Avangrid (AGR) 10-Q 3 May 18 2018 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2018	May 01, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q1
Trading Symbol	AGR
Entity Registrant Name	Avangrid, Inc.
Entity Central Index Key	1,634,997
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		309,005,272

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Income Statement [Abstract]
Operating Revenues	$ 1,865	$ 1,758
Operating Expenses
Purchased power, natural gas and fuel used	576	465
Loss from assets held for sale	5
Operations and maintenance	527	522
Depreciation and amortization	203	197
Taxes other than income taxes	151	147
Total Operating Expenses	1,462	1,331
Operating Income	403	427
Other Income and (Expense)
Other expense	(21)	(16)
Earnings from equity method investments	2	2
Interest expense, net of capitalization	(74)	(71)
Income Before Income Tax	310	342
Income tax expense	72	103
Net Income	238	239
Less: Net loss attributable to noncontrolling interests	(6)
Net Income Attributable to Avangrid, Inc.	$ 244	$ 239
Earnings Per Common Share, Basic	$ 0.79	$ 0.77
Earnings Per Common Share, Diluted	$ 0.79	$ 0.77
Weighted-average Number of Common Shares Outstanding:
Basic	309,513,640	309,508,889
Diluted	309,793,064	309,837,442
Cash Dividends Declared Per Common Share	$ 0.432	$ 0.432

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Statement Of Income And Comprehensive Income [Abstract]
Net Income		$ 238	$ 239
Other Comprehensive Income, Net of Tax Amounts arising during the period:
Unrealized gain during the period on derivatives qualifying as cash flow hedges, net of income tax			2
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]	(10)	23
Other Comprehensive (Loss) Income		(10)	25
Comprehensive Income		228	264
Less: Net loss attributable to noncontrolling interests		(6)
Comprehensive Income Attributable to Avangrid, Inc.		$ 234	$ 264
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Condensed Consolidated Stateme4

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement Of Income And Comprehensive Income [Abstract]
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit		$ 1.3
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	$ (7.5)	$ 13.6

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 40	$ 41
Accounts receivable and unbilled revenues, net	1,113	1,040
Accounts receivable from affiliates	8	10
Derivative assets	20	18
Fuel and gas in storage	57	99
Materials and supplies	123	115
Prepayments and other current assets	232	273
Assets held for sale	79	357
Regulatory assets	309	307
Total Current Assets	1,981	2,260
Total Property, Plant and Equipment ($1,289 and $1,303 related to VIEs, respectively)	22,757	22,669
Equity method investments	348	352
Other investments	63	63
Regulatory assets	2,714	2,738
Deferred income taxes regulatory	20
Other Assets
Goodwill	3,127	3,127
Intangible assets	327	328
Derivative assets	63	63
Other	83	71
Total Other Assets	3,600	3,589
Total Assets	31,483	31,671
Current Liabilities
Current portion of debt	214	183
Tax equity financing arrangements - VIEs		38
Notes payable	631	757
Notes payable to affiliates	31	29
Interest accrued	65	57
Accounts payable and accrued liabilities	928	1,071
Accounts payable to affiliates	65	89
Dividends payable	134	134
Taxes accrued	59	89
Derivative liabilities	24	22
Liabilities held for sale	7	137
Other current liabilities	356	330
Regulatory liabilities	202	178
Total Current Liabilities	2,716	3,114
Regulatory liabilities	3,287	3,239
Deferred income taxes regulatory		13
Other Non-current Liabilities
Deferred income taxes	1,510	1,452
Deferred income	1,429	1,446
Pension and other postretirement	1,044	1,049
Tax equity financing arrangements - VIEs		60
Derivative liabilities	103	92
Asset retirement obligations	199	196
Environmental remediation costs	351	358
Other	365	360
Total Other Non-current Liabilities	5,001	5,013
Non-current Debt	5,160	5,196
Total Non-current Liabilities	13,448	13,461
Total Liabilities	16,164	16,575
Commitments and Contingencies
Stockholders’ Equity:
Common stock	3	3
Additional paid in capital	13,654	13,653
Treasury Stock	(8)	(8)
Retained earnings	1,579	1,475
Accumulated other comprehensive loss	(57)	(46)
Total Stockholders’ Equity	15,171	15,077
Non-controlling interests	148	19
Total Equity	15,319	15,096
Total Liabilities and Equity	$ 31,483	$ 31,671

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Property, Plant and Equipment, VIEs	$ 22,757	$ 22,669
Common stock, par value	$ 0.01	$ 0.01
Common stock, authorized	500,000,000	500,000,000
Common stock, issued	309,752,140	309,670,932
Common stock, outstanding	309,086,480	309,005,272
Variable Interest Entity, Primary Beneficiary [Member]
Property, Plant and Equipment, VIEs	$ 1,289	$ 1,303

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Cash Flow from Operating Activities:
Net Income	$ 238	$ 239
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	203	197
Loss from assets held for sale	5
Accretion expenses	3	3
Regulatory assets/liabilities amortization	19	19
Regulatory assets/liabilities carrying cost	2	10
Pension cost	31	28
Stock-based compensation		1
Earnings from equity method investments	(2)	(2)
Amortization of debt (premium) discount	(1)	2
Unrealized gain on marked-to-market derivative contracts	(8)	(27)
Deferred taxes	63	95
Other non-cash items	(6)	(22)
Changes in operating assets and liabilities:
Accounts receivable and unbilled revenues	(70)	11
Inventories	36	11
Other assets/liabilities	96	64
Cash distribution from equity method investments	3	3
Accounts payable and accrued liabilities	(51)	(155)
Taxes accrued	(29)	9
Regulatory assets/liabilities	65	(45)
Net Cash Provided by Operating Activities	597	441
Cash Flow from Investing Activities:
Capital expenditures	(399)	(525)
Contributions in aid of construction	7	6
Proceeds from sale of assets	67	1
Cash distribution from equity method investments	2	2
Other investments and equity method investments, net		2
Net Cash Used in Investing Activities	(323)	(514)
Cash Flow from Financing Activities:
Repayments of non-current debt	(2)	(4)
(Repayments) receipts of other short-term debt, net	(124)	205
Payments on tax equity financing arrangements		(27)
Repayments of capital leases	(8)	(27)
Issuance of common stock	(2)	(1)
Distributions to noncontrolling interests	(11)
Contributions from noncontrolling interests	6
Dividends paid	(134)	(134)
Net Cash (Used in) Provided by Financing Activities	(275)	12
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(1)	(61)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	46	96	$ 96
Cash, Cash Equivalents and Restricted Cash, End of Period	45	35	$ 46
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	49	45
Cash (refund)/paid for income taxes	$ (17)	$ 3

Condensed Consolidated Stateme8

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 at Dec. 31, 2016		$ 15,208	$ 3		$ 13,653	$ (5)	$ 1,630	$ (86)	$ 15,195	$ 13
Balance, shares at Dec. 31, 2016	[1]		308,993,149
Net Income		239					239		239
Other comprehensive income (loss), net of tax		25						25	25
Comprehensive Income		264
Dividends declared		$ (134)					(134)		(134)
Release of common stock held in trust		5,649	5,649	[1]
Issuance of common stock, issuance costs		$ (1)			(1)				(1)
Issuance of common stock, shares		70,493	70,493	[1]
Stock-based compensation		$ 1			1				1
Balance at Mar. 31, 2017		15,338	$ 3		13,653	(5)	1,735	(61)	15,325	13
Balance, shares at Mar. 31, 2017	[1]		309,069,291
Balance at Dec. 31, 2017		$ 15,096	$ 3		13,653	(8)	1,475	(46)	15,077	19
Balance, shares at Dec. 31, 2017		309,005,272	309,005,272	[1]
Adoption of accounting standards at Dec. 31, 2017		$ 136					(3)	(1)	(4)	140
Net Income		238					244		244	(6)
Other comprehensive income (loss), net of tax		(10)						(10)	(10)
Comprehensive Income		228
Dividends declared		$ (134)					(134)		(134)
Release of common stock held in trust		0
Issuance of common stock, issuance costs		$ (2)			1		(3)		(2)
Issuance of common stock, shares		81,208	81,208	[1]
Distributions to noncontrolling interests		$ (11)								(11)
Contributions from noncontrolling interests		6								6
Balance at Mar. 31, 2018		$ 15,319	$ 3		$ 13,654	$ (8)	$ 1,579	$ (57)	$ 15,171	$ 148
Balance, shares at Mar. 31, 2018		309,086,480	309,086,480	[1]
[1]	Par value of share amounts is $0.01

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Statement Of Stockholders Equity [Abstract]
Common Stock, Par or Value Per Share	$ 0.01
Other Comprehensive Income (Loss) Taxes	$ (7.5)	$ 14.9

Background and Nature of Operat

Background and Nature of Operations	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Background and Nature of Operations	Note 1. 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 distribution business through its principal subsidiary Avangrid Networks, Inc. (Networks) and in the renewable energy generation and gas storage businesses through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables) and Enstor Gas, LLC (Gas). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. In December 2017, management committed to a plan to sell the gas storage and trading businesses because they represent non-core businesses that were not aligned with our strategic objectives. As a result, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. On March 1, 2018, the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI). On May 1, 2018 the Company closed a transaction to sell Enstor Gas, LLC, which operated AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC. Additional details on held for sale classification are provided in Note 20 to our condensed consolidated financial statements.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2018
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	Note 2. Basis of Presentation The accompanying notes should be read in conjunction with the notes to the consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2017 and 2016 and for the three years ended December 31, 2017 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017. 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. We believe the disclosures made are adequate to make the information presented not misleading. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated balance sheets, condensed consolidated statements of income, comprehensive income, cash flows and changes in equity 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, 2018, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2018.

