — 625 Nonregulated operations – wind — 182 — 182 Nonregulated operations – solar — 5 — 5 Nonregulated operations – thermal — 16 — 16 Other(a) 37 (7 ) (4 ) 26 Revenue from contracts with customers 1,575 196 (4 ) 1,767 Leasing revenue 1 — — 1 Derivative revenue — 41 — 41 Alternative revenue programs 16 — — 16 Other revenue 12 5 — 17 Total operating revenues $ 1,604 $ 242 $ (4 ) $ 1,842 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations. As of March 31, 2020 and December 31, 2019 , accounts receivable balances related to contracts with customers were approximately $1,039 million and $1,050 million , respectively, including unbilled revenues of $312 million and $345 million , which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets. As of March 31, 2020 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of March 31, 2020 2021 2022 2023 2024 2025 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ — $ — $ 4 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 35 19 11 8 7 17 97 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 17 9 6 4 3 5 44 Total operating revenues $ 53 $ 29 $ 18 $ 13 $ 10 $ 22 $ 145 As of March 31, 2020 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2020 was $64 million .

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2020
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 the rate base or accruing carrying costs are the 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 $1,728 million . CMP 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% , based on an allowed ROE of 9.25% and a 50% equity ratio. The rate increase is effective 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. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a period of 18 consecutive months with measurement commencing on March 1, 2020. The order provides additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retains the revenue decoupling mechanism implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and initiated a management audit to assess the quality of these services as well as the impacts of the AVANGRID management structure on the quality of CMP’s customer service. NYSEG and RG&E Rate Plans and Rate Case Filings On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal filed with the NYPSC by New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E) and by certain other signatory parties on February 19, 2016, in connection with a three -year rate plan for electric and gas service at NYSEG and RG&E effective May 1, 2016. Following the approval of the Joint Proposal, most of the regulatory deferrals related to NYSEG are amortized over a five -year period, except the portion of storm costs to be recovered over ten years , unfunded deferred taxes being amortized over a period of 50 years and plant-related tax items which are amortized over the life of associated plant. Annual amortization expense for NYSEG is approximately $16.5 million per rate year. RG&E items that are being amortized are plant- related tax items, which are amortized over the life of associated plant, and unfunded deferred taxes being amortized over a period of 50 years . A majority of the other items related to RG&E, which net to a regulatory liability, remain deferred and will not be amortized until future proceedings. The approved Joint Proposal provides for annual rate increases and allowed rates of return on common equity of 9.0% for NYSEG and RG&E. The equity ratio for each company is 48% ; however, the equity ratio is set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50% , 75% and 90% of earnings over 9.5% , 10.0% and 10.5% ROE, respectively, in the first rate year covering the period May 1, 2016 – April 30, 2017. The earnings sharing levels increase in rate year two (May 1, 2017 – April 30, 2018) to 9.65% , 10.15% and 10.65% ROE, respectively. The earnings sharing levels further increase in rate year three (May 1, 2018 – April 30, 2019) to 9.75% , 10.25% and 10.75% ROE, respectively. The rate plans also include the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates, and continuation of the existing RDM for each company. On May 20, 2019, NYSEG and RG&E filed rate cases with the New York State Public Service Commission (NYPSC) for new tariffs. The effective date of new tariffs, assuming an approximately 11-month suspension period, will be April 20, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as vegetation management, hardening/resiliency and emergency preparedness. The companies are requesting delivery revenues to be based on a 9.50% ROE and 50% equity ratio. The below table provides a summary of the initial proposed delivery rate increases, delivery revenue percentages and total revenue percentages for all four businesses: Requested Revenue Increase Delivery Revenue Total Revenue Utility (Millions) % % NYSEG Electric $ 156.7 20.4 % 10.4 % NYSEG Gas $ 6.3 3.0 % 1.4 % RG&E Electric $ 31.7 7.0 % 4.1 % RG&E Gas $ 5.8 3.3 % 1.4 % Staff of the Department of Public Service (NYDPS Staff) and other parties filed responsive testimony on September 15, 2019. The NYDPS staff is recommending an 8.2% ROE and 48% equity. The NYDPS Staff recommended the following rate increases/decreases: NYSEG electric a rate increase of $76.7 million , NYSEG Gas a rate decrease of $15.9 million , RG&E Electric a rate increase of $0.7 million and RG&E Gas a rate decrease of $22.5 million . The NYDPS Staff is also recommending NYSEG credit the environmental reserve by $31.1 million due to the legal rulings in 2017 and 2018 that denied insurance claims against OneBeacon and Century Indemnity in an insurance lawsuit. The companies entered into settlement discussion with the NYDPS Staff and other parties in October 2019. On February 26, 2020, the companies filed notice with the NYPSC that an agreement in principle has been reached among the companies, the NYDPS Staff and certain other parties to the matter. As a result of the novel coronavirus (COVID-19) pandemic, NYSEG and RG&E proposed additional time for settlement negotiations, including consideration of the impacts of the COVID-19 pandemic. The suspension date would be extended through September 13, 2020, subject to a “make-whole” provision that would keep NYSEG, RG&E and their customers in the same position they would have been absent the extension. The "make whole" provision covers the period back to April 17, 2020. On March 23, 2020, the Public Utility Law Project (a party to the cases) submitted a letter motion requesting that the NYPSC administrative law judges assigned to preside over the rate cases require NYSEG and RG&E to pause settlement discussions and to provide new and accurate calculations based on the current and future expected economic impact of the COVID-19 pandemic. On March 31, 2020, the NYSEG and RG&E, Multiple Intervenors (a party to the cases), and NYDPS staff each filed a response in opposition to the motion. On April 7, 2020, the NYPSC administrative law judges issued a Ruling Denying Public Utility Law Project’s Motion, allowing settlement negotiations to continue. On April 22, 2020, the Public Utility Law Project and AARP filed an interlocutory appeal requesting that the NYPSC review the determination of the administrative law judges. NYSEG, RG&E, NYPSC staff and other parties are continuing settlement negotiations and plan to address impacts of the COVID-19 pandemic. We cannot predict the outcome of these proceedings. UI, CNG, SCG and BCG Rate Plans In December 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017 and which, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50% equity ratio, continued UI’s existing earnings sharing mechanism (ESM) pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year , continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. In December 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with rate increases of $1.5 million , $4.7 million and $5.0 million in 2018, 2019 and 2020, respectively. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for Connecticut Natural Gas Corporation (CNG), ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on a ROE of 9.25% and approximately 52% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. In December 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with rate increases of $9.9 million , $4.6 million and $5.2 million in 2019, 2020 and 2021, respectively. 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 January 18, 2019, the DPU approved new distribution rates for BGC providing for a $1.6 million distribution base rate increase effective February 1, 2019 (with a make-whole provision back to January 1, 2019), and an additional $0.7 million base distribution increase effective November 1, 2019, if certain investments are made by BGC. The distribution rate increase is based on a 9.70% ROE and 55% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021. Regulatory assets and liabilities The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. Regulatory assets as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Pension and other post-retirement benefits cost deferrals $ 113 $ 125 Pension and other post-retirement benefits 1,027 1,061 Storm costs 332 272 Rate adjustment mechanism 28 79 Revenue decoupling mechanism 61 19 Transmission revenue reconciliation mechanism 5 5 Contracts for differences 95 92 Hardship programs 24 29 Plant decommissioning 3 5 Deferred purchased gas 2 25 Deferred transmission expense 19 11 Environmental remediation costs 273 277 Debt premium 92 97 Unamortized losses on reacquired debt 29 29 Unfunded future income taxes 402 399 Federal tax depreciation normalization adjustment 152 153 Asset retirement obligation 20 17 Deferred meter replacement costs 26 27 Other 164 139 Total regulatory assets 2,867 2,861 Less: current portion 299 294 Total non-current regulatory assets $ 2,568 $ 2,567 “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. The recovery of these amounts will be determined in future proceedings. “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 service restoration costs resulting from major storms when they meet certain criteria for severity and duration. As of March 31, 2020 , deferred storm costs include $74 million and $30 million at NYSEG being recovered over ten -year and five -year periods, respectively, beginning in 2016, and $136 million and $60 million at NYSEG and RG&E, respectively, not included in the Joint Proposal. The amounts not included in the Joint Proposal will be recovered through RAM or determined as part of the current rate proceedings. “Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve month period. "Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. "Transmission revenue reconciliation mechanism" reflects differences in actual costs in the rate year from those used to set rates. This mechanism contains the Annual Transmission True up (ATU) which is recovered over the subsequent June to May period. “Contracts for Differences” (CfDs) 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. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of fifty 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 27 to 39 years and for CMP 32.5 years beginning in 2020. “Asset retirement obligations” (ARO) 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 by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “Other” includes post-term amortization deferrals and various items subject to reconciliation including hedge losses and deferred property tax. Regulatory liabilities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Energy efficiency portfolio standard $ 71 $ 72 Gas supply charge and deferred natural gas cost 18 11 Pension and other post-retirement benefits cost deferrals 75 80 Carrying costs on deferred income tax bonus depreciation 43 49 Carrying costs on deferred income tax - Mixed Services 263(a) 14 15 2017 Tax Act 1,559 1,548 Revenue decoupling mechanism 11 17 Accrued removal obligations 1,179 1,173 Asset sale gain account 10 10 Economic development 27 27 Positive benefit adjustment 36 37 Theoretical reserve flow thru impact 12 14 Deferred property tax 35 17 Net plant reconciliation 23 23 Debt rate reconciliation 72 67 Rate refund – FERC ROE proceeding 32 32 Transmission congestion contracts 24 23 Merger-related rate credits 15 16 Accumulated deferred investment tax credits 13 13 Asset retirement obligation 17 14 Earning sharing provisions 28 28 Middletown/Norwalk local transmission network service collections 18 18 Low income programs 31 33 Non-firm margin sharing credits 12 16 New York 2018 winter storm settlement 11 11 Other 175 159 Total regulatory liabilities 3,561 3,523 Less: current portion 260 242 Total non-current regulatory liabilities $ 3,301 $ 3,281 “Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year. "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” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this, a regulatory liability is not reflected within the rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016. "Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016. “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 and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, to review and address the implications associated with the Tax Act on the utilities providing service in such states. "Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the net gain on the sale of certain assets that will be used for the future benefit of customers. The amortization period for the majority of the balance will be determined in future proceedings. “Economic development” represents the economic development program which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016. “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016. "Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates . "Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the Joint Proposal. "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 Federal Energy Regulatory Commission (FERC) proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details. "Transmission congestion contracts" represents deferral of Nine Mile 2 Nuclear Plant transmission congestion contract at RGE. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During both the three months ended March 31, 2020 and 2019, $1 million of rate credits were applied against customer bills. "Asset retirement obligation" represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability . "Earning sharing provisions" represents the annual earnings over the earning sharing threshold. "Middletown/Norwalk local transmission network service collections" “Low income programs” represent various hardship and payment plan programs approved for recovery. "New York 2018 winter storm settlement" represents the settlement amount with the NYSPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation including excess generation service charge, rate change levelization, RAM and transmission revenue reconciliation mechanism.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	3 Months Ended
	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.84 $ 4.90 $ 1.60 Indiana hub ($/MWh) $ 30.15 $ 61.12 $ 16.79 Mid C ($/MWh) $ 24.68 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 24.72 $ 52.17 $ 12.48 NoIL hub ($/MWh) $ 26.93 $ 55.39 $ 12.98 Ercot S hub ($/MWh) $ 31.20 $ 248.39 $ 11.41 Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years . The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input March 31, 2020 Risk of non-performance 1.13% - 1.68% Discount rate 0.37% - 0.55% Forward pricing ($ per KW-month) $2.00 - $7.03 Fair Value of Debt As of March 31, 2020 and December 31, 2019 , debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $7,963 million and $8,168 million as of March 31, 2020 and December 31, 2019 , respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy." id="sjs-B4">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 for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities and money market funds. 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. 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). Because we use prices quoted in an active market we include the fair value measurements in Level 1. • NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used, but because an unobservable basis adjustment is added to the forward prices, we include the fair value measurement for these contracts in Level 3. • UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical products with no adjustment are included in fair value Level 1. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in fair value Level 2. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in fair value Level 3. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. We determine the fair value of our interest rate swap derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate swaps). 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 their estimated fair values and are considered Level 1. Restricted cash was $6 million as of both March 31, 2020 and December 31, 2019 , and is included in "Other Assets" on our condensed consolidated balance sheets. The financial instruments measured at fair value as of March 31, 2020 and December 31, 2019 , respectively, consisted of: As of March 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 37 $ 11 $ — $ — $ 48 Derivative assets Derivative financial instruments - power 2 42 125 (63 ) 106 Derivative financial instruments - gas 1 33 32 (65 ) 1 Contracts for differences — — 2 — 2 Total 3 75 159 (128 ) 109 Derivative liabilities Derivative financial instruments - power (37 ) (28 ) (39 ) 98 (6 ) Derivative financial instruments - gas — (22 ) (6 ) 28 — Contracts for differences — — (97 ) — (97 ) Derivative financial instruments – other — (39 ) (2 ) — (41 ) Total $ (37 ) $ (89 ) $ (144 ) $ 126 $ (144 ) As of December 31, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 38 $ 13 $ — $ — $ 51 Derivative assets Derivative financial instruments - power 4 23 120 (54 ) 93 Derivative financial instruments - gas — 40 31 (71 ) — Contracts for differences — — 2 — 2 Total 4 63 153 (125 ) 95 Derivative liabilities Derivative financial instruments - power (28 ) (43 ) (29 ) 92 (8 ) Derivative financial instruments - gas (4 ) (26 ) (5 ) 33 (2 ) Contracts for differences — — (94 ) — (94 ) Derivative financial instruments - other — (1 ) — — (1 ) Total $ (32 ) $ (70 ) $ (128 ) $ 125 $ (105 ) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2020 and 2019 , respectively, is as follows: Three Months Ended March 31, (Millions) 2020 2019 Fair Value Beginning of Period, $ 25 $ (15 ) Gains recognized in operating revenues 13 25 (Losses) recognized in operating revenues (10 ) (13 ) Total gains recognized in operating revenues 3 12 Gains recognized in OCI 1 1 (Losses) recognized in OCI (5 ) (15 ) Total gains recognized in OCI (4 ) (14 ) Net change recognized in regulatory assets and liabilities (3 ) (2 ) Purchases — — Settlements (6 ) (3 ) Fair Value as of March 31, $ 15 $ (22 ) Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 3 $ 12 For assets and liabilities that are recognized in the condensed consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the periods reported. Level 3 Fair Value Measurement The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. As of March 31, 2020 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.84 $ 4.90 $ 1.60 Indiana hub ($/MWh) $ 30.15 $ 61.12 $ 16.79 Mid C ($/MWh) $ 24.68 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 24.72 $ 52.17 $ 12.48 NoIL hub ($/MWh) $ 26.93 $ 55.39 $ 12.98 Ercot S hub ($/MWh) $ 31.20 $ 248.39 $ 11.41 Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years . The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extends over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input March 31, 2020 Risk of non-performance 1.13% - 1.68% Discount rate 0.37% - 0.55% Forward pricing ($ per KW-month) $2.00 - $7.03 Fair Value of Debt As of March 31, 2020 and December 31, 2019 , debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $7,963 million and $8,168 million as of March 31, 2020 and December 31, 2019 , respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy.

Derivative Instruments and Hedg

Derivative Instruments and Hedging	3 Months Ended
	Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Derivative Instruments and Hedging Our Networks and Renewables activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities The tables below present Networks' derivative positions as of March 31, 2020 and December 31, 2019 , respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of March 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 2 $ 3 $ 2 $ 1 Derivative liabilities (1 ) (1 ) (42 ) (92 ) 1 2 (40 ) (91 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (5 ) (4 ) — — (5 ) (4 ) Total derivatives before offset of cash collateral 1 2 (45 ) (95 ) Cash collateral receivable — — 28 6 Total derivatives as presented in the balance sheet $ 1 $ 2 $ (17 ) $ (89 ) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 1 $ 4 $ 1 $ 2 Derivative liabilities (1 ) (2 ) (39 ) (86 ) — 2 (38 ) (84 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1 ) (1 ) — — (1 ) (1 ) Total derivatives before offset of cash collateral — 2 (39 ) (85 ) Cash collateral receivable — — 27 1 Total derivatives as presented in the balance sheet $ — $ 2 $ (12 ) $ (84 ) The net notional volumes of the outstanding derivative instruments associated with Networks activities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Wholesale electricity purchase contracts (MWh) 4.7 5.1 Natural gas purchase contracts (Dth) 7.7 8.5 Fleet fuel purchase contracts (Gallons) 2.3 2.2 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 their exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2020 and December 31, 2019 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2020 and 2019 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended March 31, March 31, 2020 Electricity Natural Gas 2020 Electricity Natural Gas Regulatory assets $ 34 $ — Purchased power, natural gas and fuel used $ 21 $ 5 December 31, 2019 2019 Regulatory assets $ 24 $ 4 Purchased power, natural gas and fuel used $ 4 $ — Pursuant to a PURA order, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2020 , UI has recorded a gross derivative asset of $2 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $95 million , a gross derivative liability of $98 million ( $94 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, 2019 , UI had recorded a gross derivative asset of $2 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $92 million , a gross derivative liability of $94 million ( $92 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0 . The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2020 and 2019 , respectively, were as follows: Three Months Ended March 31, 2020 2019 (Millions) Derivative assets $ — $ (1 ) Derivative liabilities $ (3 ) $ (1 ) Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 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) 2020 Interest rate contracts $ — Interest expense $ 1 $ 76 Commodity contracts (2 ) Purchased power, natural gas and fuel used — 475 Foreign currency exchange contracts (6 ) — Total $ (8 ) $ 1 2019 Interest rate contracts $ — Interest expense $ 2 $ 78 Commodity contracts 1 Purchased power, natural gas and fuel used — 563 Total $ 1 $ 2 (a) Changes in accumulated OCI are reported on a pre-tax basis. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $54 million and $55 million as of March 31, 2020 and December 31, 2019 , respectively. We recorded $1 million and $2 million in net derivative losses related to discontinued cash flow hedges for the three months ended March 31, 2020 and 2019, respectively. We will amortize approximately $3 million of discontinued cash flow hedges for the remainder of 2020 . Unrealized losses of $9 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable as of March 31, 2020 . We expect that $2 million of those losses will be reclassified into earnings within the next twelve months . The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is 12 months . (b) Renewables activities We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities. Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed-price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed-price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. The net notional volumes of outstanding derivative instruments associated with Renewables activities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (MWh/Dth in millions) Wholesale electricity purchase contracts 4 4 Wholesale electricity sales contracts 9 9 Natural gas and other fuel purchase contracts 29 29 Financial power contracts 11 10 Basis swaps – purchases 41 42 Basis swaps – sales 2 1 The fair values of derivative contracts associated with Renewables activities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Wholesale electricity purchase contracts $ (2 ) $ 10 Wholesale electricity sales contracts 22 4 Natural gas and other fuel purchase contracts — (2 ) Financial power contracts 79 73 Total $ 99 $ 85 The tables below present Renewables' derivative positions as of March 31, 2020 and December 31, 2019 , respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of March 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 35 $ 108 $ 37 $ 17 Derivative liabilities (1 ) (2 ) (43 ) (21 ) 34 106 (6 ) (4 ) Designated as hedging instruments Derivative assets — 17 8 8 Derivative liabilities — (13 ) (8 ) (7 ) — 4 — 1 Total derivatives before offset of cash collateral 34 110 (6 ) (3 ) Cash collateral receivable (payable) (11 ) (27 ) 1 1 Total derivatives as presented in the balance sheet $ 23 $ 83 $ (5 ) $ (2 ) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 110 $ 42 $ 13 Derivative liabilities (1 ) (7 ) (48 ) (18 ) 22 103 (6 ) (5 ) Designated as hedging instruments Derivative assets — 18 5 4 Derivative liabilities — (9 ) (13 ) (6 ) — 9 (8 ) (2 ) Total derivatives before offset of cash collateral 22 112 (14 ) (7 ) Cash collateral receivable (payable) (11 ) (30 ) 7 6 Total derivatives as presented in the balance sheet $ 11 $ 82 $ (7 ) $ (1 ) Derivatives not designated as hedging instruments The effects of trading and non-trading derivatives associated with Renewables activities for the three months ended March 31, 2020 , consisted of: Three Months Ended March 31, 2020 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1 ) $ — Wholesale electricity sales contracts 4 11 Financial power contracts — 22 Total gain included in operating revenues $ 3 $ 33 $ 1,789 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (11 ) Financial power contracts — (6 ) Financial and natural gas contracts — (2 ) Total loss included in purchased power, natural gas and fuel used $ — $ (19 ) $ 475 Total Gain $ 3 $ 14 The effects of trading and non-trading derivatives associated with Renewables activities for the three months ended March 31, 2019 , consisted of: Three Months Ended March 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ — Wholesale electricity sales contracts — (9 ) Financial power contracts (1 ) (13 ) Financial and natural gas contracts (1 ) (2 ) Total loss included in operating revenues $ (1 ) $ (24 ) $ 1,842 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 20 Financial power contracts — 1 Financial and natural gas contracts — 7 Total gain included in purchased power, natural gas and fuel used $ — $ 28 $ 563 Total (Loss) Gain $ (1 ) $ 4 Derivatives designated as hedging instruments The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Commodity contracts $ 7 Operating revenues $ — $ 1,789 2019 Commodity contracts $ (20 ) Operating revenues $ — $ 1,842 (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 $ 3 of gains included in accumulated OCI at March 31, 2020 , is expected to be reclassified into earnings within the next twelve months. We did not record any net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2020 and 2019 . (c) Interest rate swaps 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. We previously settled interest rate swaps designated as cash flow hedges related to the issuance of $750 million in debt. The net loss in accumulated OCI related to these interest rate swaps is $37 million and $38 million as of March 31, 2020 and December 31, 2019 , respectively. We amortized into income $1 million and $0 of the loss related to the settled interest rate swaps for the three months ended March 31, 2020 and 2019 , respectively. We will amortize approximately $3 million of the net loss on the interest rate swaps for the remainder of 2020 . On January 31, 2020, AVANGRID entered into two forward interest rate swaps, with a total notional amount of $600 million , to hedge the issuance of forecasted fixed rate debt. The forward interest rate swaps are designated and qualify as cash flow hedges and were settled upon the second quarter debt issuance described in Note 15. The gains or losses on the interest rate swap derivatives are reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense of the forecasted debt is incurred. The table below presents our interest rate swap derivative positions as of March 31, 2020 and December 31, 2019 , respectively, including the location of the net derivative positions on our condensed consolidated balance sheets: As of March 31, 2020 Current Liabilities (Millions) Designated as hedging instruments Derivative liabilities $ (31 ) As of December 31, 2019 Designated as hedging instruments Derivative liabilities $ — The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Interest rate contracts $ (31 ) Interest expense $ 1 $ 76 2019 Interest rate contracts $ (20 ) Interest expense $ — $ 78 (a) Changes in OCI are reported on a pre-tax basis. The amount in accumulated OCI is being reclassified into earnings over the underlying debt maturity period which ends in 2029. (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 rating on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2020 , UI would have had to post an aggregate of approximately $16 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 amounts of cash collateral under master netting arrangements that have not been offset against net derivative positions were $17 million and $21 million as of March 31, 2020 and December 31, 2019 , respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of March 31, 2020 is $35 million , for which we have posted collateral.

Contingencies

Contingencies	3 Months Ended
	Mar. 31, 2020
Commitments and Contingencies Disclosure [Abstract]
Contingencies	Contingencies 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 likely and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a joint complaint with the FERC pursuant to sections 206 and 306 of the Federal Power Act, against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15 -month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV). On October 16, 2014, the FERC issued its decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19% . The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $25 million and $7 million , respectively, as of March 31, 2020 , which has not changed since December 31, 2019 , except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17 million , which is based upon currently available information for these proceedings. Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). The FERC proposes to use this new methodology to resolve Complaints I, II, III and IV filed by the New England state consumer advocates. The new proposed ROE methodology set forth in the October 2018 Order considers more than just the two-step discounted cash flow (DCF) analysis adopted in the FERC order on Complaint I vacated by the Court. The new proposed ROE methodology uses three financial analyses (i.e., DCF, the capital-asset pricing model and the expected earnings analysis) to produce a range of returns to narrow the zone of reasonableness when assessing whether a complainant has met its initial burden of demonstrating that the utility’s existing ROE is unjust and unreasonable. The new proposed ROE methodology establishes a range of just and reasonable ROEs of 9.60% to 10.99% and proposes a just and reasonable base ROE of 10.41% with a new ROE cap of 13.08% . Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019. On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision. We cannot predict the outcome of this proceeding, and the potential impact it may have in establishing a precedent for our pending four Complaints. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2018 Winter Storms In March 2018, following two severe winter storms that impacted more than one million electric utility customers in New York, including 520,000 NYSEG and RG&E customers, the NYDPS commenced a comprehensive investigation of the preparation and response to those events by New York's major electric utility companies. The investigation was expanded in the spring of 2018 to include other 2018 New York spring storm events. On April 18, 2019, the NYDPS staff issued a report (the 2018 Staff Report) of the findings from their investigation. The 2018 Staff Report identifies 94 recommendations for corrective actions to be implemented in the utilities Emergency Response Plans (ERP). The report also identified potential violations by several of the utilities, including NYSEG and RG&E. Also on April 18, 2019, the NYPSC issued an Order Instituting Proceeding and to Show Cause directed to all major electric utilities in New York, including NYSEG and RG&E. The order directs the utilities, including NYSEG and RG&E, to show cause why the NYPSC should not pursue civil penalties, and/or administrative penalties for the apparent failure to follow their respective ERPs as approved and mandated by the NYPSC. The NYPSC also directs the utilities, within 30 days, to address whether the NYPSC should mandate, reject or modify in whole or in part, the 94 recommendations contained in the 2018 Staff Report. On May 20, 2019, NYSEG and RG&E responded to the portion of the Order to Show Cause with respect to the recommendations contained in the 2018 Staff Report. The Commission granted the companies a series of extensions to respond to the portion of the Order to Show Cause with respect to why the Commission should not pursue a penalty action. A petition requesting Commission approval of a joint settlement agreement was filed with the Commission on December 17, 2019. On February 6, 2020, the Commission approved the joint settlement agreement, which allows the companies to avoid litigation and provides for payment by the companies of penalty of $10.5 million . NYPSC Directs Counsel to Commence Judicial Enforcement Proceeding Against NYSEG On April 18, 2019, the NYPSC issued an Order Directing Counsel to the Commission to commence a special proceeding or an action in New York State Supreme Court to stop and prevent ongoing future violations by NYSEG of NYPSC regulations and orders. On December 24, 2019, the Commission filed a verified petition to commence the action against NYSEG. At the same time, NYSEG and the Commission settled the causes of action asserted in the verified petition and entered into a consent and stipulation and also submitted a joint motion to the court requesting that the court approve and enter a consent order and judgment reflecting the settlement. The consent order and judgment was issued by the court on January 24, 2020. California Energy Crisis Litigation Two California agencies brought a complaint in 2001 against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014, the FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC trial staff recommended that the complaint against Renewables be dismissed. A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that the price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million . Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. There is no specific timetable for the FERC's ruling. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. We cannot predict the outcome of this proceeding. Class Action Regarding LDC Gas Transportation Service on Algonquin Gas Transmission PNE Energy Supply LLC v. Eversource Energy and Avangrid, Inc. - Class Action . On August 10, 2018, PNE Energy Supply LLC, a competitive energy supplier located in New England that purchases electricity in the day-ahead and real time wholesale electric market, filed a civil antitrust action, on behalf of itself and those similarly situated, against the Company and Eversource alleging that their respective gas subsidiaries illegally manipulated the supply of pipeline capacity in the “secondary capacity market” in order to artificially inflate New England natural gas and electricity prices. These allegations were also based on the conclusions of the whitepaper issued by EDF. The plaintiff claims to represent entities who purchased electricity directly in the wholesale electricity market that it claims was targeted by the alleged anticompetitive conduct of Eversource and the Company. On September 28, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry and the dismissal of the related case, "Breiding et al. v. Eversource and Avangrid," by the same court in September. The plaintiffs filed opposition to the motion to dismiss on October 26, 2018 and the Company filed a reply on November 15, 2018. The district court heard oral arguments on the motion to dismiss on January 18, 2019. On April 26, 2019, the Company filed a brief in support of its motion to dismiss, and on June 7, 2019, the district court granted the Company’s Motion to Dismiss and dismissed all claims. On July 3, 2019, the plaintiffs filed notice of appeal in the U.S. Court of Appeals for the First Circuit and, on October 18, 2019, filed a brief in support of appeal. On January 2, 2020, the Company and Eversource filed a joint motion in opposition and on January 23, 2020, the plaintiffs filed a reply brief. On April 9, 2020, the U.S. Court of Appeals for the First Circuit canceled oral arguments of the appeal and ordered the case to be decided on the briefs without oral argument. We cannot predict the outcome of this class action lawsuit. Gas Storage Indemnification Claims On May 1, 2018, ARHI closed a transaction to sell our gas storage business to Amphora Gas Storage USA, LLC. On October 30, 2019, ARHI received notice of a claim for indemnification from Amphora Gas Storage USA, LLC under the purchase agreement with respect to such sale in the amount of approximately $20 million related to, among other things, certain alleged violations of occupational, health and safety requirements, the condition and sufficiency of assets and a third party intellectual property infringement claim. Pursuant to the terms of the purchase agreement, the aggregate amount for which ARHI may be responsible to indemnify Amphora Gas Storage USA, LLC for all claims arising under the purchase agreement, other than those related to certain fundamental representations, tax matters and claims involving fraud, shall not exceed 15% of the purchase price, or approximately $10 million . ARHI has disputed this claim for indemnification. We cannot predict the outcome of this matter. Guarantee Commitments to Third Parties As of March 31, 2020 , we had approximately $441 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of March 31, 2020 , neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liabilities