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Significant Accounting Policies and New Accounting Pronouncements	Note 3. Significant Accounting Policies and New Accounting Pronouncements As of March 31, 2018, the new accounting pronouncements that we have adopted as of January 1, 2018, and reflected in our consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2017 and 2016, and for the three years ended December 31, 2017. Adoption of New Accounting Pronouncements (a) Revenue from contracts with customers In May 2014 the Financial Accounting Standards Board (FASB) Upon adoption, we classify production tax credits as income tax expense (benefit) rather than as operating revenue. (b) Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets The FASB The cumulative Balance Sheet Balance at December 31, 2017 Adjustments Due to ASC 606 Adjustments Due to ASC 610-20 Balance at January 1, 2018 (Millions) Liabilities Tax equity financing arrangements - VIEs $ 98 $ — $ (98 ) $ — Deferred income taxes $ 1,452 $ — $ (40 ) $ 1,412 Equity Retained earnings $ 1,475 $ — $ (2 ) $ 1,473 Non-controlling interests $ 19 $ — $ 140 $ 159 We also adopted the following standards as of their effective date of January 1, 2018, none of which had a material effect on our consolidated results of operations, financial position, cash flows, and disclosures. (c) Classifying and measuring financial instruments In January 2016 the FASB issued final guidance on the classification and measurement of financial instruments. As a result of our adoption we reclassified immaterial amounts from AOCI to retained earnings. (d) Certain classifications in the statement of cash flows In August 2016 the FASB issued amendments to address existing diversity in practice concerning the classification of certain cash receipts and payments on the statement of cash flows, which must be applied on a full retrospective basis. Upon adoption, we had no changes to our cash flow classifications and disclosures in our consolidated financial statements. (e) Improving the presentation of net periodic benefit costs In March 2017 the FASB issued amendments to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost in the financial statements. We retrospectively adopted the amendments that require us to present the service cost component separately from the other (non-service) components of net benefit cost, to report the service cost component in the income statement line item where we report the corresponding compensation cost, and to present all non-service components outside of operating cost. As a result, we have reclassified the non-service components – interest cost, expected return on plan assets, amortization of prior service cost (benefit), amortization of net loss, and settlement charge – from Operations and maintenance to Other income/(expense) within the statement of income. Prospectively, upon adoption, we will capitalize only the service cost component when applicable (for example, as a cost of a self-constructed asset). We elected to apply the practical expedient that allows us to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in our notes to financial statements for Post-retirement and Similar Obligations as the basis for those periods. In addition to those amounts, we included amortization of net benefit costs recorded as regulatory deferrals as a result of purchase accounting in a prior year. In connection with applying the practical expedient, in periods after adoption we will continue to include in operating income all legacy net benefit costs previously capitalized as a cost of self-constructed assets and other deferred regulatory costs. Our adoption of the amendments did not affect net income attributable to AVANGRID. The effect of the change in retrospective presentation related to the net periodic cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated statement of income was as follows: Three Months Ended March 31, 2017 Statement of Income As Revised As Previously Reported Effect of Change Higher/(Lower) (Millions) Operations and maintenance $ 522 $ 551 $ (29 ) Other income / (expense) $ (16 ) $ 13 $ (29 ) The segment information related to our Networks reportable segment provided in Note 13 for the three months ended March 31, 2017 has also been revised to reflect the change as a result of the adoption of these amendments. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements issued since December 31, 2017, that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) Land easement practical expedient In January 2018 the FASB issued amendments to clarify the application of the new leases guidance to land easements (also commonly called rights of way) and provide relief concerning adoption efforts for existing land easements that are not accounted for as leases under current GAAP. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We are currently reviewing our contracts and are in the process of determining the proper application of the lease standard, including the land easement practical expedient, in order to determine the impact that the adoption will have on our consolidated financial statements. We expect our adoption of the new guidance will materially affect our financial position through the recording of operating leases on the balance sheet as right-of-use assets, along with the corresponding liabilities. (b) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018 the FASB issued amendments to address a narrow-scope financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) enacted on December 22, 2017, by the U.S. federal government. Under current guidance, the adjustment of deferred taxes for the effect of a change in tax laws or rates is required to be included in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the Tax Act. As a result, the amendments eliminate the stranded tax effects resulting from the Tax Act and will improve the usefulness of information reported to financial statement users. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. The amendments are effective for all entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted including, for public entities, adoption in any interim period for which financial statements have not been issued. An entity has the option to apply the amendments either in the period of adoption or retrospectively to each period (or periods) in which it recognizes the effect of the change in the U.S. federal corporate income tax rate in the Tax Act. An entity is required to disclose its accounting policy election, including its policy for reclassifying material stranded tax effects in AOCI to earnings (specific identification or portfolio method). We have not early adopted the amendments as of March 31, 2018. We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows, and disclosures.

Revenue

Revenue	3 Months Ended
	Mar. 31, 2018
Revenue From Contract With Customer [Abstract]
Revenue	Note 4. Revenue On January 1, 2018, we adopted ASC 606 and all related amendments using the modified retrospective method, which we applied only to contracts that were not completed as of January 1, 2018. For reporting periods beginning on January 1, 2018, we present revenue in accordance with ASC 606, and have not adjusted comparative prior period information, which we continue to report under the legacy accounting standards in effect for those prior periods. For the three months ended March 31, 2018, the effect of applying ASC 606 to recognize revenue as compared to applying the legacy accounting standards was not material. 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 material significant payment terms 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. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the NE-ISO, NYISO, or 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 transmission service. We record revenue for all of those sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. Networks does not have any material significant payment terms because it receives payment at or shortly after the point of sale. For its New York utilities, Networks assesses its deferred payment arrangements at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations, and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property, and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives, or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar, and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all 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 does not have any material significant payment terms because it receives payment at or shortly after the point of sale. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. Renewables classifies certain contracts for the sale of electricity as either leases or derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer. Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration. Other Other, which does not represent a segment, derives its revenues primarily from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards, gas trading contracts not classified as derivatives, and other miscellaneous revenues including intersegment eliminations. Contract Costs and Practical Expedient We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. Renewables has an origination sharing bonus plan that meets the requirements for capitalization. Costs incurred prior to 2018 were insignificant and not capitalized. Costs capitalized to date in 2018 are also insignificant, with amortization on a straight-line basis over the term of the related contract for which the terms may be from three years to 20 years. We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs. Revenues disaggregated by major source for our reportable segments are as follows: Three Months Ended March 31, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 926 $ — $ — $ 926 Regulated operations – natural gas 572 — — 572 Nonregulated operations – wind — 168 — 168 Nonregulated operations – solar — 2 — 2 Nonregulated operations – thermal — 13 — 13 Nonregulated operations – gas storage — — 4 4 Other (a) 25 (23 ) 15 17 Revenue from contracts with customers 1,523 160 19 1,702 Leasing revenue 9 81 — 90 Derivative revenue — 43 10 53 Alternative revenue programs 19 — — 19 Other revenue 1 — — 1 Total operating revenues $ 1,552 $ 284 $ 29 $ 1,865 (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, Gas and intersegment eliminations. As of March 31, 2018, accounts receivable balances related to contracts with customers were approximately $1,076 million, which are included in “ Accounts receivable and unbilled revenues, net” As of March 31, 2018, for contracts with durations greater than one year (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied), and (2) when we expect to recognize the revenue, were as follows: As of March 31, 2018 2019 2020 2021 2022 2023 Thereafter Total (Millions) Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts $ — $ 14 $ 8 $ 3 $ 3 $ 4 $ 32 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 25 15 7 4 1 1 53 Total operating revenues $ 25 $ 29 $ 15 $ 7 $ 4 $ 5 $ 85 We did not include disclosures for unsatisfied performance obligations for Gas in the table above due to the expected sale of the Gas business in the second quarter of 2018. We do not disclose information about remaining performance obligations for (i) contracts with an original expected duration of one year or less and (ii) contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Note 5. Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific 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 is 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 , 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. 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 these items 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 fifty 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 fifty 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 an 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, provides 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. On June 30, 2017, The Southern Connecticut Gas Company (SCG) filed an application with PURA for new tariffs to become effective January 1, 2018. SCG requested a three-year rate plan for calendar years 2018, 2019 and 2020 and a proposed ROE of 9.95%. SCG also requested to implement a RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for Connecticut Natural Gas Corporation (CNG). On October 16, 2017, SCG, Prosecutorial Staff from PURA, and the Connecticut Office of Consumer Counsel (OCC) filed an amended settlement agreement with PURA for approval, which included among other items, the implementation of an RDM, ESM and the DIMP as proposed by SCG, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and approximately 52% equity level. PURA approved the amended rate case settlement agreement on December 13, 2017, and Current and non-current regulatory assets as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 24 $ 24 Pension and other post-retirement benefits 11 7 Storm costs 46 46 Temporary supplemental assessment surcharge 1 — Reliability support services 27 27 Revenue decoupling mechanism 19 21 Transmission revenue reconciliation mechanism 3 8 Electric supply reconciliation 23 — Hedges losses 11 3 Contracts for differences 8 9 Hardship programs 13 14 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 2 31 Deferred transmission expense 38 37 Environmental remediation costs 13 13 Other 54 51 Total Current Regulatory Assets 309 307 Non-current Pension and other post-retirement benefits cost deferrals 111 110 Pension and other post-retirement benefits 1,116 1,162 Storm costs 284 254 Deferred meter replacement costs 29 29 Unamortized losses on reacquired debt 17 17 Environmental remediation costs 280 283 Unfunded future income taxes 376 376 Asset retirement obligation 19 18 Deferred property tax 10 14 Federal tax depreciation normalization adjustment 154 155 Merger capital expense target customer credit 2 2 Debt premium 128 131 Reliability support services 4 10 Plant decommissioning 7 9 Contracts for differences 95 84 Hardship programs 10 13 Deferred income taxes regulatory 20 — Other 72 71 Total Non-current Regulatory Assets $ 2,734 $ 2,738 “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 Central Maine Power (CMP), NYSEG and RG&E are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. Storm costs in the amount of $123 million at NYSEG are being recovered over ten-year period and the remaining portion is being amortized over five years following the approval of the Joint Proposal by the NYPSC. UI is allowed to defer costs associated with any storm totaling $1 million or greater for future recovery. UI’s storm regulatory asset balance was $0 as of March 31, 2018. “Deferred meter replacement costs” represent the deferral of the book value of retired meters that were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “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. Following the approval of the Joint Proposal by the NYPSC, these amounts will be collected over a fifty-year period, and the NYPSC Staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Asset retirement obligations” (ARO) represent 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 property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amount for NYSEG and RG&E is being amortized over a five year period following the approval of the Joint Proposal by the NYPSC. “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 rates years covering 2011 forward. The recovery period in New York is from 27 to 39 years and for CMP this will be determined in future Maine Public Utility Commission (MPUC) rate proceedings. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “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. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL Holdings Corporation (UIL) at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided for in rates. “Other” includes post term amortization deferrals and various items subject to reconciliation including rate change levelization, loss on re-acquired debt and power tax deferral. Current and non-current regulatory liabilities as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Current Non by-passable charges $ 8 $ 5 Energy efficiency portfolio standard 46 37 Gas supply charge and deferred natural gas cost 13 4 Transmission revenue reconciliation mechanism 15 14 Pension and other post-retirement benefits 1 1 Pension and other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 23 21 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE Refund — 4 Merger related rate credits — 1 Revenue decoupling mechanism 5 4 Stranded costs 13 17 Other 59 51 Total Current Regulatory Liabilities 202 178 Non-current Accrued removal obligations 1,143 1,132 Tax Act - remeasurement 1,562 1,515 Asset sale gain account 10 10 Carrying costs on deferred income tax bonus depreciation 66 72 Economic development 32 32 Merger capital expense target customer credit account 6 6 Pension and other post-retirement benefits cost deferrals 70 74 Positive benefit adjustment 38 39 New York state tax rate change 6 6 Theoretical reserve flow thru impact 18 19 Deferred property tax 21 19 Net plant reconciliation 10 10 Variable rate debt 35 33 Carrying costs on deferred income tax - Mixed Services 263(a) 19 20 Rate refund – FERC ROE proceeding 27 27 Transmission congestion contracts 20 19 Merger-related rate credits 20 20 Accumulated deferred investment tax credits 13 13 Asset retirement obligation 13 13 Earning sharing provisions 15 22 Middletown/Norwalk local transmission network service collections 18 19 Excess generation service charge — 2 Low income programs 39 42 Non-firm margin sharing credits 12 8 Deferred income taxes regulatory — 13 Other 74 67 Total Non-current Regulatory Liabilities $ 3,287 $ 3,252 “Non by-passable charges” represent the non by-passable charge paid by all customers. An asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered. This liability will be refunded to customers within the next year. “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. “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 gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station located in Oswego, New York. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “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. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “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 ratepayers. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Merger capital expense target customer credit” account was created as a result of NYSEG and RG&E not meeting certain capital expenditure requirements established in the order approving the purchase of AVANGRID (formerly Energy East Corporation) by Iberdrola. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “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 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. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. The amortization period is five years following the approval of the Joint Proposal by the NYPSC and included in the Ginna RSSA settlement. “New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from 7.1% to 6.5%. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “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. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Tax Act - remeasurement” 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 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 to review and address the implications associated with the Tax Act on the utilities providing service in those states. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the three months ended March 31, 2018 and 2017, respectively, $1 and $2 million of rate credits was applied against customer bills. “Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “Low Income Programs” represent various hardship and payment plan programs approved for recovery. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Note 6. Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and available for sale non-current investments associated with Networks’ activities utilizing market approach valuation techniques: • We measure the fair value of our noncurrent investments using quoted market prices in active markets for identical assets and include the measurements in Level 1. The available for sale investments, which are Rabbi Trusts for deferred compensation plans, primarily consist of money market funds and are included in Level 1 fair value measurement. • 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 New York Independent System Operator (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 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. • CfDs entered into by UI 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 and Gas 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 product with no adjustment are included in the Level 1 fair value. 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 Level 2 fair value. 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 Level 3 fair value. 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. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable and interest accrued approximate their estimated fair values and are considered as Level 1. Restricted cash was $5 million as of both March 31, 2018 and December 31, 2017, which is included in “Other Assets” on the balance sheet. The financial instruments measured at fair value as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 4 36 76 (40 ) 76 Derivative financial instruments - gas — 10 39 (52 ) -3 Contracts for differences — — 10 — 10 Total 4 46 125 (92 ) 83 Derivative liabilities Derivative financial instruments - power (16 ) (21 ) (16 ) 46 (7 ) Derivative financial instruments - gas — (15 ) (5 ) 13 (7 ) Contracts for differences — — (113 ) — (113 ) Derivative financial instruments - other — — — — — Total $ (16 ) $ (36 ) $ (134 ) $ 59 $ (127 ) As of December 31, 2017 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 14 30 74 (49 ) 69 Derivative financial instruments - gas 89 18 64 (146 ) 25 Contracts for differences — — 12 — 12 Total 103 48 150 (195 ) 106 Derivative liabilities Derivative financial instruments - power (14 ) (17 ) (15 ) 37 (9 ) Derivative financial instruments - gas (80 ) (20 ) (25 ) 110 (15 ) Contracts for differences — — (104 ) — (104 ) Total $ (94 ) $ (37 ) $ (144 ) $ 147 $ (128 ) Included in the derivative financial instruments – gas are derivative assets and liabilities of Gas segment classified as held for sale on the condensed consolidated balance sheet as of December 31, 2017. See Note 20 – Assets Held For Sale for further discussion. The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2018 and 2017, respectively, is as follows: Three Months Ended March 31, (Millions) 2018 2017 Fair Value Beginning of Period, $ 6 $ 31 Gains recognized in operating revenues 5 12 (Losses) recognized in operating revenues (4 ) (2 ) Total gains recognized in operating revenues 1 10 Gains recognized in OCI — 1 (Losses) recognized in OCI (2 ) (1 ) Total gains recognized in OCI (2 ) — Net change recognized in regulatory assets and liabilities (11 ) (5 ) Purchases (2 ) 3 Settlements (1 ) (6 ) Fair Value as of March 31, $ (9 ) $ 33 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 $ 1 $ 10 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 tables below illustrate 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, 2018 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions delivery Transactions valued forward market Observable extrapolated forward power not can NYMEX $ 3.02 $ 3.93 $ 2.35 with delivery exceeding two on a corroborated by Indiana hub $ 31.32 $ 65.55 $ 18.53 period > two years discounted market data for Mid C $ 23.68 $ 46.50 $ (0.50 ) years basis identical or Minn hub $ 25.90 $ 62.33 $ 9.56 similar 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 both gas inventory in firm storage and 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 gas storage inventory and 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 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 discussion of 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 extended 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, 2018 Risk of non-performance 0.66% - 0.69% Discount rate 2.27% - 2.74% Forward pricing ($ per MW) $4.30 - $9.55 Fair Value of Debt As of March 31, 2018 and December 31, 2017, debt consisted of first mortgage bonds, fixed and variable unsecured pollution control notes, other various non-current debt securities and obligations under capital leases. The estimated fair value of debt amounted to $5,625 million and $5,799 million as of March 31, 2018 and December 31, 2017, 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 risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy pertaining to the fair value of debt is considered as Level 2, except for unsecured pollution control notes-variable with a fair value of $61 million as of both March 31, 2018 and December 31, 2017, which are considered Level 3. The fair value of these unsecured pollution control notes-variable are determined using unobservable interest rates as the market for these notes is inactive.