Environmental Liabilities	3 Months Ended
	Mar. 31, 2020
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-five waste sites, which do not include sites where gas was manufactured in the past. Seventeen of the twenty-five sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six 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, seven of the twenty-five 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 eleven of the twenty-five sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another eleven 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. Our estimate for costs to remediate these sites ranges from $13 million to $23 million as of March 31, 2020 . 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). Eight sites are included in the New York State Registry; three sites are included in the New York State Department of Environmental Conservation Multi-Site Order on Consent; three sites are part of Maine’s Voluntary Response Action Program with two such sites part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $158 million to $424 million as of March 31, 2020 . Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives and changes to current laws and regulations. Certain of our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; no liability was recorded related to these sites as of March 31, 2020 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of both March 31, 2020 and December 31, 2019 , the liability associated with our MGP sites in Connecticut was $97 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. Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $342 million and $349 million as of March 31, 2020 and December 31, 2019 , 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 2056. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former MGP sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor, requiring FirstEnergy to pay NYSEG approximately $60 million for past and future clean-up costs at the sixteen sites in dispute. On September 9, 2011, FirstEnergy paid NYSEG $30 million , representing their share of past costs of $27 million and pre-judgment interest of $3 million . FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million , excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean up expenses at nine MGP sites. Based on current projections, FirstEnergy’s share is estimated at approximately $20 million . This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG customers. English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was stayed in 2014 pending resolutions of other proceedings before the Connecticut Department of Energy and Environmental Protection (DEEP) concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs have appealed the court's decision to strike. We cannot predict the outcome of this matter. On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with DEEP. On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the consent order, to the extent that the cost of this investigation and remediation is less than $30 million , UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut and the Commissioner of DEEP. UI is obligated to comply with the terms of the consent order even if the cost of such compliance exceeds $30 million . Under the terms of the consent order, the State will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties; however, it is not bound to agree to or support any means of recovery or funding. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order. As of March 31, 2020 and December 31, 2019 , the amount reserved for this matter was $15 million and $16 million , respectively. We cannot predict the outcome of this matter. On April 24, 2020, ACV Environmental Services Company (ACV) filed a lawsuit in Connecticut Superior Court against UI arising out of a contract dispute for services rendered by ACV in the demolition of the Station B at the English Station site. The complaint seeks damages in the amount of $5 million on claims of breach of contract, breach of the covenant of good faith and fair dealing, quantum merit, and unjust enrichment. The claims arise from the alleged non-payment of certain change order requests. We cannot predict the outcome of this matter.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	3 Months Ended
	Mar. 31, 2020
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar Obligations We made $10 million of pension contributions for the three months ended March 31, 2020 . We expect to make additional contributions of $73 million for the remainder of 2020 . The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions) Service cost $ 12 $ 10 Interest cost 27 33 Expected return on plan assets (50 ) (48 ) Amortization of: Actuarial loss 31 30 Net Periodic Benefit Cost $ 20 $ 25 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions) Service cost $ 1 $ 1 Interest cost 3 4 Expected return on plan assets (2 ) (2 ) Amortization of: Prior service costs (2 ) (2 ) Net Periodic Benefit Cost $ — $ 1

Equity

Equity	3 Months Ended
	Mar. 31, 2020
Equity [Abstract]
Equity	Equity As of March 31, 2020 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,485 shares outstanding, 81.5% of which are owned by Iberdrola, each having a par value of $0.01 , for a total value of common stock of $3 million and additional paid in capital of $13,667 million . As of December 31, 2019 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% 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 capital of $13,660 million . We had 485,597 and 485,810 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding as of March 31, 2020 and December 31, 2019 . During the three months ended March 31, 2020 we issued no shares of common stock and released 213 shares of common stock held in trust. During the three months ended March 31, 2019 , we issued no shares of common stock and released no shares of common stock held in trust. We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage by Iberdrola at 81.5% . The stock repurchase program may be suspended or discontinued at any time upon notice. As of March 31, 2020, 261,058 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. The total cost of all repurchases, including commissions, was $12 million as of March 31, 2020 . No shares have been repurchased since 2018. Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Loss for the three months ended March 31, 2020 and 2019 , respectively, consisted of: As of December 31, Three Months Ended March 31, As of March 31, As of December 31, Adoption of new accounting Three Months Ended March 31, As of March 31, 2019 2020 2020 2018 standard 2019 2019 (Millions) Change in revaluation of defined benefit plans $ (12 ) $ — $ (12 ) $ (11 ) $ (2 ) $ — $ (13 ) Loss on nonqualified pension plans (7 ) — (7 ) (6 ) — — (6 ) Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(8.5) for 2020 and $(10.9) for 2019 (13 ) (23 ) (36 ) 9 — (29 ) (20 ) Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $0.3 for 2020 and $0.7 for 2019(a) (63 ) 2 (61 ) (64 ) (10 ) 2 (72 ) Loss on derivatives qualifying as cash flow hedges (76 ) (21 ) (97 ) (55 ) (10 ) (27 ) (92 ) Accumulated Other Comprehensive Loss $ (95 ) $ (21 ) $ (116 ) $ (72 ) $ (12 ) $ (27 ) $ (111 ) (a)Reclassification is reflected in the operating expenses line item in our condensed consolidated statements of income.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2020
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three months ended March 31, 2020 and 2019 , while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculation for the three months ended March 31, 2020 and 2019 . The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 240 $ 217 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,491,082 Weighted average number of shares outstanding - diluted 309,623,573 309,712,308 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.78 $ 0.70 Earnings Per Common Share, Diluted $ 0.78 $ 0.70

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2020
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 eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments and accelerated depreciation derived from repowering of wind farms. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment. Segment information as of and for the three months ended March 31, 2020 , consisted of: Three Months Ended March 31, 2020 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,461 $ 328 $ — $ 1,789 Depreciation and amortization 148 103 — 251 Operating income 309 13 5 327 Earnings (losses) from equity method investments 2 (8 ) — (6 ) Interest expense, net of capitalization 68 1 7 76 Income tax expense (benefit) 43 (30 ) (1 ) 12 Adjusted net income 198 46 (8 ) 236 Capital expenditures 437 305 — 742 As of March 31, 2020 Property, plant and equipment 16,036 9,442 10 25,488 Equity method investments 138 518 — 656 Total assets $ 23,355 $ 11,942 $ (704 ) $ 34,593 (a) Includes Corporate and intersegment eliminations. Segment information for the three months ended March 31, 2019 and as of December 31, 2019 , consisted of: Three Months Ended March 31, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,600 $ 242 $ — $ 1,842 Revenue - intersegment 4 — (4 ) — Depreciation and amortization 134 88 — 222 Operating income (loss) 331 13 (3 ) 341 Earnings (losses) from equity method investments 3 (2 ) — 1 Interest expense, net of capitalization 68 4 6 78 Income tax expense (benefit) 64 1 (24 ) 41 Adjusted net income 201 5 13 219 Capital expenditures 324 101 — 425 As of December 31, 2019 Property, plant and equipment 15,840 9,368 10 25,218 Equity method investments 139 506 — 645 Total assets $ 23,250 $ 13,163 $ (1,997 ) $ 34,416 (a) Includes Corporate and intersegment eliminations. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2020 and 2019 , respectively, is as follows: Three Months Ended March 31, 2020 2019 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 236 $ 219 Adjustments: Mark-to-market earnings - Renewables (1) 18 3 Restructuring charges (2) (3 ) — Accelerated depreciation from repowering (3) (10 ) (5 ) Income tax impact of adjustments (2 ) — Net Income Attributable to Avangrid, Inc. $ 240 $ 217 (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) Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth. (3) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables.

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2020
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Renovables Energía, S.L. $ — $ (2 ) $ — $ (4 ) Iberdrola Financiación, S.A. $ — $ (1 ) $ — $ — Iberdrola, S.A. $ — $ (10 ) $ — $ (10 ) Vineyard Wind $ 2 $ — $ — $ — Other $ — $ — $ — $ (1 ) In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola had an 8.1% ownership interest until Iberdrola sold its interest in February 2020. After the sale, the turbine purchases are no longer considered related party transactions. The amounts capitalized for transactions while Siemens-Gamesa was considered a related party were $11 million and $18 million for the periods ended March 31, 2020 and December 31, 2019 , respectively. Related party balances as of March 31, 2020 and December 31, 2019 , respectively, consisted of: As of March 31, 2020 December 31, 2019 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 1 $ (10 ) $ 1 $ (42 ) Iberdrola Renovables Energía, S.L. $ — $ (2 ) $ — $ — Iberdrola Financiación, S.A. $ — $ (1 ) $ — $ — Vineyard Wind $ 3 $ — $ 5 $ — Iberdrola Solutions $ — $ (14 ) $ — $ — Siemens-Gamesa (a) $ — $ — $ — $ (18 ) Other $ — $ (2 ) $ 4 $ (4 ) (a) After Iberdrola's sale of its interest of Siemens-Gamesa in February 2020, transactions with Siemens-Gamesa are no longer considered related party. 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. We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had a notes payable balance of $14 million and $0 , respectively, as of March 31, 2020 and December 31, 2019 . 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. Networks holds an approximate 20% ownership interest in New York TransCo, LLC (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. NYSEG’s contribution as 20% co-owner is $120 million . As of both March 31, 2020 and December 31, 2019 , the amount receivable from New York TransCo was $0 . We hold a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners. Vineyard Wind acquired an easement from the U.S. Bureau of Ocean Energy Management containing rights to develop offshore wind generation in a 260 square-mile area located southeast of Martha’s Vineyard. The area subject to easement has the capacity for siting up to approximately 3,000 MW. In May 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. In 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project. Under the provisions of the LLC agreement, Renewables has contributed $137 million to Vineyard Wind. Contributions were made to a second offshore development project of $106 million to enter into the easement contract. We expect to provide additional capital contributions. The amount receivable from Vineyard was $3 million and $5 million as of March 31, 2020 and December 31, 2019 , respectively. AVANGRID manages its overall 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 March 31, 2020 and December 31, 2019 , was zero and $150 million , respectively. AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023 . AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of March 31, 2020 and December 31, 2019 , there was no outstanding amount under this credit facility.

Other Financial Statement Items

Other Financial Statement Items	3 Months Ended
	Mar. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Other Financial Statement Items	Other Financial Statement Items Accounts receivable and unbilled revenue, net Accounts receivable and unbilled revenues, net as of March 31, 2020 and December 31, 2019 consisted of: As of March 31, 2020 December 31, 2019 (Millions) Trade receivables and unbilled revenues $ 1,150 $ 1,151 Allowance for credit losses (73 ) (69 ) Accounts receivable and unbilled revenues, net $ 1,077 $ 1,082 The change in the allowance for credit losses for the three months ended March 31, 2020 and 2019 consisted of: Three Months Ended March 31, (Millions) 2020 2019 As of January 1, $ 69 $ 62 Current period provision 19 21 Write-off as uncollectible (15 ) (17 ) As of March 31, $ 73 $ 66 Deferred Payment Arrangements (DPA) receivable balances were $63 million and $65 million at March 31, 2020 and December 31, 2019 , respectively. The allowance for credit losses for DPAs at both March 31, 2020 and December 31, 2019 was $33 million . Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2020 and 2019 was $0 and $1 million , respectively. Prepayments and other current assets Included in prepayments and other current assets are $152 million and $123 million of prepaid other taxes as of March 31, 2020 and December 31, 2019 , respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of March 31, 2020 and December 31, 2019 , respectively, were as follows: March 31, December 31, As of 2020 2019 (Millions) Property, plant and equipment Accumulated depreciation $ 9,262 $ 9,059 Intangible assets Accumulated amortization $ 308 $ 305 Debt As of March 31, 2020 and December 31, 2019 , "Notes Payable" consisted of $383 million and $562 million , respectively, of commercial paper outstanding and $350 million and $0 , respectively, drawn on our revolving credit facility, presented net of discounts on our condensed consolidated balance sheets. On April 9, 2020, AGR issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20% .