Derivative Instruments and Hedg

Derivative Instruments and Hedging	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Note 7. Derivative Instruments and Hedging Our Networks, Renewables and Gas 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 the condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities NYSEG and RG&E each have an electric commodity charge that passes through rates costs for the market price of electricity. They 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. The amount recognized in regulatory assets for electricity derivatives was a loss of $11.5 million and $0.2 million as of March 31, 2018 and December 31, 2017, respectively. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a gain of $5.8 million and a loss of $10.9 million, for the three months ended March 31, 2018 and 2017, respectively. NYSEG and RG&E each have purchased gas adjustment clauses that allow them 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 amount recognized in regulatory assets for natural gas hedges was a loss of $0.2 million and $2.5 million as of March 31, 2018 and December 31, 2017, respectively. The amount reclassified from regulatory assets and liabilities into income, which is included in natural gas purchased, was a loss of $1.7 million and a gain of $0.6 million, for the three months ended March 31, 2018 and 2017, respectively. Pursuant to 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, 2018, UI has recorded a gross derivative asset of $10 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $103 million, a gross derivative liability of $113 million ($100 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, 2017, UI had recorded a gross derivative asset of $12 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $93 million, a gross derivative liability of $104 million ($90 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 or regulatory liabilities, for the three months ended March 31, 2018 and 2017, respectively, were as follows: Three Months Ended March 31, 2018 2017 (Millions) Derivative assets $ (2 ) $ 5 Derivative liabilities $ (9 ) $ 1 The net notional volumes of the outstanding derivative instruments associated with Networks activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts (MWh) 3.7 3.9 Natural gas purchase contracts (Dth) 6.7 6.1 Fleet fuel purchase contracts (Gallons) 2.0 2.1 The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Networks activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 9 $ 5 $ 3 $ 1 Derivative liabilities (3 ) (1 ) (28 ) (101 ) 6 4 (25 ) (100 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 6 4 (25 ) (100 ) Cash collateral receivable — — 11 1 Total derivatives as presented in the balance sheet $ 6 $ 4 $ (14 ) $ (99 ) As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 20 $ 5 $ 13 $ — Derivative liabilities (13 ) — (32 ) (88 ) 7 5 (19 ) (88 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 7 5 (19 ) (88 ) Cash collateral receivable — — 3 — Total derivatives as presented in the balance sheet $ 7 $ 5 $ (16 ) $ (88 ) The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses — Total $ — $ 2 2017 Interest rate contracts $ — Interest expense $ 2 Commodity contracts (1 ) Operating expenses — Total $ (1 ) $ 2 (a) The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $66.8 million and $68.8 million as of March 31, 2018 and December 31, 2017, respectively. We recorded $2.0 million and $2.0 million in net derivative losses related to discontinued cash flow hedges for the three months ended March 31, 2018 and 2017, respectively. We will amortize approximately $8.0 million of discontinued cash flow hedges in 2018. During the three months ended March 31, 2018 and 2017, there was no ineffective portion for cash flow hedges. The unrealized loss of $0.2 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable as of March 31, 2018. We expect that $0.2 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 twelve months. (b) Renewables and Gas activities The below presented information includes derivative financial instruments associated with Gas activities, which were classified as held for sale in the condensed consolidated balance sheet as of December 31, 2017 (see Note 20 - Assets Held for Sale). 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. Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also enter into basis swaps to hedge the value of our contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and delivery point of the contracted transport in future periods. Both Renewables and Gas have 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. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future power sales and gas purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. 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. Gas also periodically designates NYMEX fixed price derivative contracts as cash flow hedges related to its firm storage trading activities. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future gas sales and purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. Derivative contracts entered into to hedge the gas transport trading activities are not designated as cash flow hedges, with all changes in fair value of such derivative contracts recorded in current period earnings. The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (MWh/Dth in millions) Wholesale electricity purchase contracts 4 4 Wholesale electricity sales contracts 6 6 Natural gas and other fuel purchase contracts 19 285 Financial power contracts 12 12 Basis swaps – purchases 33 68 Basis swaps – sales 5 62 The fair values of derivative contracts associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts $ (1 ) $ (3 ) Wholesale electricity sales contracts 9 8 Natural gas and other fuel purchase contracts (1 ) 19 Financial power contracts 62 55 Basis swaps – purchases (10 ) (13 ) Basis swaps – sales — 4 Total $ 59 $ 70 The effect of trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Wholesale electricity purchase contracts $ 1 $ (3 ) Wholesale electricity sales contracts 1 7 Financial power contracts (1 ) (3 ) Financial and natural gas contracts 3 4 Total Gain $ 4 $ 5 The effect of non-trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Wholesale electricity purchase contracts $ 1 $ (6 ) Wholesale electricity sales contracts — 11 Financial power contracts 3 16 Financial and natural gas contracts 5 (4 ) Total Gain $ 9 $ 17 Such gains and losses are included in “Operating revenues” and in “Purchased power, natural gas and fuel used” operating expenses in the condensed consolidated statements of income, depending upon the nature of the transaction. The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 43 $ 100 $ 3 $ 5 Derivative liabilities (21 ) (7 ) (13 ) (12 ) 22 93 (10 ) (7 ) Designated as hedging instruments Derivative assets 4 3 — 3 Derivative liabilities — — — (5 ) 4 3 — (2 ) Total derivatives before offset of cash collateral 26 96 (10 ) (9 ) Cash collateral receivable (payable) (12 ) (37 ) — 5 Total derivatives as presented in the balance sheet $ 14 $ 59 $ (10 ) $ (4 ) As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 111 $ 99 $ 31 $ 4 Derivative liabilities (82 ) (5 ) (51 ) (10 ) 29 94 (20 ) (6 ) Designated as hedging instruments Derivative assets 24 4 — 2 Derivative liabilities — (1 ) (3 ) (3 ) 24 3 (3 ) (1 ) Total derivatives before offset of cash collateral 53 97 (23 ) (7 ) Cash collateral receivable (payable) (17 ) (39 ) 3 3 Total derivatives as presented in the balance sheet, including assets and liabilities held for sale $ 36 $ 58 $ (20 ) $ (4 ) The effect of derivatives in cash flow hedging relationships on OCI and income for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, (Loss) Gain Recognized in OCI on Derivatives Location of Loss (Gain) Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Commodity contracts $ (1 ) Revenues $ (19 ) Total $ (1 ) $ (19 ) 2017 Commodity contracts $ 4 Revenues $ 33 Total $ 4 $ 33 (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 $3.7 million of gain included in accumulated OCI at March 31, 2018, is expected to be reclassified into earnings within the next twelve months. During the three months ended March 31, 2018 and 2017, we recorded a net gain of $0.1 million and a net loss of $0.3 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges. The net loss in accumulated OCI related to a discontinued cash flow hedge is $0.5 million as of March 31, 2018, out of which $0.2 million will be amortized in 2018. (c) 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 dependent on the counterparty’s or the counterparty’s guarantor’s applicable credit rating, normally 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, 2018, UI would have had to post an aggregate of approximately $15 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 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 $2 million and $30 million as of March 31, 2018 and December 31, 2017, respectively. Derivative instruments settlements and collateral payments are included in “Other assets/liabilities” of operating activities in the 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, 2018 is $11.7 million, for which we have posted collateral.

Contingencies

Contingencies	3 Months Ended
	Mar. 31, 2018
Commitments And Contingencies Disclosure [Abstract]
Contingencies	Note 8. 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, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, 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 complaint (Complaint I) with the FERC pursuant to sections 206 and 306 of the Federal Power Act. The filing parties sought an order from the FERC reducing the 11.14% base return on equity used in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) to 9.2%. CMP, MEPCO and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint. On June 19, 2014, the FERC issued its decision in Complaint I, establishing an ROE methodology and setting an issue for a paper hearing. On October 16, 2014, FERC issued its final 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, and ordered the NETOs to file a refund report. On November 17, 2014, the NETOs filed the requested refund report. On March 3, 2015, the FERC issued an order on requests for rehearing of its October 16, 2014 decision. The March order upheld the FERC’s June 19, 2014 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. In June 2015 the NETOs and complainants both filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. On April 14, 2017, the Court of Appeals (the Court) vacated FERC’s decision on Complaint I and remanded it to FERC. The Court held that FERC, as directed by statute, did not determine first that the existing ROE was unjust and unreasonable before determining a new ROE. The Court ruled that FERC should have first determined that the then existing 11.14% base ROE was unjust and unreasonable before selecting the 10.57% as the new base ROE. The Court also found that FERC did not provide reasoned judgment as to why ROE of 10.57% at the midpoint of the upper end of the zone of reasonableness, is a just and reasonable ROE. Instead, FERC had only explained in its order that the midpoint of 9.39% was not just and reasonable and a higher base ROE was warranted. On June 5, 2017, the NETOs made a filing with FERC seeking to reinstate transmission rates to the status quo ante (effect of the Court vacating order is to return the parties to the rates in effect prior to FERC Final decision) as of June 8, 2017, the date the Court decision became effective. In that filing, the NETOs stated that they will not begin billing at the higher rates until 60 days after FERC has a quorum of commissioners. On October 6, 2017, FERC issued an order rejecting the NETOs request to collect transmission revenue requirements at the higher ROE of 11.14%, pending FERC order on remand. In reaching this decision, FERC stated that it has broad remedial authority to make whatever ROE it eventually determines to be just and reasonable effective for the Complaint I refund period and prospectively from October 2014, the effective date of the Complaint I Order. Therefore FERC reasoned that the NETOs will not be harmed financially by not immediately returning to their pre-Complaint I ROE. We anticipate FERC to address the Court decision during 2018. We cannot predict the outcome of action by FERC . On December 26, 2012, a second ROE complaint (Complaint II) for a subsequent rate period was filed requesting the then effective ROE of 11.14% be reduced to 8.7%. On June 19, 2014, FERC accepted Complaint II, established a 15-month refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in Complaint I. On July 31, 2014, a third ROE complaint (Complaint III) was filed for a subsequent rate period requesting the then effective ROE of 11.14% be reduced to 8.84%. On November 24, 2014, FERC accepted the Complaint III, established a 15-month refund effective date of July 31, 2014, and set this matter consolidated with Complaint II for hearing in June 2015. Hearings relating to the refund periods and going forward period were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the NETOs filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The FERC Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that: (1) for the 15-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 15-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 is the Administrative Law Judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in 2018. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final 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 $22.7 million and $4.4 million, respectively, as of March 31, 2018, which has not changed since December 31, 2017, except for the accrual of carrying costs. If adopted as final, the impact of the initial decision would be an additional aggregate reserve for Complaints II and III of $17.1 million, which is based upon currently available information for these proceedings. We cannot predict the outcome of the Complaint II and III proceedings. On April 29, 2016, a fourth ROE complaint (Complaint IV) was filed for a rate period subsequent to prior complaints requesting the then existing base ROE of 10.57% be reduced to 8.61% and the ROE Cap be set at 11.24%. The NETOs filed a response to the Complaint IV on June 3, 2016. On September 20, 2016, FERC accepted the Complaint IV, established a 15-month refund effective date of April 29, 2016, and set the matter for hearing and settlement judge procedures. In April 2017, the NETOs filed for a stay in the hearings pending FERC on the Court order described above. That request was denied by the Administrative Law Judge. On November 21, 2017, the parties submitted updates to their ROE analyses and recommendations just prior to hearings with the NETOs continuing to advocate that the existing base ROE of 10.57% should remain in effect. Hearings were held in December 2017 and on March 27, 2018, the Administrative Law Judge issued a decision rejecting Complaint IV, finding the currently-filed base ROE of 10.57%, which with incentive adders may reach a maximum ROE of 11.74%, is not unjust and unreasonable, and hence is not unlawful. We cannot predict the outcome of the Complaint IV proceeding. On October 5, 2017, the NETOs filed a Motion for Dismissal of Pancaked Return on Equity Complaints in light of the decision by the Court in April 2017 that became effective on June 8, 2017. The NETOs assert that all four complaints should be dismissed because the complainants have not shown that the existing ROE of 11.14% is unjust and unreasonable as the Court decision requires. In addition, the NETOs assert that Complaints II, III and IV should also be dismissed because the Court decision implicitly found that FERC’s acceptance of Pancaked FPA Section 206 complaints was statutorily improper as Congress intended that the 15-month refund period under Section 206 applies whenever FERC does not complete its review of a complaint within the 15-month period. In the event FERC chooses not to dismiss the complaints, the NETOs request that FERC consolidate the complaints for decision as the evidentiary records are either closed or advanced enough for FERC to address the requirements of the Court decision and expeditiously issue a final order. FERC has not yet ruled on this Motion. We cannot predict the outcome of action by FERC. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm On March 11, 2017 the New York State Department of Public Service (the “Department”) commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which affected more than 219,000 customers. The Department investigation included a comprehensive review of NYSEG’s and RG&E’s preparation for and response to the windstorm, including all aspects of the companies’ filed and approved emergency plan. The Department held public hearings on April 12 and 13, 2017. On November 16, 2017, the NYPSC announced that the Department Staff had completed their investigation into the March 2017 Windstorm and the NYPSC issued an Order Instituting Proceeding and to Show Cause. The Staff’s investigation found that RG&E and NYSEG violated certain parts of their emergency response plans, which makes them subject to possible financial penalties. NYSEG and RG&E responded to the order in a timely manner and have entered into settlement discussions with the Department Staff. We cannot predict the outcome of this regulatory action. 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. FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed FERC's dismissal of Renewables. 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 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 an administrative law judge of FERC 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 contract that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million. Class Action Regarding LDC Gas Transportation Service on Algonquin Gas Transmission On November 16, 2017, a class action lawsuit was filed in the U.S. District Court in Massachusetts on behalf of customers in New England against the Company and Eversource alleging that certain of their respective subsidiaries that take gas transportation service over the Algonquin Gas Transmission, AGT, which for AVANGRID would be its indirect subsidiaries SCG and CNG, engaged in pipeline capacity scheduling practices on AGT that resulted in artificially increased electricity prices in New England. These allegations were based on the conclusions of a White Paper issued by the Environmental Defense Fund (EDF), an environmental advocacy organization, on October 10, 2017, purporting to analyze the relationship between the New England electricity market and the New England local gas distribution companies. The plaintiffs assert claims under federal antitrust law, state antitrust, unfair competition and consumer protection laws, and under the common law of unjust enrichment. They seek damages, disgorgement, restitution, injunctive relief, and attorney fees and costs. The Company filed a Motion to Dismiss all of the claims on January 29, 2018. On February 27, 2018, the FERC released the results of a FERC staff inquiry into the pipeline capacity scheduling practices on the AGT. The inquiry arose out of the allegations made by the EDF in its White Paper. FERC announced that, based on an extensive review of public and non-public data, it had determined that the EDF study was flawed and led to incorrect conclusions. FERC also stated that the staff inquiry revealed no evidence of anticompetitive withholding of natural gas pipeline capacity on the AGT and that it would take no further action on the matter. On March 28, 2018, the plaintiffs filed a consolidated amended complaint, repeating the prior claims, except omitting the common law claim of unjust enrichment. On April 27, 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 conclusion. Nevertheless, we cannot predict the outcome of this class action lawsuit. Guarantee Commitments to Third Parties As of March 31, 2018, we had approximately $2.2 billion 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, 2018, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liabilities

Environmental Liabilities	3 Months Ended
	Mar. 31, 2018
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Note 9. Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-five waste sites, which do not include sites where gas was manufactured in the past. Fifteen 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, nine of the twenty-five sites are also included on the National Priorities list. Any liability may be joint and severable for certain sites. We have recorded an estimated liability of $5 million related to ten of the twenty-five sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another ten sites where we believe it is probable that we will incur remediation costs 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. We recorded a corresponding regulatory asset because we expect to recover these costs in rates. 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 $12 million to $21 million as of March 31, 2018. 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; twelve sites are included in the New York Voluntary Cleanup Program; three sites are part of Maine’s Voluntary Response Action Program and with two of such sites being 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-nine of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $213 million to $442 million as of March 31, 2018. 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 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 in respect of these sites as of March 31, 2018 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 March 31, 2018 and December 31, 2017, the liability associated with other MGP sites in Connecticut, 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, was $99 million and $100 million, respectively. The total liability to investigate and perform remediation at the known inactive MGP sites and other sites was $387 million and $389 million as of March 31, 2018 and December 31, 2017, 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 2054. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former manufactured gas sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor. Based on past and future clean-up costs at the sixteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the decision were upheld on appeal. 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 $22 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 ratepayers. Century Indemnity and OneBeacon On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at 22 former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share could equal or exceed approximately $89 million, excluding pre-judgment interest, although this amount may change substantially depending upon the determination of various factual matters and legal issues during the case. Century Indemnity and OneBeacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. On March 31, 2017, the District Court granted motions filed by Century Indemnity and One Beacon dismissing all of NYSEG’s claims against both defendants on the grounds of late notice. NYSEG filed a motion with the District Court on April 14, 2017 seeking reconsideration of the Court’s decision, which was denied by an order dated March 27, 2018. NYSEG filed English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. This proceeding had been 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 in Connecticut state court seeking among other things: (i) remediation of the English Station site; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages. This lawsuit had been stayed in May 2014 pending mediation. Due to lack of activity in the case, the court terminated the stay and scheduled a status conference for July 6, 2017. On July 5, 2017, Asnat filed a pretrial memorandum claiming damages of $10 million for “environmental remediation activities” and lost use of the property. In December 2017 Plaintiffs filed a Request for Leave to Amend Complaint and Motion to Cite-In Additional Parties, including former UIL officers and employees and other UI officers, which motion was approved in February 2018. 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. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April 2015. 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 the 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 December 31, 2017, we reserved $25 million for this matter. As of March 31, 2018, the reserve amount remained unchanged. We cannot predict the outcome of this matter.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	3 Months Ended
	Mar. 31, 2018
Compensation And Retirement Disclosure [Abstract]
Post-retirement and Similar Obligations	Note 10. Post-retirement and Similar Obligations We made $2 million of pension contributions for the three months ended March 31, 2018. We expect to make additional contributions of $46 million for the remainder of 2018. The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Service cost $ 11 $ 11 Interest cost 32 35 Expected return on plan assets (50 ) (50 ) Amortization of: Prior service costs — — Actuarial loss 38 32 Net Periodic Benefit Cost $ 31 $ 28 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Service cost $ 1 $ 1 Interest cost 4 5 Expected return on plan assets (2 ) (2 ) Amortization of: Prior service costs (2 ) (2 ) Actuarial loss 1 1 Net Periodic Benefit Cost $ 2 $ 3 Beginning in 2018, in the condensed consolidated statement of income, we include the service cost component in other operating expenses net of capitalized portion, and include the components of net periodic benefit cost other than the service cost component in the line item “Other income / (expense).”

Equity

Equity	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Equity	Note 11. Equity As of March 31, 2018, our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,086,480 shares outstanding, 81.5% of which is 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 $13,654 million. As of December 31, 2017, our share capital consisted of 500,000,000 shares of common stock authorized, 309,670,932 shares issued and 309,005,272 shares outstanding, 81.5% of which was 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 $13,653 million. We had 485,810 shares of common stock held in trust and no convertible preferred shares outstanding as of both March 31, 2018 and December 31, 2017, respectively. During the three months ended March 31, 2018, we issued 81,208 shares of common stock each having a par value of $0.01 and released no shares of common stock held in trust. During the three months ended March 31, 2017, we issued 70,493 shares of common stock and released 5,649 shares of common stock held in trust each having a par value of $0.01. On April 28, 2016, we entered into 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. Out of a total of 179,850 treasury shares of common stock of AVANGRID as of March 31, 2018, 115,831 shares were repurchased during 2016 and 64,019 shares were repurchased in May 2017, all in the open market. The total cost of repurchases, including commissions, was $8 million as of March 31, 2018. Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Gain (Loss) for the three months ended March 31, 2018 and 2017, respectively, consisted of: As of December 31, Adoption of new accounting Three Months Ended March 31, As of March 31, As of December 31, Three Months Ended March 31, As of March 31, 2017 standard 2018 2018 2016 2017 2017 (Millions) Loss on revaluation of defined benefit plans $ (14 ) $ — $ — $ (14 ) $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans (6 ) (1 ) — (7 ) (7 ) — (7 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense of $1.3 for 2017 30 — — 30 5 2 7 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense of $(7.5) for 2018 and $13.6 for 2017(a) (56 ) — (10 ) (66 ) (70 ) 23 (47 ) Gain (loss) on derivatives qualifying as cash flow hedges (26 ) — (10 ) (36 ) (65 ) 25 (40 ) Accumulated Other Comprehensive (Loss) Gain $ (46 ) $ (1 ) $ (10 ) $ (57 ) $ (86 ) $ 25 $ (61 ) (a) Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Earnings Per Share

Earnings Per Share	3 Months Ended
	Mar. 31, 2018
Earnings Per Share [Abstract]
Net Income Per Share	Note 12. Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three months ended March 31, 2018 and 2017, 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, 2018 and 2017. The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 244 $ 239 Denominator: Weighted average number of shares outstanding - basic 309,513,640 309,508,889 Weighted average number of shares outstanding - diluted 309,793,064 309,837,442 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.79 $ 0.77 Earnings Per Common Share, Diluted $ 0.79 $ 0.77

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Segment Information	Note 13. Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: including all the energy transmission and distribution activities, and 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. Based on the quantitative assessment and due to the disposition of gas trading and storage businesses (see Note 20 – Assets Held For Sale for further discussion) Gas segment no longer meets the reportable segment criteria effective in the first quarter of 2018. As a result, the prior period segment information has been restated to conform to the 2018 presentation. Products and services are sold between reportable segments and affiliate companies at cost. The chief operating decision maker evaluates segment performance based on segment adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) defined as net income adding back net income attributable to other non-controlling interests, Segment information as of and for the three months ended March 31, 2018, consisted of: Three Months Ended March 31, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,549 $ 283 $ 33 $ 1,865 Revenue - intersegment 3 1 (4 ) — Loss from assets held for sale — — 5 5 Depreciation and amortization 118 85 — 203 Operating income (loss) 344 44 15 403 Adjusted EBITDA 462 129 20 611 Earnings (losses) from equity method investments 2 — — 2 Interest expense, net of capitalization 60 8 6 74 Income tax expense (benefit) 64 (8 ) 16 72 Capital expenditures 282 116 1 399 As of March 31, 2018 Property, plant and equipment 13,996 8,754 7 22,757 Equity method investments 144 204 — 348 Total assets $ 21,481 $ 11,427 $ (1,425 ) $ 31,483 (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the three months ended March 31, 2018, are: $955 million from regulated electric operations, $600 million from regulated gas operations and $(6) million amounts from other operations of Networks; $283 million from renewable energy generation of Renewables. Segment information for the three months ended March 31, 2017, consisted of: Three Months Ended March 31, 2017 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,460 $ 285 $ 13 $ 1,758 Revenue - intersegment (1 ) 2 (1 ) — Depreciation and amortization 113 78 6 197 Operating income (loss) 365 56 6 427 Adjusted EBITDA 478 133 13 624 Earnings (losses) from equity method investments 4 (2 ) — 2 Interest expense, net of capitalization 63 7 1 71 Income tax expense (benefit) 116 (21 ) 8 103 Capital expenditures 267 257 1 525 As of December 31, 2017 Property, plant and equipment 13,876 8,786 7 22,669 Equity method investments 147 205 — 352 Total assets $ 21,411 $ 11,308 $ (1,048 ) $ 31,671 (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the three months ended March 31, 2017, are: $921 million from regulated electric operations, $537 million from regulated gas operations and $2 million amounts from other operations of Networks; $285 million from renewable energy generation of Renewables. Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three months ended March 31, 2018 and 2017, respectively, is as follows: Three Months Ended March 31, 2018 2017 (Millions) Consolidated Adjusted EBITDA $ 611 $ 624 Less: Loss from assets held for sale 5 — Depreciation and amortization 203 197 Interest expense, net of capitalization 74 71 Income tax expense 72 103 Add: Other expense (21 ) (16 ) Earnings from equity method investments 2 2 Consolidated Net Income $ 238 $ 239