Income Tax Expense

Income Tax Expense	3 Months Ended
	Mar. 31, 2020
Income Tax Disclosure [Abstract]
Income Tax Expense	Income Tax Expense The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2020 , was 5.0% which is below the federal statutory tax rate of 21% , primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act. The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2019 , was 16.0% which is lower than the federal statutory tax rate of 21% , primarily due to the recognition of production tax credits associated with wind production, partially offset by discrete tax adjustments recorded during the period.

Stock-Based Compensation Expens

Stock-Based Compensation Expense	3 Months Ended
	Mar. 31, 2020
Share-based Payment Arrangement [Abstract]
Stock-Based Compensation Expense	Stock-Based Compensation Expense The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares). In June and October 2018, 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vest in full in one installment in June and December 2020, respectively, for each award, provided that the award holders remain continuously employed with AVANGRID through such dates. The fair value on the grant date was determined based on a price of $50.40 and $47.59 per share, respectively, for June and October 2018 awards. 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 will be payable in three equal installments, net of applicable taxes, in 2020 , 2021 and 2022 . The remaining unvested PSUs were forfeited. On March 18, 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. As of March 31, 2020, the total liability is $1 million , which is included in other current and non-current liabilities. The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2020 and 2019 was $7 million and $1 million

Variable Interest Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Variable Interest Entities	Variable Interest Entities We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). 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 March 2, 2020, we closed on two TEF agreements, receiving $237 million from two tax equity investors related to two wind farms that reached commercial operation. The two wind farms are the first in a portfolio of companies called Aeolus Wind Power VII, LLC (Aeolus VII). One more newly constructed wind farm and one wind farm undergoing a repowering will become a part of Aeolus VII once the projects are complete and TEF agreements are finalized. The four wind farms expected to be part of Aeolus VII will total 681 MW of wind power. The assets and liabilities of the VIEs totaled approximately $1,497 million and $56 million , respectively, at March 31, 2020 . As of December 31, 2019 , the assets and liabilities of VIEs totaled approximately $806 million and $29 million , respectively. At March 31, 2020 and December 31, 2019 , the assets and liabilities of the VIEs consisted primarily of property, plant and equipment. At March 31, 2020 , we consider El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot) and Aeolus VII to be VIEs. Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind farms. Under these structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments. The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met. Our El Cabo, Patriot and Aeolus VII 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.

Restructuring and Severance Rel

Restructuring and Severance Related Expenses	3 Months Ended
	Mar. 31, 2020
Restructuring and Related Activities [Abstract]
Restructuring and Severance Related Expenses	Restructuring and Severance Related Expenses In 2017, we announced initial targeted voluntary workforce reductions predominantly within the Networks segment. Those actions primarily include: reducing our workforce through voluntary programs in various areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology (IT) workforce to make increasing use of external services for operations, support and development of systems. In 2019, we also announced changes across the Company aimed to mitigate costs and deliver sustainable growth, including among others, outsourcing and insourcing of certain areas of the Company and technology initiatives that help improve efficiency and reduce costs. Those decisions and transactions resulted in restructuring charges of $2 million and $0 recorded for the three months ended March 31, 2020 and 2019, respectively, which are included in "Operations and maintenance" and $1 million and $0 , respectively, recorded in "Depreciation and amortization" in our condensed consolidated statements of income. The remaining costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods through December 2020. As of March 31, 2020 , our severance and lease restructuring charges reserves, which are recorded in "Other current liabilities" and "Other liabilities" on our condensed consolidated balance sheets, consisted of: Three Months Ended March 31, 2020 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 2 Payments (2 ) Ending Balance $ 5

Subsequent Event

Subsequent Event	3 Months Ended
	Mar. 31, 2020
Subsequent Events [Abstract]
Subsequent Event	Subsequent Event On April 27, 2020, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on July 1, 2020 to shareholders of record at the close of business on June 2, 2020.

Significant Accounting Polici_2

Significant Accounting Policies and New Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 2020
Accounting Policies [Abstract]
Goodwill	Goodwill 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 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 of first performing 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 that 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.
Accounts receivable and unbilled revenue, net	Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain accounts receivable and payable 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. Accounts receivable include amounts due under Deferred Payment Arrangements (DPAs). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as short term. We establish our allowance for credit losses, including for unbilled revenue, 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. Due to our adoption of Accounting Standards Codification (ASC) 326 effective January 1, 2020, we now also 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 accounts receivable. We write off amounts when we have exhausted reasonable collection efforts.
New Accounting Pronouncements	Adoption of New Accounting Pronouncements (a) Measurement of credit losses on financial instruments, amendments and updates The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments (ASC 326). The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The FASB subsequently issued various updates to ASC 326 to clarify transition and scope requirements, make narrow-scope codification improvements, including in March 2020, and corrections and provide targeted transition relief. We adopted the amendments effective January 1, 2020, including the narrow-scope improvements issued in March 2020, and recorded a cumulative-effect adjustment of $1 million to retained earnings at the beginning of the period of adoption, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. (b) Simplifying the test for goodwill impairment In January 2017, the FASB issued amendments to simplify the test for goodwill impairment, which are required for public entities and certain other entities that have goodwill reported in their financial statements. The amendments simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test, which requires the valuation of assets acquired and liabilities assumed using business combination accounting guidance. Under the new guidance, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Also, an entity should consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. Certain requirements are eliminated for any reporting unit with a zero or negative carrying amount; therefore, the same impairment assessment applies to all reporting units. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we will apply the amendments on a prospective basis. (c) Changes to the disclosure requirements for fair value measurement and defined benefit plans In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans. The amendments concerning fair value measurement remove, modify and add certain disclosure requirements in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. We adopted the amendments effective January 1, 2020, with no material effect to our disclosures. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively. The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. The amendments change annual disclosures requirements, including removal of disclosures that are no longer considered cost beneficial, adding certain new relevant disclosures and clarifying specific requirements of disclosures concerning information for defined benefit pension plans. We adopted the amendments effective January 1, 2020, and they will not materially affect the disclosures for our fiscal year ending December 31, 2020. As required, our application will be on a retrospective basis. (d) Targeted improvements to related party guidance for VIEs In October 2018, the FASB issued amendments that affect reporting entities that are required to determine whether they should consolidate a legal entity under the consolidation guidance applicable to VIEs. The targeted improvements specifically applicable to public business entities clarify that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. (e) Clarifying guidance for certain collaborative arrangements with respect to revenue recognition The FASB issued amendments in November 2018 to clarify the interaction between the guidance for certain collaborative arrangements and the guidance applicable to ASC 606. A collaborative arrangement is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. The targeted improvements clarify that certain transactions between collaborative arrangement participants are within the scope of ASC 606 and thus subject to all of its guidance. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we retrospectively applied the amendments to the date of our initial application of ASC 606. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2019, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements. (a) Simplifying the accounting for income taxes In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes , eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. The amendments are effective for public business entities for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued, with adoption of all amendments in the same period. Application is on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment aspect. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows. (b) Facilitation of the effects of reference rate reform on financial reporting In March 2020, the FASB issued amendments to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 2020
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2020 and 2019 are as follows: Three Months Ended March 31, 2020 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 873 $ — $ — $ 873 Regulated operations – natural gas 507 — — 507 Nonregulated operations – wind — 211 — 211 Nonregulated operations – solar — 4 — 4 Nonregulated operations – thermal — 10 — 10 Other(a) 19 28 — 47 Revenue from contracts with customers 1,399 253 — 1,652 Leasing revenue 1 — — 1 Derivative revenue — 70 — 70 Alternative revenue programs 56 — — 56 Other revenue 5 5 — 10 Total operating revenues $ 1,461 $ 328 $ — $ 1,789 Three Months Ended March 31, 2019 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 913 $ — $ — $ 913 Regulated operations – natural gas 625 — — 625 Nonregulated operations – wind — 182 — 182 Nonregulated operations – solar — 5 — 5 Nonregulated operations – thermal — 16 — 16 Other(a) 37 (7 ) (4 ) 26 Revenue from contracts with customers 1,575 196 (4 ) 1,767 Leasing revenue 1 — — 1 Derivative revenue — 41 — 41 Alternative revenue programs 16 — — 16 Other revenue 12 5 — 17 Total operating revenues $ 1,604 $ 242 $ (4 ) $ 1,842 (a) Primarily includes certain intra-month trading activities, billing, collection and administrative charges, sundry billings and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations	As of March 31, 2020 , the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows: As of March 31, 2020 2021 2022 2023 2024 2025 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1 $ 1 $ 1 $ 1 $ — $ — $ 4 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 35 19 11 8 7 17 97 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 17 9 6 4 3 5 44 Total operating revenues $ 53 $ 29 $ 18 $ 13 $ 10 $ 22 $ 145

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2020
Regulated Operations [Abstract]
Schedule of Delivery Rate Increases	The below table provides a summary of the initial proposed delivery rate increases, delivery revenue percentages and total revenue percentages for all four businesses: Requested Revenue Increase Delivery Revenue Total Revenue Utility (Millions) % % NYSEG Electric $ 156.7 20.4 % 10.4 % NYSEG Gas $ 6.3 3.0 % 1.4 % RG&E Electric $ 31.7 7.0 % 4.1 % RG&E Gas $ 5.8 3.3 % 1.4 %
Schedule of Current and Non-Current Regulatory Assets	Regulatory assets as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Pension and other post-retirement benefits cost deferrals $ 113 $ 125 Pension and other post-retirement benefits 1,027 1,061 Storm costs 332 272 Rate adjustment mechanism 28 79 Revenue decoupling mechanism 61 19 Transmission revenue reconciliation mechanism 5 5 Contracts for differences 95 92 Hardship programs 24 29 Plant decommissioning 3 5 Deferred purchased gas 2 25 Deferred transmission expense 19 11 Environmental remediation costs 273 277 Debt premium 92 97 Unamortized losses on reacquired debt 29 29 Unfunded future income taxes 402 399 Federal tax depreciation normalization adjustment 152 153 Asset retirement obligation 20 17 Deferred meter replacement costs 26 27 Other 164 139 Total regulatory assets 2,867 2,861 Less: current portion 299 294 Total non-current regulatory assets $ 2,568 $ 2,567
Schedule of Current and Non-Current Regulatory Liabilities	Regulatory liabilities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Energy efficiency portfolio standard $ 71 $ 72 Gas supply charge and deferred natural gas cost 18 11 Pension and other post-retirement benefits cost deferrals 75 80 Carrying costs on deferred income tax bonus depreciation 43 49 Carrying costs on deferred income tax - Mixed Services 263(a) 14 15 2017 Tax Act 1,559 1,548 Revenue decoupling mechanism 11 17 Accrued removal obligations 1,179 1,173 Asset sale gain account 10 10 Economic development 27 27 Positive benefit adjustment 36 37 Theoretical reserve flow thru impact 12 14 Deferred property tax 35 17 Net plant reconciliation 23 23 Debt rate reconciliation 72 67 Rate refund – FERC ROE proceeding 32 32 Transmission congestion contracts 24 23 Merger-related rate credits 15 16 Accumulated deferred investment tax credits 13 13 Asset retirement obligation 17 14 Earning sharing provisions 28 28 Middletown/Norwalk local transmission network service collections 18 18 Low income programs 31 33 Non-firm margin sharing credits 12 16 New York 2018 winter storm settlement 11 11 Other 175 159 Total regulatory liabilities 3,561 3,523 Less: current portion 260 242 Total non-current regulatory liabilities $ 3,301 $ 3,281

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2020
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of March 31, 2020 and December 31, 2019 , respectively, consisted of: As of March 31, 2020 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 37 $ 11 $ — $ — $ 48 Derivative assets Derivative financial instruments - power 2 42 125 (63 ) 106 Derivative financial instruments - gas 1 33 32 (65 ) 1 Contracts for differences — — 2 — 2 Total 3 75 159 (128 ) 109 Derivative liabilities Derivative financial instruments - power (37 ) (28 ) (39 ) 98 (6 ) Derivative financial instruments - gas — (22 ) (6 ) 28 — Contracts for differences — — (97 ) — (97 ) Derivative financial instruments – other — (39 ) (2 ) — (41 ) Total $ (37 ) $ (89 ) $ (144 ) $ 126 $ (144 ) As of December 31, 2019 Level 1 Level 2 Level 3 Netting Total (Millions) Equity investments with readily determinable fair values $ 38 $ 13 $ — $ — $ 51 Derivative assets Derivative financial instruments - power 4 23 120 (54 ) 93 Derivative financial instruments - gas — 40 31 (71 ) — Contracts for differences — — 2 — 2 Total 4 63 153 (125 ) 95 Derivative liabilities Derivative financial instruments - power (28 ) (43 ) (29 ) 92 (8 ) Derivative financial instruments - gas (4 ) (26 ) (5 ) 33 (2 ) Contracts for differences — — (94 ) — (94 ) Derivative financial instruments - other — (1 ) — — (1 ) Total $ (32 ) $ (70 ) $ (128 ) $ 125 $ (105 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2020 and 2019 , respectively, is as follows: Three Months Ended March 31, (Millions) 2020 2019 Fair Value Beginning of Period, $ 25 $ (15 ) Gains recognized in operating revenues 13 25 (Losses) recognized in operating revenues (10 ) (13 ) Total gains recognized in operating revenues 3 12 Gains recognized in OCI 1 1 (Losses) recognized in OCI (5 ) (15 ) Total gains recognized in OCI (4 ) (14 ) Net change recognized in regulatory assets and liabilities (3 ) (2 ) Purchases — — Settlements (6 ) (3 ) Fair Value as of March 31, $ 15 $ (22 ) Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 3 $ 12 Range at Unobservable Input March 31, 2020 Risk of non-performance 1.13% - 1.68% Discount rate 0.37% - 0.55% Forward pricing ($ per KW-month) $2.00 - $7.03
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. As of March 31, 2020 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 2.84 $ 4.90 $ 1.60 Indiana hub ($/MWh) $ 30.15 $ 61.12 $ 16.79 Mid C ($/MWh) $ 24.68 $ 105.00 $ (0.50 ) Minn hub ($/MWh) $ 24.72 $ 52.17 $ 12.48 NoIL hub ($/MWh) $ 26.93 $ 55.39 $ 12.98 Ercot S hub ($/MWh) $ 31.20 $ 248.39 $ 11.41