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Note 14. Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (4 ) $ — $ (10 ) Iberdrola Renovables Energía, S.L. — (3 ) — (2 ) Iberdrola, S.A. — (14 ) — (9 ) Iberdrola Energia Monterrey, S.A. de C.V. 3 — 15 — Other 1 (1 ) 1 — In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola has an 8.1% ownership. The amounts capitalized for these transactions were $0 and $266 million for the periods ended March 31, 2018 and December 31, 2017, respectively. Related party balances as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 December 31, 2017 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ — $ (31 ) $ — $ (31 ) Siemens-Gamesa 1 (47 ) 2 (51 ) Iberdrola, S.A. — (14 ) 1 (32 ) Iberdrola Renovables Energía, S.L. — (3 ) — — Iberdrola Energia Monterrey, S.A. de C.V. — — 1 — Other 7 (1 ) 6 (4 ) Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID any costs remaining after direct charge are allocated using agreed upon cost allocation methods designed to allocate those costs. We believe that the allocation method used is reasonable. Transactions with Iberdrola Canada Energy Services (ICES) predominantly relate to the purchase of gas for ARHI’s gas-fired cogeneration facility in Klamath, Oregon. Included in the amounts owed to ICES is the balance of notes payable of $31 million and $29 million as of March 31, 2018 and December 31, 2017, respectively. Transactions with Iberdrola Energia Monterrey predominantly relate to the sale of gas by Enstor Gas for the power generation plant in Monterrey, Mexico. 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 the regulated 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. As of both March 31, 2018 and December 31, 2017, the amount receivable from New York TransCo was $6 million. AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both March 31, 2018 and December 31, 2017, was zero.

Supplemental Balance Sheet Info

Supplemental Balance Sheet Information	3 Months Ended
	Mar. 31, 2018
Balance Sheet Related Disclosures [Abstract]
Supplemental Balance Sheet Information	Note 15. Supplemental Balance Sheet Information Accounts receivable Accounts receivable include amounts due under deferred payment arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. The utility company 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 current. We establish provisions for uncollectible accounts for DPAs by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collection efforts have been exhausted. DPA receivable balances were $59 million and $55 million at March 31, 2018 and December 31, 2017, respectively. The allowance for doubtful accounts for DPAs at March 31, 2018 and December 31, 2017, was $31 million and $30 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for the three months ended March 31, 2018 and 2017 was $1 million for both periods. Prepayments and other current assets Included in “Prepayments and other current assets” are $151 million and $194 million of prepaid other taxes as of March 31, 2018 and December 31, 2017, respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of March 31, 2018 and December 31, 2017, respectively, were as follows March 31, December 31, As of 2018 2017 (Millions) Property, plant and equipment Accumulated depreciation $ 7,767 $ 7,497 Intangible assets Accumulated amortization $ 280 $ 276

Income Tax Expense

Income Tax Expense	3 Months Ended
	Mar. 31, 2018
Income Tax Disclosure [Abstract]
Income Tax Expense	Note 16. Income Tax Expense The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2018, was 23.2%, which is higher than the 21% statutory federal income tax rate, applicable in 2018, predominantly due to discrete tax adjustments recorded during the period offset by the recognition of production tax credits associated with wind production. The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2017, was 30.1%, which was lower than the statutory federal income tax rate, applicable in 2017, predominantly due $14 million

Stock-Based Compensation Expens

Stock-Based Compensation Expense	3 Months Ended
	Mar. 31, 2018
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-Based Compensation Expense	Note 17. Stock-Based Compensation Expense Pursuant to the 2016 Avangrid, Inc. Omnibus Incentive Plan 21,532 additional performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in March 2018. The PSUs will vest upon achievement of certain performance- and market-based metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020, 2021 and 2022. The fair value on the grant date was determined based on The total stock-based compensation (credit) expense, which is included in operations and maintenance of the condensed consolidated statements of income, for the three months ended March 31, 2018 and 2017 was $(0.1) million and $1.3 million, respectively. Before 2016, AVANGRID’s historical stock-based compensation expense and liabilities were based on shares of Iberdrola and not on shares of AVANGRID. These Iberdrola shares-based awards were early terminated at the end of 2015, and the remaining liability was settled in March 2018. The total liability relating to those awards, which was included in other current liabilities, was $5.5 million as of December 31, 2017.

Variable Interest Entities

Variable Interest Entities	3 Months Ended
	Mar. 31, 2018
Variable Interest Entities [Abstract]
Variable Interest Entities	Note 18. Variable Interest Entities We participate in certain partnership arrangement 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 the investor 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 in the condensed consolidated balance sheets valued based on a HLBV model. Earnings from the TEFs are recognized in earnings attributable to noncontrolling interests in the condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. The assets and liabilities of the VIEs totaled approximately $1,432 million and $91 million, respectively, at March 31, 2018. As of December 31, 2017, the assets and liabilities of VIEs totaled approximately $1,441 million and $185 million, respectively. At March 31, 2018 and December 31, 2017, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment, equity method investments and TEF liabilities. At March 31, 2018 and December 31, 2017, equity method investments of VIEs were approximately $106 million and $107 million, respectively. At March 31, 2018 we consider Aeolus Wind Power II LLC and Aeolus Wind Power IV LLC, (collectively, Aeolus) to be TEFs and El Cabo Wind, LLC to be a VIE. We retain a class of membership interest and day-to-day operational and management control of Aeolus, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any Aeolus assets and have no recourse against us for their upfront cash payments Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits generated by Aeolus, we have entered into the Aeolus structured institutional partnership investment transactions related to certain wind farms. Under the Aeolus 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 Aeolus 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 issuance of fixed and contingent notes. The third party investors receive a disproportionate amount of the profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation 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 Company taking a disproportionate share of such amounts 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 Aeolus 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 Expenses

Restructuring Expenses	3 Months Ended
	Mar. 31, 2018
Restructuring And Related Activities [Abstract]
Restructuring Expenses	Note 19. 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 other 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. Those decisions and transactions resulted in restructuring charges recorded in the three months ended March 31, 2018 for severance expenses of $1.2 million, which are included in “Operations and maintenance” in the 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 2018. Accordingly, the Company expects additional costs to be incurred in 2018 related to the remaining employee service periods under the severance plans. For the three months ended March 31, 2018, the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of: Three Months Ended March 31, 2018 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 1 Payments — Ending Balance $ 6

Assets Held for Sale

Assets Held for Sale	3 Months Ended
	Mar. 31, 2018
Assets Held For Sale Not Part Of Disposal Group [Abstract]
Assets Held for Sale	Note 20. Assets Held For Sale In December 2017, our management committed to a plan to sell the gas trading and storage businesses because they represent non-core businesses that were not aligned with our strategic objectives. As a result, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. On March 1, 2018, the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI) for $66 million, subject to working capital, cash, and other adjustments. The transaction price did not differ materially from the estimated fair value of our gas trading business at December 31, 2017, but is subject to adjustment based on closing and other contract provisions, including certain transition services. On May 1, 2018, the Company closed a transaction to sell Enstor Gas, LLC, which operated AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC for $66 million, subject to working capital, cash, and other adjustments. The transaction price was lower than the estimated fair value of our gas storage business at March 31, 2018 by approximately $9 millio March 31, December 31, As of 2018 2017 (Millions) Accounts receivable, net $ 1 $ 137 Derivative assets — 25 Fuel and gas in storage 1 77 Prepayments and other current assets 6 19 Property, plant and equipment 71 71 Intangible assets — 28 Assets held for sale $ 79 $ 357 Accounts payable and accrued liabilities 2 107 Derivative liabilities — 14 Other liabilities 5 16 Liabilities held for sale $ 7 $ 137 The fair values of the assets held for sale were determined using Level 3 inputs and were estimated based on recent market analysis studies, recent offers, and management has performed its own fair valuation modeling using discounted cash flows updated for market participant assumptions as completed by third party valuation firms. Unobservable inputs obtained from third parties were adjusted as necessary for the condition and attributes of the specific assets.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2018
Subsequent Events [Abstract]
Subsequent Events	Note 21. Subsequent Events On April 25, 2018, the board of directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable on July 2, 2018 to shareholders of record at the close of business on June 8, 2018 . On May 1, 2018, pursuant to the stock repurchase program, we repurchased 81,208 shares of AVANGRID common stock in the open market. The total cost of repurchase, including commissions, was $4 million .

Significant Accounting Polici31

Significant Accounting Policies and New Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued But Not Yet Adopted	Adoption of New Accounting Pronouncements (a) Revenue from contracts with customers In May 2014 the Financial Accounting Standards Board (FASB) Upon adoption, we classify production tax credits as income tax expense (benefit) rather than as operating revenue. (b) Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets The FASB The cumulative Balance Sheet Balance at December 31, 2017 Adjustments Due to ASC 606 Adjustments Due to ASC 610-20 Balance at January 1, 2018 (Millions) Liabilities Tax equity financing arrangements - VIEs $ 98 $ — $ (98 ) $ — Deferred income taxes $ 1,452 $ — $ (40 ) $ 1,412 Equity Retained earnings $ 1,475 $ — $ (2 ) $ 1,473 Non-controlling interests $ 19 $ — $ 140 $ 159 We also adopted the following standards as of their effective date of January 1, 2018, none of which had a material effect on our consolidated results of operations, financial position, cash flows, and disclosures. (c) Classifying and measuring financial instruments In January 2016 the FASB issued final guidance on the classification and measurement of financial instruments. As a result of our adoption we reclassified immaterial amounts from AOCI to retained earnings. (d) Certain classifications in the statement of cash flows In August 2016 the FASB issued amendments to address existing diversity in practice concerning the classification of certain cash receipts and payments on the statement of cash flows, which must be applied on a full retrospective basis. Upon adoption, we had no changes to our cash flow classifications and disclosures in our consolidated financial statements. (e) Improving the presentation of net periodic benefit costs In March 2017 the FASB issued amendments to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost in the financial statements. We retrospectively adopted the amendments that require us to present the service cost component separately from the other (non-service) components of net benefit cost, to report the service cost component in the income statement line item where we report the corresponding compensation cost, and to present all non-service components outside of operating cost. As a result, we have reclassified the non-service components – interest cost, expected return on plan assets, amortization of prior service cost (benefit), amortization of net loss, and settlement charge – from Operations and maintenance to Other income/(expense) within the statement of income. Prospectively, upon adoption, we will capitalize only the service cost component when applicable (for example, as a cost of a self-constructed asset). We elected to apply the practical expedient that allows us to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in our notes to financial statements for Post-retirement and Similar Obligations as the basis for those periods. In addition to those amounts, we included amortization of net benefit costs recorded as regulatory deferrals as a result of purchase accounting in a prior year. In connection with applying the practical expedient, in periods after adoption we will continue to include in operating income all legacy net benefit costs previously capitalized as a cost of self-constructed assets and other deferred regulatory costs. Our adoption of the amendments did not affect net income attributable to AVANGRID. The effect of the change in retrospective presentation related to the net periodic cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated statement of income was as follows: Three Months Ended March 31, 2017 Statement of Income As Revised As Previously Reported Effect of Change Higher/(Lower) (Millions) Operations and maintenance $ 522 $ 551 $ (29 ) Other income / (expense) $ (16 ) $ 13 $ (29 ) The segment information related to our Networks reportable segment provided in Note 13 for the three months ended March 31, 2017 has also been revised to reflect the change as a result of the adoption of these amendments. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements issued since December 31, 2017, that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) Land easement practical expedient In January 2018 the FASB issued amendments to clarify the application of the new leases guidance to land easements (also commonly called rights of way) and provide relief concerning adoption efforts for existing land easements that are not accounted for as leases under current GAAP. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We are currently reviewing our contracts and are in the process of determining the proper application of the lease standard, including the land easement practical expedient, in order to determine the impact that the adoption will have on our consolidated financial statements. We expect our adoption of the new guidance will materially affect our financial position through the recording of operating leases on the balance sheet as right-of-use assets, along with the corresponding liabilities. (b) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018 the FASB issued amendments to address a narrow-scope financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) enacted on December 22, 2017, by the U.S. federal government. Under current guidance, the adjustment of deferred taxes for the effect of a change in tax laws or rates is required to be included in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the Tax Act. As a result, the amendments eliminate the stranded tax effects resulting from the Tax Act and will improve the usefulness of information reported to financial statement users. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. The amendments are effective for all entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted including, for public entities, adoption in any interim period for which financial statements have not been issued. An entity has the option to apply the amendments either in the period of adoption or retrospectively to each period (or periods) in which it recognizes the effect of the change in the U.S. federal corporate income tax rate in the Tax Act. An entity is required to disclose its accounting policy election, including its policy for reclassifying material stranded tax effects in AOCI to earnings (specific identification or portfolio method). We have not early adopted the amendments as of March 31, 2018. We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows, and disclosures.

Significant Accounting Polici32

Significant Accounting Policies and New Accounting Pronouncements (Tables)	3 Months Ended
	Mar. 31, 2018
Accounting Policies [Abstract]
Schedule of Cumulative Effects of Changes to Consolidated Balance Sheet	The cumulative Balance Sheet Balance at December 31, 2017 Adjustments Due to ASC 606 Adjustments Due to ASC 610-20 Balance at January 1, 2018 (Millions) Liabilities Tax equity financing arrangements - VIEs $ 98 $ — $ (98 ) $ — Deferred income taxes $ 1,452 $ — $ (40 ) $ 1,412 Equity Retained earnings $ 1,475 $ — $ (2 ) $ 1,473 Non-controlling interests $ 19 $ — $ 140 $ 159
Effect of Change in Retrospective Presentation Related to Net Periodic Cost	The effect of the change in retrospective presentation related to the net periodic cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated statement of income was as follows: Three Months Ended March 31, 2017 Statement of Income As Revised As Previously Reported Effect of Change Higher/(Lower) (Millions) Operations and maintenance $ 522 $ 551 $ (29 ) Other income / (expense) $ (16 ) $ 13 $ (29 )

Revenue (Tables)

Revenue (Tables)	3 Months Ended
	Mar. 31, 2018
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 are as follows: Three Months Ended March 31, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 926 $ — $ — $ 926 Regulated operations – natural gas 572 — — 572 Nonregulated operations – wind — 168 — 168 Nonregulated operations – solar — 2 — 2 Nonregulated operations – thermal — 13 — 13 Nonregulated operations – gas storage — — 4 4 Other (a) 25 (23 ) 15 17 Revenue from contracts with customers 1,523 160 19 1,702 Leasing revenue 9 81 — 90 Derivative revenue — 43 10 53 Alternative revenue programs 19 — — 19 Other revenue 1 — — 1 Total operating revenues $ 1,552 $ 284 $ 29 $ 1,865 (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, Gas and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue	As of March 31, 2018, accounts receivable balances related to contracts with customers were approximately $1,076 million, which are included in “ Accounts receivable and unbilled revenues, net” As of March 31, 2018, for contracts with durations greater than one year (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied), and (2) when we expect to recognize the revenue, were as follows: As of March 31, 2018 2019 2020 2021 2022 2023 Thereafter Total (Millions) Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts $ — $ 14 $ 8 $ 3 $ 3 $ 4 $ 32 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 25 15 7 4 1 1 53 Total operating revenues $ 25 $ 29 $ 15 $ 7 $ 4 $ 5 $ 85

Regulatory Assets and Liabili34

Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2018
Regulated Operations [Abstract]
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 24 $ 24 Pension and other post-retirement benefits 11 7 Storm costs 46 46 Temporary supplemental assessment surcharge 1 — Reliability support services 27 27 Revenue decoupling mechanism 19 21 Transmission revenue reconciliation mechanism 3 8 Electric supply reconciliation 23 — Hedges losses 11 3 Contracts for differences 8 9 Hardship programs 13 14 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 2 31 Deferred transmission expense 38 37 Environmental remediation costs 13 13 Other 54 51 Total Current Regulatory Assets 309 307 Non-current Pension and other post-retirement benefits cost deferrals 111 110 Pension and other post-retirement benefits 1,116 1,162 Storm costs 284 254 Deferred meter replacement costs 29 29 Unamortized losses on reacquired debt 17 17 Environmental remediation costs 280 283 Unfunded future income taxes 376 376 Asset retirement obligation 19 18 Deferred property tax 10 14 Federal tax depreciation normalization adjustment 154 155 Merger capital expense target customer credit 2 2 Debt premium 128 131 Reliability support services 4 10 Plant decommissioning 7 9 Contracts for differences 95 84 Hardship programs 10 13 Deferred income taxes regulatory 20 — Other 72 71 Total Non-current Regulatory Assets $ 2,734 $ 2,738
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Current Non by-passable charges $ 8 $ 5 Energy efficiency portfolio standard 46 37 Gas supply charge and deferred natural gas cost 13 4 Transmission revenue reconciliation mechanism 15 14 Pension and other post-retirement benefits 1 1 Pension and other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 23 21 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE Refund — 4 Merger related rate credits — 1 Revenue decoupling mechanism 5 4 Stranded costs 13 17 Other 59 51 Total Current Regulatory Liabilities 202 178 Non-current Accrued removal obligations 1,143 1,132 Tax Act - remeasurement 1,562 1,515 Asset sale gain account 10 10 Carrying costs on deferred income tax bonus depreciation 66 72 Economic development 32 32 Merger capital expense target customer credit account 6 6 Pension and other post-retirement benefits cost deferrals 70 74 Positive benefit adjustment 38 39 New York state tax rate change 6 6 Theoretical reserve flow thru impact 18 19 Deferred property tax 21 19 Net plant reconciliation 10 10 Variable rate debt 35 33 Carrying costs on deferred income tax - Mixed Services 263(a) 19 20 Rate refund – FERC ROE proceeding 27 27 Transmission congestion contracts 20 19 Merger-related rate credits 20 20 Accumulated deferred investment tax credits 13 13 Asset retirement obligation 13 13 Earning sharing provisions 15 22 Middletown/Norwalk local transmission network service collections 18 19 Excess generation service charge — 2 Low income programs 39 42 Non-firm margin sharing credits 12 8 Deferred income taxes regulatory — 13 Other 74 67 Total Non-current Regulatory Liabilities $ 3,287 $ 3,252

Fair Value of Financial Instr35

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 4 36 76 (40 ) 76 Derivative financial instruments - gas — 10 39 (52 ) -3 Contracts for differences — — 10 — 10 Total 4 46 125 (92 ) 83 Derivative liabilities Derivative financial instruments - power (16 ) (21 ) (16 ) 46 (7 ) Derivative financial instruments - gas — (15 ) (5 ) 13 (7 ) Contracts for differences — — (113 ) — (113 ) Derivative financial instruments - other — — — — — Total $ (16 ) $ (36 ) $ (134 ) $ 59 $ (127 ) As of December 31, 2017 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 14 30 74 (49 ) 69 Derivative financial instruments - gas 89 18 64 (146 ) 25 Contracts for differences — — 12 — 12 Total 103 48 150 (195 ) 106 Derivative liabilities Derivative financial instruments - power (14 ) (17 ) (15 ) 37 (9 ) Derivative financial instruments - gas (80 ) (20 ) (25 ) 110 (15 ) Contracts for differences — — (104 ) — (104 ) Total $ (94 ) $ (37 ) $ (144 ) $ 147 $ (128 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	Included in the derivative financial instruments – gas are derivative assets and liabilities of Gas segment classified as held for sale on the condensed consolidated balance sheet as of December 31, 2017. See Note 20 – Assets Held For Sale for further discussion. The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2018 and 2017, respectively, is as follows: Three Months Ended March 31, (Millions) 2018 2017 Fair Value Beginning of Period, $ 6 $ 31 Gains recognized in operating revenues 5 12 (Losses) recognized in operating revenues (4 ) (2 ) Total gains recognized in operating revenues 1 10 Gains recognized in OCI — 1 (Losses) recognized in OCI (2 ) (1 ) Total gains recognized in OCI (2 ) — Net change recognized in regulatory assets and liabilities (11 ) (5 ) Purchases (2 ) 3 Settlements (1 ) (6 ) Fair Value as of March 31, $ (9 ) $ 33 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 $ 1 $ 10 Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input March 31, 2018 Risk of non-performance 0.66% - 0.69% Discount rate 2.27% - 2.74% Forward pricing ($ per MW) $4.30 - $9.55
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	As of March 31, 2018 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions delivery Transactions valued forward market Observable extrapolated forward power not can NYMEX $ 3.02 $ 3.93 $ 2.35 with delivery exceeding two on a corroborated by Indiana hub $ 31.32 $ 65.55 $ 18.53 period > two years discounted market data for Mid C $ 23.68 $ 46.50 $ (0.50 ) years basis identical or Minn hub $ 25.90 $ 62.33 $ 9.56 similar