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	3 Months Ended
	Mar. 31, 2020
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts	The tables below present Networks' derivative positions as of March 31, 2020 and December 31, 2019 , respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets: As of March 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 2 $ 3 $ 2 $ 1 Derivative liabilities (1 ) (1 ) (42 ) (92 ) 1 2 (40 ) (91 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (5 ) (4 ) — — (5 ) (4 ) Total derivatives before offset of cash collateral 1 2 (45 ) (95 ) Cash collateral receivable — — 28 6 Total derivatives as presented in the balance sheet $ 1 $ 2 $ (17 ) $ (89 ) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 1 $ 4 $ 1 $ 2 Derivative liabilities (1 ) (2 ) (39 ) (86 ) — 2 (38 ) (84 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1 ) (1 ) — — (1 ) (1 ) Total derivatives before offset of cash collateral — 2 (39 ) (85 ) Cash collateral receivable — — 27 1 Total derivatives as presented in the balance sheet $ — $ 2 $ (12 ) $ (84 ) The tables below present Renewables' derivative positions as of March 31, 2020 and December 31, 2019 , respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets: As of March 31, 2020 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 35 $ 108 $ 37 $ 17 Derivative liabilities (1 ) (2 ) (43 ) (21 ) 34 106 (6 ) (4 ) Designated as hedging instruments Derivative assets — 17 8 8 Derivative liabilities — (13 ) (8 ) (7 ) — 4 — 1 Total derivatives before offset of cash collateral 34 110 (6 ) (3 ) Cash collateral receivable (payable) (11 ) (27 ) 1 1 Total derivatives as presented in the balance sheet $ 23 $ 83 $ (5 ) $ (2 ) As of December 31, 2019 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 23 $ 110 $ 42 $ 13 Derivative liabilities (1 ) (7 ) (48 ) (18 ) 22 103 (6 ) (5 ) Designated as hedging instruments Derivative assets — 18 5 4 Derivative liabilities — (9 ) (13 ) (6 ) — 9 (8 ) (2 ) Total derivatives before offset of cash collateral 22 112 (14 ) (7 ) Cash collateral receivable (payable) (11 ) (30 ) 7 6 Total derivatives as presented in the balance sheet $ 11 $ 82 $ (7 ) $ (1 )
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks activities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Wholesale electricity purchase contracts (MWh) 4.7 5.1 Natural gas purchase contracts (Dth) 7.7 8.5 Fleet fuel purchase contracts (Gallons) 2.3 2.2 The net notional volumes of outstanding derivative instruments associated with Renewables activities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (MWh/Dth in millions) Wholesale electricity purchase contracts 4 4 Wholesale electricity sales contracts 9 9 Natural gas and other fuel purchase contracts 29 29 Financial power contracts 11 10 Basis swaps – purchases 41 42 Basis swaps – sales 2 1
Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 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) 2020 Interest rate contracts $ — Interest expense $ 1 $ 76 Commodity contracts (2 ) Purchased power, natural gas and fuel used — 475 Foreign currency exchange contracts (6 ) — Total $ (8 ) $ 1 2019 Interest rate contracts $ — Interest expense $ 2 $ 78 Commodity contracts 1 Purchased power, natural gas and fuel used — 563 Total $ 1 $ 2 (a) Changes in accumulated OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, (Loss) Recognized in OCI on Derivatives (a) Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Interest rate contracts $ (31 ) Interest expense $ 1 $ 76 2019 Interest rate contracts $ (20 ) Interest expense $ — $ 78 (a) Changes in OCI are reported on a pre-tax basis. The amount in accumulated OCI is being reclassified into earnings over the underlying debt maturity period which ends in 2029. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, Gain (Loss) Recognized in OCI on Derivatives (a) Location of Loss (Gain) Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income Total amount per Income Statement (Millions) 2020 Commodity contracts $ 7 Operating revenues $ — $ 1,789 2019 Commodity contracts $ (20 ) Operating revenues $ — $ 1,842 (a) Changes in OCI are reported on a pre-tax basis.
Summary of Unrealized Gains and Losses from Fair Value Adjustments	The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2020 and 2019 , respectively, were as follows: Three Months Ended March 31, 2020 2019 (Millions) Derivative assets $ — $ (1 ) Derivative liabilities $ (3 ) $ (1 ) The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2020 and December 31, 2019 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2020 and 2019 are as follows: (Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income As of Three Months Ended March 31, March 31, 2020 Electricity Natural Gas 2020 Electricity Natural Gas Regulatory assets $ 34 $ — Purchased power, natural gas and fuel used $ 21 $ 5 December 31, 2019 2019 Regulatory assets $ 24 $ 4 Purchased power, natural gas and fuel used $ 4 $ —
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables activities as of March 31, 2020 and December 31, 2019 , respectively, consisted of: March 31, December 31, As of 2020 2019 (Millions) Wholesale electricity purchase contracts $ (2 ) $ 10 Wholesale electricity sales contracts 22 4 Natural gas and other fuel purchase contracts — (2 ) Financial power contracts 79 73 Total $ 99 $ 85
Effect of Derivatives Associated with Renewables and Gas Activities	The effects of trading and non-trading derivatives associated with Renewables activities for the three months ended March 31, 2020 , consisted of: Three Months Ended March 31, 2020 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ (1 ) $ — Wholesale electricity sales contracts 4 11 Financial power contracts — 22 Total gain included in operating revenues $ 3 $ 33 $ 1,789 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ (11 ) Financial power contracts — (6 ) Financial and natural gas contracts — (2 ) Total loss included in purchased power, natural gas and fuel used $ — $ (19 ) $ 475 Total Gain $ 3 $ 14 The effects of trading and non-trading derivatives associated with Renewables activities for the three months ended March 31, 2019 , consisted of: Three Months Ended March 31, 2019 Trading Non-trading Total amount per income statement (Millions) Operating Revenues Wholesale electricity purchase contracts $ 1 $ — Wholesale electricity sales contracts — (9 ) Financial power contracts (1 ) (13 ) Financial and natural gas contracts (1 ) (2 ) Total loss included in operating revenues $ (1 ) $ (24 ) $ 1,842 Purchased power, natural gas and fuel used Wholesale electricity purchase contracts $ — $ 20 Financial power contracts — 1 Financial and natural gas contracts — 7 Total gain included in purchased power, natural gas and fuel used $ — $ 28 $ 563 Total (Loss) Gain $ (1 ) $ 4
Derivative Liabilities	The table below presents our interest rate swap derivative positions as of March 31, 2020 and December 31, 2019 , respectively, including the location of the net derivative positions on our condensed consolidated balance sheets: As of March 31, 2020 Current Liabilities (Millions) Designated as hedging instruments Derivative liabilities $ (31 ) As of December 31, 2019 Designated as hedging instruments Derivative liabilities $ —

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	3 Months Ended
	Mar. 31, 2020
Retirement Benefits [Abstract]
Components of Net Periodic Pension and Postretirement Benefits	The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions) Service cost $ 12 $ 10 Interest cost 27 33 Expected return on plan assets (50 ) (48 ) Amortization of: Actuarial loss 31 30 Net Periodic Benefit Cost $ 20 $ 25 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions) Service cost $ 1 $ 1 Interest cost 3 4 Expected return on plan assets (2 ) (2 ) Amortization of: Prior service costs (2 ) (2 ) Net Periodic Benefit Cost $ — $ 1

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2020
Equity [Abstract]
Accumulated Other Comprehensive Gain (Loss)	Accumulated Other Comprehensive Loss for the three months ended March 31, 2020 and 2019 , respectively, consisted of: As of December 31, Three Months Ended March 31, As of March 31, As of December 31, Adoption of new accounting Three Months Ended March 31, As of March 31, 2019 2020 2020 2018 standard 2019 2019 (Millions) Change in revaluation of defined benefit plans $ (12 ) $ — $ (12 ) $ (11 ) $ (2 ) $ — $ (13 ) Loss on nonqualified pension plans (7 ) — (7 ) (6 ) — — (6 ) Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(8.5) for 2020 and $(10.9) for 2019 (13 ) (23 ) (36 ) 9 — (29 ) (20 ) Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $0.3 for 2020 and $0.7 for 2019(a) (63 ) 2 (61 ) (64 ) (10 ) 2 (72 ) Loss on derivatives qualifying as cash flow hedges (76 ) (21 ) (97 ) (55 ) (10 ) (27 ) (92 ) Accumulated Other Comprehensive Loss $ (95 ) $ (21 ) $ (116 ) $ (72 ) $ (12 ) $ (27 ) $ (111 ) (a)Reclassification is reflected in the operating expenses line item in our condensed consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2020
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 240 $ 217 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,491,082 Weighted average number of shares outstanding - diluted 309,623,573 309,712,308 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.78 $ 0.70 Earnings Per Common Share, Diluted $ 0.78 $ 0.70

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2020
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the three months ended March 31, 2020 , consisted of: Three Months Ended March 31, 2020 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,461 $ 328 $ — $ 1,789 Depreciation and amortization 148 103 — 251 Operating income 309 13 5 327 Earnings (losses) from equity method investments 2 (8 ) — (6 ) Interest expense, net of capitalization 68 1 7 76 Income tax expense (benefit) 43 (30 ) (1 ) 12 Adjusted net income 198 46 (8 ) 236 Capital expenditures 437 305 — 742 As of March 31, 2020 Property, plant and equipment 16,036 9,442 10 25,488 Equity method investments 138 518 — 656 Total assets $ 23,355 $ 11,942 $ (704 ) $ 34,593 (a) Includes Corporate and intersegment eliminations. Segment information for the three months ended March 31, 2019 and as of December 31, 2019 , consisted of: Three Months Ended March 31, 2019 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,600 $ 242 $ — $ 1,842 Revenue - intersegment 4 — (4 ) — Depreciation and amortization 134 88 — 222 Operating income (loss) 331 13 (3 ) 341 Earnings (losses) from equity method investments 3 (2 ) — 1 Interest expense, net of capitalization 68 4 6 78 Income tax expense (benefit) 64 1 (24 ) 41 Adjusted net income 201 5 13 219 Capital expenditures 324 101 — 425 As of December 31, 2019 Property, plant and equipment 15,840 9,368 10 25,218 Equity method investments 139 506 — 645 Total assets $ 23,250 $ 13,163 $ (1,997 ) $ 34,416 (a) Includes Corporate and intersegment eliminations.
Schedule of Reconciliation of Adjusted Net Income to Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2020 and 2019 , respectively, is as follows: Three Months Ended March 31, 2020 2019 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 236 $ 219 Adjustments: Mark-to-market earnings - Renewables (1) 18 3 Restructuring charges (2) (3 ) — Accelerated depreciation from repowering (3) (10 ) (5 ) Income tax impact of adjustments (2 ) — Net Income Attributable to Avangrid, Inc. $ 240 $ 217 (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) Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth. (3) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables.

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2020
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three months ended March 31, 2020 and 2019 , respectively, consisted of: Three Months Ended March 31, 2020 2019 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Renovables Energía, S.L. $ — $ (2 ) $ — $ (4 ) Iberdrola Financiación, S.A. $ — $ (1 ) $ — $ — Iberdrola, S.A. $ — $ (10 ) $ — $ (10 ) Vineyard Wind $ 2 $ — $ — $ — Other $ — $ — $ — $ (1 )
Schedule of Related Party Balances	Related party balances as of March 31, 2020 and December 31, 2019 , respectively, consisted of: As of March 31, 2020 December 31, 2019 (Millions) Owed By Owed To Owed By Owed To Iberdrola, S.A. $ 1 $ (10 ) $ 1 $ (42 ) Iberdrola Renovables Energía, S.L. $ — $ (2 ) $ — $ — Iberdrola Financiación, S.A. $ — $ (1 ) $ — $ — Vineyard Wind $ 3 $ — $ 5 $ — Iberdrola Solutions $ — $ (14 ) $ — $ — Siemens-Gamesa (a) $ — $ — $ — $ (18 ) Other $ — $ (2 ) $ 4 $ (4 ) (a) After Iberdrola's sale of its interest of Siemens-Gamesa in February 2020, transactions with Siemens-Gamesa are no longer considered related party.

Other Financial Statement Ite_2

Other Financial Statement Items (Tables)	3 Months Ended
	Mar. 31, 2020
Balance Sheet Related Disclosures [Abstract]
Schedule of Accounts, Notes, Loans and Financing Receivable	Accounts receivable and unbilled revenues, net as of March 31, 2020 and December 31, 2019 consisted of: As of March 31, 2020 December 31, 2019 (Millions) Trade receivables and unbilled revenues $ 1,150 $ 1,151 Allowance for credit losses (73 ) (69 ) Accounts receivable and unbilled revenues, net $ 1,077 $ 1,082
Accounts Receivable, Allowance for Credit Loss	The change in the allowance for credit losses for the three months ended March 31, 2020 and 2019 consisted of: Three Months Ended March 31, (Millions) 2020 2019 As of January 1, $ 69 $ 62 Current period provision 19 21 Write-off as uncollectible (15 ) (17 ) As of March 31, $ 73 $ 66
Schedule of Accumulated Depreciation and Amortization	The accumulated depreciation and amortization as of March 31, 2020 and December 31, 2019 , respectively, were as follows: March 31, December 31, As of 2020 2019 (Millions) Property, plant and equipment Accumulated depreciation $ 9,262 $ 9,059 Intangible assets Accumulated amortization $ 308 $ 305

Restructuring and Severance R_2

Restructuring and Severance Related Expenses (Tables)	3 Months Ended
	Mar. 31, 2020
Restructuring and Related Activities [Abstract]
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities	As of March 31, 2020 , our severance and lease restructuring charges reserves, which are recorded in "Other current liabilities" and "Other liabilities" on our condensed consolidated balance sheets, consisted of: Three Months Ended March 31, 2020 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 2 Payments (2 ) Ending Balance $ 5

Background and Nature Of Oper_2

Background and Nature Of Operations (Detail)	3 Months Ended
	Mar. 31, 2020
Avangrid | Iberdrola S.A.
Nature Of Business [Line Items]
Ownership percentage held by parent	81.50%

Significant Accounting Polici_3

Significant Accounting Policies and New Accounting Pronouncements - Narrative (Details) - USD ($) $ in Millions	Mar. 31, 2020	Jan. 01, 2020	Dec. 31, 2019
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings	$ 1,784		$ 1,681
Cumulative Effect, Period of Adoption, Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Retained earnings		$ 1

Revenue - Narrative (Detail)

Revenue - Narrative (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Utility Revenue [Line Items]
Contract assets	$ 12
TCC contract liabilities	5	$ 10
Revenue recognized	5
Accounts receivable related to contracts with customers	1,039	1,050
Unbilled revenues	$ 312	$ 345
Networks
Utility Revenue [Line Items]
Revenue performance obligation, timing	P1Y
Renewables
Utility Revenue [Line Items]
Capitalized contract cost amortization term	15 years
Capitalized contract cost expected life	10 years

Revenue - Narrative Revenue Ter

Revenue - Narrative Revenue Term (Details) - Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-04-01	Mar. 31, 2020
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Auction period	9 months
Transmission congestion contracts | Minimum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Auction period	6 months
Transmission congestion contracts | Maximum
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Auction period	2 years

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Segment Reporting Information [Line Items]
Operating revenues	$ 1,652	$ 1,767
Lease Income	1	1
Derivative revenue	70	41
Alternative revenue programs	56	16
Other revenue	10	17
Revenues	1,789	1,842
Electricity
Segment Reporting Information [Line Items]
Operating revenues	873	913
Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	507	625
Wind Energy
Segment Reporting Information [Line Items]
Operating revenues	211	182
Solar Energy
Segment Reporting Information [Line Items]
Operating revenues	4	5
Thermal Energy
Segment Reporting Information [Line Items]
Operating revenues	10	16
Other
Segment Reporting Information [Line Items]
Operating revenues	47	26
Networks
Segment Reporting Information [Line Items]
Operating revenues	1,399	1,575
Lease Income	1	1
Alternative revenue programs	56	16
Other revenue	5	12
Revenues	1,461	1,604
Networks | Electricity
Segment Reporting Information [Line Items]
Operating revenues	873	913
Networks | Natural Gas
Segment Reporting Information [Line Items]
Operating revenues	507	625
Networks | Other
Segment Reporting Information [Line Items]
Operating revenues	19	37
Renewables
Segment Reporting Information [Line Items]
Operating revenues	253	196
Lease Income	0	0
Derivative revenue	70	41
Other revenue	5	5
Revenues	328	242
Renewables | Wind Energy
Segment Reporting Information [Line Items]
Operating revenues	211	182
Renewables | Solar Energy
Segment Reporting Information [Line Items]
Operating revenues	4	5
Renewables | Thermal Energy
Segment Reporting Information [Line Items]
Operating revenues	10	16
Renewables | Other
Segment Reporting Information [Line Items]
Operating revenues	28	(7)
Other
Segment Reporting Information [Line Items]
Operating revenues	0	(4)
Lease Income	0	0
Revenues	0	(4)
Other | Other
Segment Reporting Information [Line Items]
Operating revenues	$ 0	$ (4)

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Detail) $ in Millions	Mar. 31, 2020USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 64
Remaining performance obligation, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 53
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	29
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	18
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	13
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	10
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	22
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	145
Retail Energy Sales Contracts In Place | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Retail Energy Sales Contracts In Place | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Retail Energy Sales Contracts In Place | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Retail Energy Sales Contracts In Place | 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	$ 1
Remaining performance obligation, period	1 year
Retail Energy Sales Contracts In Place | 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	$ 0
Remaining performance obligation, period	1 year
Retail Energy Sales Contracts In Place | 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	$ 0
Remaining performance obligation, period
Retail Energy Sales Contracts In Place | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 4
Capacity And Carbon Free Energy Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 35
Remaining performance obligation, period	1 year
Capacity And Carbon Free Energy Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 19
Remaining performance obligation, period	1 year
Capacity And Carbon Free Energy Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 11
Remaining performance obligation, period	1 year
Capacity And Carbon Free Energy Sale Contracts | 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	$ 8
Remaining performance obligation, period	1 year
Capacity And Carbon Free Energy Sale Contracts | 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	$ 7
Remaining performance obligation, period	1 year
Capacity And Carbon Free Energy Sale Contracts | 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	$ 17
Remaining performance obligation, period
Capacity And Carbon Free Energy Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 97
Renewable Energy Credit Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 17
Remaining performance obligation, period	1 year
Renewable Energy Credit Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 9
Remaining performance obligation, period	1 year
Renewable Energy Credit Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 6
Remaining performance obligation, period	1 year
Renewable Energy Credit Sale Contracts | 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	$ 4
Remaining performance obligation, period	1 year
Renewable Energy Credit Sale Contracts | 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	$ 3
Remaining performance obligation, period	1 year
Renewable Energy Credit Sale Contracts | 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	$ 5
Remaining performance obligation, period
Renewable Energy Credit Sale Contracts | Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 44

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Additional Information (Detail) - USD ($) $ in Millions

Sep. 15, 2019

Jun. 17, 2019

May 20, 2019

Feb. 22, 2019

Jan. 18, 2019

Dec. 19, 2018

Aug. 30, 2018

May 17, 2018

Dec. 31, 2017

Dec. 31, 2016

Mar. 31, 2020

Mar. 31, 2019

Apr. 30, 2019

Apr. 30, 2018

Apr. 30, 2017

Dec. 31, 2019

Dec. 31, 2018

Regulatory Assets And Liabilities [Line Items]

Unrecorded regulatory assets

$ 1,728

Equity ratio

50.00%

Public utilities regulatory authority distribution rate

9.10%

Environmental reserve

$ 342

$ 349

Equity ratio, year three

55.00%

Rate increase agreement, term

3 years

Regulatory assets

$ 2,867

2,861

Unfunded future Income tax expense collection period

50 years

NEW YORK

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Asset sale gain account

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Carrying costs on deferred income tax bonus depreciation

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Economic development

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Merger capital expense target customer credit

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Positive benefit adjustment

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Theoretical reserve flow thru impact

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

UIL Holdings

Regulatory Assets And Liabilities [Line Items]

Business combination merger related rate credits

$ 1

$ 1

Maximum | NEW YORK

Regulatory Assets And Liabilities [Line Items]

Deferred income tax recovery period

39 years

Minimum | NEW YORK

Regulatory Assets And Liabilities [Line Items]

Deferred income tax recovery period

27 years

Electric and Gas Service Rate Plan Year One

Regulatory Assets And Liabilities [Line Items]

Customer receiving percentage

50.00%

Return on equity

9.75%

9.65%

9.50%

Electric and Gas Service Rate Plan Year Two

Regulatory Assets And Liabilities [Line Items]

Customer receiving percentage

75.00%

Return on equity

10.25%

10.15%

10.00%

Electric and Gas Service Rate Plan Year Three

Regulatory Assets And Liabilities [Line Items]

Customer receiving percentage

90.00%

Return on equity

10.75%

10.65%

10.50%

Storm costs

Regulatory Assets And Liabilities [Line Items]

Regulatory assets

$ 332

$ 272

Central Maine Power

Regulatory Assets And Liabilities [Line Items]

Recovery of deferred storm costs

74

Central Maine Power | Maximum

Regulatory Assets And Liabilities [Line Items]

Proposed tariff rate decrease based on ROE

1.00%

1.00%

Central Maine Power | Minimum

Regulatory Assets And Liabilities [Line Items]

Proposed tariff rate decrease based on ROE

0.75%

0.75%

NYSEG

Regulatory Assets And Liabilities [Line Items]

Recovery of deferred storm costs

$ 30

Regulatory items amortization period

3 years

Storm costs not included in joint proposal

$ 136

Annual amortization of regulatory items

$ 16.5

Approved return on equity

9.00%

Equity ratio

48.00%

Environmental reserve

$ 31.1

NYSEG | Maximum

Regulatory Assets And Liabilities [Line Items]

Equity ratio for earnings sharing

50.00%

NYSEG | Electric

Regulatory Assets And Liabilities [Line Items]

Amount of proposed ROE increase (decrease), total

$ 76.7

NYSEG | Derivative financial instruments - gas

Regulatory Assets And Liabilities [Line Items]

Amount of proposed ROE increase (decrease), total

(15.9)

NYSEG | Storm costs

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

10 years

NYSEG | Regulatory Items Other Than Storm Costs

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

NYSEG | Deferred Income Tax Charge

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

50 years

RG&E

Regulatory Assets And Liabilities [Line Items]

Storm costs not included in joint proposal

$ 60

Approved return on equity

9.00%

Equity ratio

48.00%

RG&E | Deferred property tax

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

RG&E | Maximum

Regulatory Assets And Liabilities [Line Items]

Equity ratio for earnings sharing

50.00%

RG&E | Electric

Regulatory Assets And Liabilities [Line Items]

Amount of proposed ROE increase (decrease), total

0.7

RG&E | Derivative financial instruments - gas

Regulatory Assets And Liabilities [Line Items]

Amount of proposed ROE increase (decrease), total

$ (22.5)

RG&E | Deferred Income Tax Charge

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

50 years

Southern Connecticut Gas Company S C G

Regulatory Assets And Liabilities [Line Items]

Equity ratio

52.00%

Public utilities regulatory authority distribution rate

9.25%

Amount of approved ROE for the year 2018

$ 1.5

Amount of approved ROE for the year 2019

4.7

Amount of approved ROE for the year 2020

$ 5

Berkshire Gas Company

Regulatory Assets And Liabilities [Line Items]

Proposed alternative ratemaking mechanism term

5 years

Connecticut Natural Gas Corporation

Regulatory Assets And Liabilities [Line Items]

Amount Of Proposed ROE for the year 2019

$ 9.9

Amount of proposed ROE for the year 2020

4.6

Amount of proposed ROE for the year 2021

$ 5.2

PURA

Regulatory Assets And Liabilities [Line Items]

Equity ratio

54.00%

Percentage of proposed return on equity, year one

9.30%

Equity ratio, year two

54.50%

BGC

Regulatory Assets And Liabilities [Line Items]

Equity ratio

55.00%

Public utilities regulatory authority distribution rate

9.70%

Amount of approved ROE for the year 2018

$ 1.6

Amount of approved ROE for the year 2019

$ 0.7

NYSEG | Deferred property tax

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

NYDPS

Regulatory Assets And Liabilities [Line Items]

Equity ratio for earnings sharing

50.00%

Return on equity

9.50%

NYPSC

Regulatory Assets And Liabilities [Line Items]

Equity ratio

48.00%

Public utilities regulatory authority distribution rate

8.20%

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities Regulatory Assets and Liabilities - Rate Increases (Details) $ in Millions	May 20, 2019USD ($)
Electric | NYSEG
Regulatory Liabilities [Line Items]
Requested Revenue Increase	$ 156.7
Delivery Revenue	20.40%
Total Revenue	10.40%
Electric | RG&E
Regulatory Liabilities [Line Items]
Requested Revenue Increase	$ 31.7
Delivery Revenue	7.00%
Total Revenue	4.10%
Gas | NYSEG
Regulatory Liabilities [Line Items]
Requested Revenue Increase	$ 6.3
Delivery Revenue	3.00%
Total Revenue	1.40%
Gas | RG&E
Regulatory Liabilities [Line Items]
Requested Revenue Increase	$ 5.8
Delivery Revenue	3.30%
Total Revenue	1.40%

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,867	$ 2,861
Less: current portion	299	294
Total non-current regulatory assets	2,568	2,567
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	113	125
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	1,027	1,061
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	332	272
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	28	79
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	61	19
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	5	5
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	95	92
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	24	29
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	3	5
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	2	25
Deferred transmission expense
Regulatory Assets [Line Items]
Total regulatory assets	19	11
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	273	277
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	92	97
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	29	29
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	402	399
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	152	153
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	17
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	26	27
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 164	$ 139

Regulatory Assets and Liabili_6

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,561	$ 3,523
Less: current portion	260	242
Total non-current regulatory liabilities	3,301	3,281
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	71	72
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	11
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	75	80
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	43	49
Carrying costs on deferred income tax - Mixed Services 263
Regulatory Liabilities [Line Items]
Total regulatory liabilities	14	15
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,559	1,548
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	17
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,179	1,173
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	10	10
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	27	27
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	36	37
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	12	14
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	35	17
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	23
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	72	67
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	32	32
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	23
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	16
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	13
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	14
Earning sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	28
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	18
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	31	33
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	12	16
New York 2018 Winter Storm Settlement [Member]
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	11
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 175	$ 159

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 346	$ 311
Fair value of debt	$ 7,963	$ 8,168
Minimum
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value input, gas or power delivery period (in years)	2 years
Restricted Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 6
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	70.00%

Fair Value of Financial Instr_4

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 109	$ 95
Derivative liabilities	(144)	(105)
Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(128)	(125)
Derivative liabilities	126	125
Equity investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	48	51
Equity investments with readily determinable fair values | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	0	0
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	106	93
Derivative liabilities	(6)	(8)
Derivative financial instruments - power | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(63)	(54)
Derivative liabilities	98	92
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	0
Derivative liabilities	0	(2)
Derivative financial instruments - gas | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(65)	(71)
Derivative liabilities	28	33
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	2
Derivative liabilities	(97)	(94)
Contracts for differences | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(41)	(1)
Derivative financial instruments – other | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	3	4
Derivative liabilities	(37)	(32)
Level 1 | Equity investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	37	38
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	4
Derivative liabilities	(37)	(28)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	1	0
Derivative liabilities	0	(4)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 1 | Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	75	63
Derivative liabilities	(89)	(70)
Level 2 | Equity investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	11	13
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	42	23
Derivative liabilities	(28)	(43)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	33	40
Derivative liabilities	(22)	(26)
Level 2 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 2 | Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	(39)	(1)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	159	153
Derivative liabilities	(144)	(128)
Level 3 | Equity investments with readily determinable fair values
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	0	0
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	125	120
Derivative liabilities	(39)	(29)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	32	31
Derivative liabilities	(6)	(5)
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	2	2
Derivative liabilities	(97)	(94)
Level 3 | Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities	$ (2)	$ 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 (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Fair Value, Instruments Classified in Shareholders' Equity Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward] (Deprecated 2019-01-31)
Fair Value Beginning of Period,	$ 25	$ (15)
Gains recognized in operating revenues	13	25
(Losses) recognized in operating revenues	(10)	(13)
Total gains recognized in operating revenues	3	12
Gains recognized in OCI	1	1
(Losses) recognized in OCI	(5)	(15)
Total gains recognized in OCI	(4)	(14)
Net change recognized in regulatory assets and liabilities	(3)	(2)
Purchases	0	0
Settlements	(6)	(3)
Fair Value as of March 31,	15	(22)
Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$ 3	$ 12

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	3 Months Ended
	Mar. 31, 2020$ / MMBTU$ / MWh
NYMEX ($/MMBtu) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	2.84
NYMEX ($/MMBtu) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	4.90
NYMEX ($/MMBtu) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	1.60
Indiana hub ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	30.15
Indiana hub ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	61.12
Indiana hub ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	16.79
Mid C ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	24.68
Mid C ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	105
Mid C ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability, liability	(0.50)
Minn hub ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	24.72
Minn hub ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	52.17
Minn hub ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	12.48
NoIL hub ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	26.93
NoIL hub ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	55.39
NoIL hub ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	12.98
Ercot S hub ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	31.20
Ercot S hub ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	248.39
Ercot S hub ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	11.41

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Detail) - Contracts for differences - Level 3	3 Months Ended
	Mar. 31, 2020$ / MWh
Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	1.13%
Forward pricing ($ per MWh)	2
Minimum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Discount rate	0.0037
Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	1.68%
Forward pricing ($ per MWh)	7.03
Maximum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Discount rate	0.0055

Derivative Instruments and He_3

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 109	$ 95
Derivative Liability	(144)	(105)
Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liabilities	(31)	0
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	1	0
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	1	0
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	1
Derivative liabilities	(1)	(1)
Derivative Asset	1	0
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	2	2
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	2	2
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	4
Derivative liabilities	(1)	(2)
Derivative Asset	2	2
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(45)	(39)
Cash collateral (payable) receivable, Liability	28	27
Total derivatives as presented in the balance sheet, Liability	(17)	(12)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	1
Derivative liabilities	(42)	(39)
Derivative Liability	(40)	(38)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	(5)	(1)
Derivative Liability	(5)	(1)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(95)	(85)
Cash collateral (payable) receivable, Liability	6	1
Total derivatives as presented in the balance sheet, Liability	(89)	(84)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	2
Derivative liabilities	(92)	(86)
Derivative Liability	(91)	(84)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	(4)	(1)
Derivative Liability	(4)	(1)
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	34	22
Cash collateral (payable) receivable, Asset	(11)	(11)
Total derivatives as presented in the balance sheet, Asset	23	11
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	35	23
Derivative liabilities	(1)	(1)
Derivative Asset	34	22
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	110	112
Cash collateral (payable) receivable, Asset	(27)	(30)
Total derivatives as presented in the balance sheet, Asset	83	82
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	108	110
Derivative liabilities	(2)	(7)
Derivative Asset	106	103
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	17	18
Derivative liabilities	(13)	(9)
Derivative Asset	4	9
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(6)	(14)
Cash collateral (payable) receivable, Liability	1	7
Total derivatives as presented in the balance sheet, Liability	(5)	(7)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	37	42
Derivative liabilities	(43)	(48)
Derivative Liability	(6)	(6)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	8	5
Derivative liabilities	(8)	(13)
Derivative Liability	0	(8)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(3)	(7)
Cash collateral (payable) receivable, Liability	1	6
Total derivatives as presented in the balance sheet, Liability	(2)	(1)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	17	13
Derivative liabilities	(21)	(18)
Derivative Liability	(4)	(5)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	8	4
Derivative liabilities	(7)	(6)
Derivative Liability	$ 1	$ (2)

Derivative Instruments and He_4

Derivative Instruments and Hedging - Net Notional Volume (Detail) gal in Millions, dth in Millions, MWh in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2020galdthMWh	Dec. 31, 2019galdthMWh
Networks | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount | MWh	4.7	5.1
Networks | Natural Gas Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	7.7	8.5
Networks | Fleet Fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount | gal	2.3	2.2
Renewables and Gas Activities | Long | Basis Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	41	42
Renewables and Gas Activities | Short | Basis Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	2	1
Renewables and Gas Activities | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure (MWh) | MWh	4	4
Renewables and Gas Activities | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure (MWh) | MWh	9	9
Renewables and Gas Activities | Natural Gas and Other fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	29	29
Renewables and Gas Activities | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	11	10

Derivative Instruments and He_5

Derivative Instruments and Hedging - Additional Information (Detail)	Jan. 31, 2020USD ($)Swap	Mar. 31, 2020USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2020USD ($)	Dec. 31, 2019USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory Assets		$ 2,867,000,000			$ 2,861,000,000
Regulatory liabilities		3,561,000,000			3,523,000,000
UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross derivative asset		2,000,000			2,000,000
Regulatory Assets		95,000,000			92,000,000
Gross amounts of recognized liabilities		98,000,000			94,000,000
Regulatory liabilities		$ 0			0
Contracts for differences | UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers		20.00%
Contracts for differences | CL&P
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers		80.00%
Gross derivative asset		$ 0			0
Gross amounts of recognized liabilities		94,000,000			92,000,000
Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative settled		750,000,000
Net loss in cashflow hedge		37,000,000			38,000,000
Net loss in accumulated OCI related to discontinued cash flow hedge		1,000,000	$ 0
Number of derivatives entered into | Swap	2
Derivative notional amount	$ 600,000,000
Amortization of net loss		3,000,000
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge		8,000,000	(1,000,000)
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge		1,000,000	2,000,000
Derivative instruments, losses expected to be reclassified into earnings in the next 12 months		(9,000,000)
Loss to be reclassified into earnings		$ 2,000,000
Derivative instrument, estimate of time to transfer		12 months
Maximum period of time of cash flow hedges		12 months
Networks | Fuel Derivatives | Cash Flow Hedging | Maximum
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges		12 months
Renewables and Gas Activities | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative reclassification estimate		$ 3,000,000
Renewables and Gas Activities | Cash Flow Hedging | Forecast
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in accumulated OCI related to discontinued cash flow hedge				$ 3,000,000
Counter Party
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross amounts of recognized liabilities		35,000,000
Cash collateral pledged		17,000,000			21,000,000
Counter Party | UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative collateral obligation to be paid in decrease in credit rating below investment grade		16,000,000
Swap | Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps		54,000,000			55,000,000
Non-trading | Renewables and Gas Activities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) reclassified from regulatory assets and liabilities into income		14,000,000	$ 4,000,000
Iberdrola Solutions
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notes payable		$ 14,000,000			$ 0

Derivative Instruments and He_6

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Derivative assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain (loss) on derivatives	$ 0	$ (1)
Derivative liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain (loss) on derivatives	(3)	(1)
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	34		$ 24
Unrealized gain (loss) on derivatives	21	4
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0		$ 4
Unrealized gain (loss) on derivatives	$ 5	$ 0

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	$ 1,789	$ 1,842
Interest Expense	76	78
Purchased power, natural gas and fuel used	475	563
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	1,461	1,604
Net loss in cashflow hedge	8	(1)
Net loss in cashflow hedge, tax effect	(1)	(2)
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge	31	20
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge	0	0
Net loss in cashflow hedge, tax effect	(1)	(2)
Interest rate contracts | Other | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge, tax effect	(1)	0
Commodity contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge	2	(1)
Net loss in cashflow hedge, tax effect	0	0
Commodity contracts | Renewables and Gas Activities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge	(7)	20
Commodity contracts | Renewables and Gas Activities | Operating revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge, tax effect	0	$ 0
Foreign currency exchange contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss in cashflow hedge	6
Net loss in cashflow hedge, tax effect	$ 0

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 99	$ 85
Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	79	73
Long | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(2)	10
Long | Natural Gas and Other fuel Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	0	(2)
Short | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 22	$ 4

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total gain included in operating revenues	$ 1,789	$ 1,842
Total loss included in purchased power, natural gas and fuel used	475	563
Renewables and Gas Activities | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	3	(1)
Renewables and Gas Activities | Trading | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		1
Renewables and Gas Activities | Trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		(1)
Renewables and Gas Activities | Trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		0
Renewables and Gas Activities | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	14	4
Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		0
Renewables and Gas Activities | Non-trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		(13)
Renewables and Gas Activities | Non-trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		(9)
Operating revenues | Renewables and Gas Activities | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	3	(1)
Operating revenues | Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	(1)
Operating revenues | Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	4
Operating revenues | Renewables and Gas Activities | Trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	0
Operating revenues | Renewables and Gas Activities | Trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		(1)
Operating revenues | Renewables and Gas Activities | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	33	(24)
Operating revenues | Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	0
Operating revenues | Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	11
Operating revenues | Renewables and Gas Activities | Non-trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	22
Operating revenues | Renewables and Gas Activities | Non-trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain		(2)
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	0	0
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	0	0
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	0	0
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	0	0
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	(19)	28
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	(11)	20
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	(6)	1
Purchased power, natural gas and fuel used | Renewables and Gas Activities | Non-trading | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain	$ (2)	$ 7

Derivative Instruments and H_10

Derivative Instruments and Hedging - Derivative Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Designated as hedging instruments | Current Liabilities
Derivative [Line Items]
Derivative liabilities	$ (31)	$ 0

Contingencies (Detail)

Contingencies (Detail) customer in Thousands, $ in Millions	Feb. 06, 2020USD ($)	Apr. 18, 2019recommendation	Mar. 22, 2016	Mar. 03, 2015	Oct. 16, 2014	Oct. 31, 2018complaint	Apr. 30, 2018	Mar. 31, 2020USD ($)	Dec. 31, 2019USD ($)	May 01, 2018USD ($)	Mar. 31, 2018stormcustomer
Loss Contingencies [Line Items]
Regulatory liabilities								$ 3,301	$ 3,281
Price of the power purchase agreements								259
Requested renewables delay from preliminary proposed ruling period							2 years
Standby letters of credit								441
March 2018 Windstorm
Loss Contingencies [Line Items]
Number of severe winter storm | storm											2
Number of affected customers | customer											520
Amount awarded to other party	$ 10.5
Complaint II
Loss Contingencies [Line Items]
Regulatory liabilities								25
Complaint III
Loss Contingencies [Line Items]
Regulatory liabilities								7
Complaint II and III
Loss Contingencies [Line Items]
Reasonably possible loss, in additional reserve, pre tax								$ 17
Unfavorable Regulatory Action | Complaint I
Loss Contingencies [Line Items]
Approved return on equity			9.59%		10.57%	9.88%
Refund period term								15 months
Requested existing base return on equity base percentage						10.41%
Number of claims | complaint						4
Unfavorable Regulatory Action | Complaint I | Maximum
Loss Contingencies [Line Items]
Approved return on equity			10.42%	11.74%	11.74%	10.99%
Requested existing base return on equity base percentage						13.08%
Unfavorable Regulatory Action | Complaint I | Minimum
Loss Contingencies [Line Items]
Approved return on equity						9.60%
Unfavorable Regulatory Action | Complaint III
Loss Contingencies [Line Items]
Approved return on equity			10.90%
Unfavorable Regulatory Action | Complaint III | Maximum
Loss Contingencies [Line Items]
Approved return on equity			12.19%
Before Amendment
Loss Contingencies [Line Items]
Approved return on equity								11.14%
Amphora Gas Storage USA, LLC
Loss Contingencies [Line Items]
Claim for indemnification										$ 20
Indemnification liability, percentage of purchase price										15.00%
Indemnification liability, maximum amount										$ 10
NYPSC
Loss Contingencies [Line Items]
Number of recommendations | recommendation		94

Environmental Liabilities (Deta

Environmental Liabilities (Detail) $ in Millions	Apr. 24, 2020USD ($)	Sep. 11, 2014USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)site	Mar. 31, 2020USD ($)site	Dec. 31, 2019USD ($)	Aug. 04, 2016USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						25
Number of sites with liability recorded | site						11
Number of sits note expected to incur additional liabilities | site						14
Number of additional sites with liability recorded | site						11
Number of sites where gas was manufactured in the past | site						53,000,000
Number of sites for which we have entered into consent orders to investigate and remediate | site						41,000,000
Costs related to investigation and remediation						$ 342	$ 349
Accrual for environmental loss contingencies		$ 27				$ 20
Number of sites with modified decision | site						9
Damages for incurred costs payment amount		$ 22
Refund of environmental remediation cost paid				$ 5
First Energy
Environmental Exit Cost [Line Items]
Former manufactured gas sites | site					16
Reasonably possible loss, in additional reserve, net of tax					$ 60
Environmental costs paid			$ 30
First Energy | Past Costs
Environmental Exit Cost [Line Items]
Accrual for environmental loss contingencies			27
First Energy | Pre-judgment Interest
Environmental Exit Cost [Line Items]
Environmental costs paid			$ 3
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 15	$ 16	$ 30
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						17
Number of sites where gas was manufactured in the past | site						8
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						6
Number of sites where gas was manufactured in the past | site						2
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						7
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability						$ 6
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability						9
Another Ten Sites | Minimum
Environmental Exit Cost [Line Items]
Estimated environmental liability						13
Another Ten Sites | Maximum
Environmental Exit Cost [Line Items]
Estimated environmental liability						$ 23
New York Voluntary Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site						3
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site						3
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 97
Manufactured Gas Plants | Minimum
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						158
Manufactured Gas Plants | Maximum
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 424
Subsequent Event
Environmental Exit Cost [Line Items]
Loss Contingency, Damages Sought, Value	$ 5

Post-Retirement and Similar O_3

Post-Retirement and Similar Obligations - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)
Retirement Benefits [Abstract]
Defined benefit, pension contributions	$ 10
Additional contributions for remainder of fiscal year	$ 73

Post-Retirement and Similar O_4

Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 12	$ 10
Interest cost	27	33
Expected return on plan assets	(50)	(48)
Amortization of actuarial loss	31	30
Net Periodic Benefit Cost	20	25
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1
Interest cost	3	4
Expected return on plan assets	(2)	(2)
Amortization of prior service costs	(2)	(2)
Net Periodic Benefit Cost	$ 0	$ 1

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		27 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Mar. 31, 2020	Dec. 31, 2019
Class of Stock [Line Items]
Common stock, authorized (in shares)	500,000,000		500,000,000	500,000,000
Common stock, issued (in shares)	309,752,140		309,752,140	309,752,140
Common stock, outstanding (in shares)	309,005,485		309,005,485	309,005,272
Common stock, par value (in usd per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Common stock, issued	$ 3		$ 3	$ 3
Additional paid-in capital	$ 13,667		$ 13,667	$ 13,660
Treasury stock, shares (in shares)	485,597		485,597	485,810
Convertible preferred stock, shares outstanding (in shares)	0		0	0
Issuances of common stock (in shares)	0	0
Release of common stock held in trust (in shares)		0
Treasury shares of common stock (in shares)	261,058		261,058
Repurchases of common stock (in shares)			0
Repurchases of common stock	$ 12		$ 12	$ 12
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent	81.50%		81.50%	81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Gain (Loss) (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Jan. 01, 2020	Jan. 01, 2019
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	$ 15,237
Adoption of new accounting standards			$ (1)	$ (1)
Other comprehensive income (loss), net of tax	(21)	$ (27)
Period End	15,326
Other comprehensive income (loss), taxes	10.2	8.2
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(95)	(72)
Adoption of new accounting standards				(12)
Other comprehensive income (loss), net of tax	(21)	(27)
Period End	(116)	(111)
Gain on revaluation of defined benefit plans net of tax expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(12)	(11)
Adoption of new accounting standards				(2)
Other comprehensive income (loss), net of tax	0	0
Period End	(12)	(13)
Other comprehensive income (loss), taxes		0.2
Loss on nonqualified pension plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(7)	(6)
Adoption of new accounting standards				0
Other comprehensive income (loss), net of tax	0
Period End	(7)	(6)
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(13)	9
Other comprehensive income (loss), net of tax	(23)	(29)
Period End	(36)	(20)
Other comprehensive income (loss), taxes	8.5	10.9
Reclassification to net income of (gains) losses on cash flow hedges, net of income tax (benefit) expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(63)	(64)
Adoption of new accounting standards				(10)
Other comprehensive income (loss), net of tax	2	2
Period End	(61)	(72)
Other comprehensive income (loss), taxes	(0.3)	(0.7)
Accumulated Gain (Loss), Net, Cash Flow Hedge, Parent
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(76)	(55)
Adoption of new accounting standards				$ (10)
Other comprehensive income (loss), net of tax	(21)	(27)
Period End	$ (97)	$ (92)

Earnings Per Share (Detail)

Earnings Per Share (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Numerator:
Net income attributable to AVANGRID	$ 240	$ 217
Denominator:
Weighted average number of shares outstanding - basic (in shares)	309,491,082	309,491,082
Weighted average number of shares outstanding - diluted (in shares)	309,623,573	309,712,308
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in usd per share)	$ 0.78	$ 0.70
Earnings Per Common Share, Diluted (in usd per share)	$ 0.78	$ 0.70

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2020USD ($)segment	Mar. 31, 2019USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | segment	2
Revenues | $	$ 1,789	$ 1,842
Networks
Segment Reporting Information [Line Items]
Number of reportable segments | segment	1
Number of operating segments | segment	8
Revenues | $	$ 1,461	1,604
Renewables
Segment Reporting Information [Line Items]
Revenues | $	$ 328	$ 242

Segment Information - Adjusted

Segment Information - Adjusted Net Income (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenues	$ 1,789	$ 1,842
Depreciation and amortization	251	222
Operating income (loss)	327	341
Earnings (losses) from equity method investments	(6)	1
Interest expense, net of capitalization	76	78
Income tax expense (benefit)	12	41
Adjusted net income	236	219
Capital expenditures	742	425
Property, plant and equipment	25,488		$ 25,218
Equity method investments	656		645
Total assets	34,593		34,416
Networks
Segment Reporting Information [Line Items]
Revenues	1,461	1,604
Renewables
Segment Reporting Information [Line Items]
Revenues	328	242
Operating Segments | Networks
Segment Reporting Information [Line Items]
Revenues	1,461	1,600
Depreciation and amortization	148	134
Operating income (loss)	309	331
Earnings (losses) from equity method investments	2	3
Interest expense, net of capitalization	68	68
Income tax expense (benefit)	43	64
Adjusted net income	198	201
Capital expenditures	437	324
Property, plant and equipment	16,036		15,840
Equity method investments	138		139
Total assets	23,355		23,250
Operating Segments | Renewables
Segment Reporting Information [Line Items]
Revenues	328	242
Depreciation and amortization	103	88
Operating income (loss)	13	13
Earnings (losses) from equity method investments	(8)	(2)
Interest expense, net of capitalization	1	4
Income tax expense (benefit)	(30)	1
Adjusted net income	46	5
Capital expenditures	305	101
Property, plant and equipment	9,442		9,368
Equity method investments	518		506
Total assets	11,942		13,163
Intersegment Eliminations
Segment Reporting Information [Line Items]
Revenues		(4)
Intersegment Eliminations | Networks
Segment Reporting Information [Line Items]
Revenues		4
Intersegment Eliminations | Renewables
Segment Reporting Information [Line Items]
Revenues		0
Corporate And Eliminations
Segment Reporting Information [Line Items]
Revenues	0	0
Depreciation and amortization	0	0
Operating income (loss)	5	(3)
Earnings (losses) from equity method investments	0	0
Interest expense, net of capitalization	7	6
Income tax expense (benefit)	(1)	(24)
Adjusted net income	(8)	13
Capital expenditures	0	$ 0
Property, plant and equipment	10		10
Equity method investments	0		0
Total assets	$ (704)		$ (1,997)

Segment Information - Reconcili

Segment Information - Reconciliation of Adjusted Net Income to Net Income (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 236	$ 219
Adjustments:
Mark-to-market earnings - Renewables	18	3
Restructuring charges	(3)	0
Accelerated depreciation from repowering	(10)	(5)
Income tax impact of adjustments	(2)	0
Net Income Attributable to Avangrid, Inc.	$ 240	$ 217

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Purchases From	$ (2)	$ (4)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Purchases From	(1)	0
Iberdrola, S.A.
Related Party Transaction [Line Items]
Purchases From	(10)	(10)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	2	0
Other
Related Party Transaction [Line Items]
Sales To	0	0
Purchases From	$ 0	$ (1)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details)	Mar. 02, 2020MW	May 31, 2018MW	Mar. 31, 2020USD ($)mi²MW	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)
Related Party Transaction [Line Items]
Proposed wind farm and electricity transmission project capacity (MW) | MW	681
Portion of amount receivable from related parties					$ 1,000,000
Deposit balance			$ 0		150,000,000
Line of credit facility fee basis points			0.105%
Credit facility outstanding amount			$ 350,000,000		0
Affiliated Entity
Related Party Transaction [Line Items]
Impairments			$ 0
New York Transco
Related Party Transaction [Line Items]
New electric generation and transmission capacity (MW) | MW			3,200
Amount of commitment funded to date			$ 600,000,000
Vineyard Wind
Related Party Transaction [Line Items]
New electric generation and transmission capacity (MW) | MW		804
Leased area transmission capacity (MW) | MW			3,000
Proposed wind farm and electricity transmission project capacity (MW) | MW		800
Portion of amount receivable from related parties			$ 3,000,000		5,000,000
Iberdrola Solutions
Related Party Transaction [Line Items]
Portion of amount receivable from related parties					0
Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity			500,000,000
Credit facility outstanding amount			$ 0
Iberdrola, S.A. | Siemens-Gamesa
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired			8.10%
Related party transaction, amount			$ 11,000,000	$ 18,000,000
Networks | New York Transco
Related Party Transaction [Line Items]
Business combination, equity interest percentage			20.00%
Amount of commitment funded to date			$ 120,000,000
Portion of amount receivable from related parties			$ 0		1,000,000
Renewables | Vineyard Wind
Related Party Transaction [Line Items]
Business combination, equity interest percentage			50.00%
Amount of commitment funded to date			$ 137,000,000
Square mileage of land containing development rights | mi²			260
Portion of amount receivable from related parties			$ 3,000,000		$ 5,000,000
Renewables | Second Offshore Development Project
Related Party Transaction [Line Items]
Amount of commitment funded to date			$ 106,000,000

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Related Party Transaction [Line Items]
Owed By		$ 1
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	$ 1
Owed To	(10)	(42)
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Owed To	(2)	0
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed By		0
Owed To	(1)	0
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	3	5
Owed To	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By		0
Owed To	(14)
Siemens-Gamesa
Related Party Transaction [Line Items]
Owed To		(18)
Other
Related Party Transaction [Line Items]
Owed By	0	4
Owed To	$ (2)	$ (4)

Other Financial Statement Ite_3

Other Financial Statement Items - Additional Information (Detail) - USD ($)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019	Apr. 09, 2020	Dec. 31, 2019	Dec. 31, 2018
Supplemental Balance Sheet Information [Line Items]
Allowance for doubtful accounts, deferred payment arrangement	$ 73,000,000	$ 66,000,000		$ 69,000,000	$ 62,000,000
Provision for doubtful accounts, accounts receivable	19,000,000	21,000,000
Prepaid other taxes	152,000,000			123,000,000
Notes payable	731,000,000			560,000,000
Credit facility outstanding amount	350,000,000			0
Deferred Payment Arrangements
Supplemental Balance Sheet Information [Line Items]
Accounts receivable	63,000,000			65,000,000
Allowance for doubtful accounts, deferred payment arrangement	33,000,000			33,000,000
Provision for doubtful accounts, accounts receivable	0	$ 1,000,000
Commercial Paper
Supplemental Balance Sheet Information [Line Items]
Notes payable	$ 383,000,000			$ 562,000,000
Subsequent Event | Senior Notes Due 2029 through 2049 | Senior Notes
Supplemental Balance Sheet Information [Line Items]
Face amount of debt			$ 750,000,000
Interest rate			3.20%

Other Financial Statement Ite_4

Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019
Property, plant and equipment
Accumulated depreciation	$ 9,262	$ 9,059
Intangible assets
Accumulated amortization	$ 308	$ 305

Other Financial Statement Ite_5

Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - USD ($) $ in Millions	Mar. 31, 2020	Dec. 31, 2019	Mar. 31, 2019	Dec. 31, 2018
Balance Sheet Related Disclosures [Abstract]
Trade receivables and unbilled revenues	$ 1,150	$ 1,151
Allowance for credit losses	(73)	(69)	$ (66)	$ (62)
Accounts receivable and unbilled revenues, net	$ 1,077	$ 1,082

Other Financial Statement Ite_6

Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
As of January 1,	$ 73	$ 66
Current period provision	19	21
Write-off as uncollectible	(15)	(17)
As of March 31,	$ 69	$ 62

Income Tax Expense (Details)

Income Tax Expense (Details)	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Income Tax Disclosure [Abstract]
Effective income tax rate	5.00%	16.00%

Stock-Based Compensation Expe_2

Stock-Based Compensation Expense (Detail) $ / shares in Units, $ in Millions	Mar. 18, 2020shares	Feb. 29, 2020shares	Oct. 31, 2018$ / sharesshares	Jun. 30, 2018$ / sharesshares	Mar. 31, 2020USD ($)installment	Mar. 31, 2019USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares) | shares	167,060	208,268
Share based compensation liability | $					$ 1
Stock-based compensation expense | $					$ 7	$ 1
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares) | shares			8,000	60,000
Share-based Compensation Arrangement by Share-based Payment Award, Equity Instruments Other than Options, Nonvested, Weighted Average Grant Date Fair Value | $ / shares			$ 47.59	$ 50.40
Performance Shares Units | Officers and Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of installment payments of employee related payables | installment					3

Variable Interest Entities (Det

Variable Interest Entities (Detail) $ in Millions	Mar. 02, 2020USD ($)wind_farmMW	Mar. 31, 2020USD ($)	Mar. 31, 2019USD ($)	Dec. 31, 2019USD ($)
Variable Interest Entity [Line Items]
Contributions from noncontrolling interests	$ 237	$ 244	$ 3
Wind firms that reached commercial operation | wind_farm	2
Wind farms expected to be part of Aeolus VII | wind_farm	4
Proposed wind farm and electricity transmission project capacity (MW) | MW	681
Assets of variable interest entities (VIEs)		34,593		$ 34,416
Liabilities of variable interest entities (VIEs)		18,685		18,830
Equity method investments of variable interest entities (VIEs)		656		645
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)		1,497		806
Liabilities of variable interest entities (VIEs)		$ 56		$ 29

Restructuring and Severance R_3

Restructuring and Severance Related Expenses - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2020	Mar. 31, 2019
Restructuring Reserve [Roll Forward]
Beginning Balance	$ 5
Severance Costs	2
Payments	(2)
Ending Balance	5
Operations and Maintenance
Restructuring Reserve [Roll Forward]
Severance Costs	2	$ 0
Depreciation And Amortization
Restructuring Reserve [Roll Forward]
Severance Costs	$ 1	$ 0

Subsequent Event Narrative (Det

Subsequent Event Narrative (Details) - $ / shares	Apr. 27, 2020	Mar. 31, 2020	Mar. 31, 2019
Subsequent Event [Line Items]
Dividends declared (in usd per share)		$ 0.44	$ 0.44
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in usd per share)	$ 0.44

Uncategorized Items - avangrid2

Label	Element	Value
Parent [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ (1,000,000)
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(1,000,000)
Retained Earnings [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	(1,000,000)
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	11,000,000
Noncontrolling Interest [Member]
Cumulative Effect of New Accounting Principle in Period of Adoption	us-gaap_CumulativeEffectOfNewAccountingPrincipleInPeriodOfAdoption	$ 0