Derivative Instruments and He36

Derivative Instruments and Hedging (Tables)	3 Months Ended
	Mar. 31, 2018
Derivative Instruments And Hedging Activities Disclosure [Abstract]
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 or regulatory liabilities, for the three months ended March 31, 2018 and 2017, respectively, were as follows: Three Months Ended March 31, 2018 2017 (Millions) Derivative assets $ (2 ) $ 5 Derivative liabilities $ (9 ) $ 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, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts (MWh) 3.7 3.9 Natural gas purchase contracts (Dth) 6.7 6.1 Fleet fuel purchase contracts (Gallons) 2.0 2.1 The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (MWh/Dth in millions) Wholesale electricity purchase contracts 4 4 Wholesale electricity sales contracts 6 6 Natural gas and other fuel purchase contracts 19 285 Financial power contracts 12 12 Basis swaps – purchases 33 68 Basis swaps – sales 5 62
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts	The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Networks activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 9 $ 5 $ 3 $ 1 Derivative liabilities (3 ) (1 ) (28 ) (101 ) 6 4 (25 ) (100 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 6 4 (25 ) (100 ) Cash collateral receivable — — 11 1 Total derivatives as presented in the balance sheet $ 6 $ 4 $ (14 ) $ (99 ) As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 20 $ 5 $ 13 $ — Derivative liabilities (13 ) — (32 ) (88 ) 7 5 (19 ) (88 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 7 5 (19 ) (88 ) Cash collateral receivable — — 3 — Total derivatives as presented in the balance sheet $ 7 $ 5 $ (16 ) $ (88 ) The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 43 $ 100 $ 3 $ 5 Derivative liabilities (21 ) (7 ) (13 ) (12 ) 22 93 (10 ) (7 ) Designated as hedging instruments Derivative assets 4 3 — 3 Derivative liabilities — — — (5 ) 4 3 — (2 ) Total derivatives before offset of cash collateral 26 96 (10 ) (9 ) Cash collateral receivable (payable) (12 ) (37 ) — 5 Total derivatives as presented in the balance sheet $ 14 $ 59 $ (10 ) $ (4 ) As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 111 $ 99 $ 31 $ 4 Derivative liabilities (82 ) (5 ) (51 ) (10 ) 29 94 (20 ) (6 ) Designated as hedging instruments Derivative assets 24 4 — 2 Derivative liabilities — (1 ) (3 ) (3 ) 24 3 (3 ) (1 ) Total derivatives before offset of cash collateral 53 97 (23 ) (7 ) Cash collateral receivable (payable) (17 ) (39 ) 3 3 Total derivatives as presented in the balance sheet, including assets and liabilities held for sale $ 36 $ 58 $ (20 ) $ (4 )
Schedule of Derivative Instruments, Effect of Cash flow Hedging on Other Comprehensive Income and Income	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses — Total $ — $ 2 2017 Interest rate contracts $ — Interest expense $ 2 Commodity contracts (1 ) Operating expenses — Total $ (1 ) $ 2 (a) The effect of derivatives in cash flow hedging relationships on OCI and income for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, (Loss) Gain Recognized in OCI on Derivatives Location of Loss (Gain) Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Commodity contracts $ (1 ) Revenues $ (19 ) Total $ (1 ) $ (19 ) 2017 Commodity contracts $ 4 Revenues $ 33 Total $ 4 $ 33 (a) Changes in OCI are reported on a pre-tax basis.
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables and Gas activities as of March 31, 2018 and December 31, 2017, respectively, consisted of: March 31, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts $ (1 ) $ (3 ) Wholesale electricity sales contracts 9 8 Natural gas and other fuel purchase contracts (1 ) 19 Financial power contracts 62 55 Basis swaps – purchases (10 ) (13 ) Basis swaps – sales — 4 Total $ 59 $ 70
Effect of Derivatives Associated with Renewables and Gas Activities	The effect of trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Wholesale electricity purchase contracts $ 1 $ (3 ) Wholesale electricity sales contracts 1 7 Financial power contracts (1 ) (3 ) Financial and natural gas contracts 3 4 Total Gain $ 4 $ 5 The effect of non-trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Wholesale electricity purchase contracts $ 1 $ (6 ) Wholesale electricity sales contracts — 11 Financial power contracts 3 16 Financial and natural gas contracts 5 (4 ) Total Gain $ 9 $ 17

Post-retirement and Similar O37

Post-retirement and Similar Obligations (Tables)	3 Months Ended
	Mar. 31, 2018
Compensation And Retirement Disclosure [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, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Service cost $ 11 $ 11 Interest cost 32 35 Expected return on plan assets (50 ) (50 ) Amortization of: Prior service costs — — Actuarial loss 38 32 Net Periodic Benefit Cost $ 31 $ 28 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Service cost $ 1 $ 1 Interest cost 4 5 Expected return on plan assets (2 ) (2 ) Amortization of: Prior service costs (2 ) (2 ) Actuarial loss 1 1 Net Periodic Benefit Cost $ 2 $ 3

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2018
Equity [Abstract]
Accumulated Other Comprehensive Gain (Loss)	Accumulated Other Comprehensive Loss Accumulated Other Comprehensive Gain (Loss) for the three months ended March 31, 2018 and 2017, respectively, consisted of: As of December 31, Adoption of new accounting Three Months Ended March 31, As of March 31, As of December 31, Three Months Ended March 31, As of March 31, 2017 standard 2018 2018 2016 2017 2017 (Millions) Loss on revaluation of defined benefit plans $ (14 ) $ — $ — $ (14 ) $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans (6 ) (1 ) — (7 ) (7 ) — (7 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense of $1.3 for 2017 30 — — 30 5 2 7 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense of $(7.5) for 2018 and $13.6 for 2017(a) (56 ) — (10 ) (66 ) (70 ) 23 (47 ) Gain (loss) on derivatives qualifying as cash flow hedges (26 ) — (10 ) (36 ) (65 ) 25 (40 ) Accumulated Other Comprehensive (Loss) Gain $ (46 ) $ (1 ) $ (10 ) $ (57 ) $ (86 ) $ 25 $ (61 ) (a) Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	3 Months Ended
	Mar. 31, 2018
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, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 244 $ 239 Denominator: Weighted average number of shares outstanding - basic 309,513,640 309,508,889 Weighted average number of shares outstanding - diluted 309,793,064 309,837,442 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.79 $ 0.77 Earnings Per Common Share, Diluted $ 0.79 $ 0.77

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2018
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the three months ended March 31, 2018, consisted of: Three Months Ended March 31, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,549 $ 283 $ 33 $ 1,865 Revenue - intersegment 3 1 (4 ) — Loss from assets held for sale — — 5 5 Depreciation and amortization 118 85 — 203 Operating income (loss) 344 44 15 403 Adjusted EBITDA 462 129 20 611 Earnings (losses) from equity method investments 2 — — 2 Interest expense, net of capitalization 60 8 6 74 Income tax expense (benefit) 64 (8 ) 16 72 Capital expenditures 282 116 1 399 As of March 31, 2018 Property, plant and equipment 13,996 8,754 7 22,757 Equity method investments 144 204 — 348 Total assets $ 21,481 $ 11,427 $ (1,425 ) $ 31,483 (a) Includes Corporate, Gas and intersegment eliminations. Segment information for the three months ended March 31, 2017, consisted of: Three Months Ended March 31, 2017 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,460 $ 285 $ 13 $ 1,758 Revenue - intersegment (1 ) 2 (1 ) — Depreciation and amortization 113 78 6 197 Operating income (loss) 365 56 6 427 Adjusted EBITDA 478 133 13 624 Earnings (losses) from equity method investments 4 (2 ) — 2 Interest expense, net of capitalization 63 7 1 71 Income tax expense (benefit) 116 (21 ) 8 103 Capital expenditures 267 257 1 525 As of December 31, 2017 Property, plant and equipment 13,876 8,786 7 22,669 Equity method investments 147 205 — 352 Total assets $ 21,411 $ 11,308 $ (1,048 ) $ 31,671 (a) Includes Corporate, Gas and intersegment eliminations.
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income	Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three months ended March 31, 2018 and 2017, respectively, is as follows: Three Months Ended March 31, 2018 2017 (Millions) Consolidated Adjusted EBITDA $ 611 $ 624 Less: Loss from assets held for sale 5 — Depreciation and amortization 203 197 Interest expense, net of capitalization 74 71 Income tax expense 72 103 Add: Other expense (21 ) (16 ) Earnings from equity method investments 2 2 Consolidated Net Income $ 238 $ 239

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2018
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three months ended March 31, 2018 and 2017, respectively, consisted of: Three Months Ended March 31, 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (4 ) $ — $ (10 ) Iberdrola Renovables Energía, S.L. — (3 ) — (2 ) Iberdrola, S.A. — (14 ) — (9 ) Iberdrola Energia Monterrey, S.A. de C.V. 3 — 15 — Other 1 (1 ) 1 —
Schedule of Related Party Balances	Related party balances as of March 31, 2018 and December 31, 2017, respectively, consisted of: As of March 31, 2018 December 31, 2017 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ — $ (31 ) $ — $ (31 ) Siemens-Gamesa 1 (47 ) 2 (51 ) Iberdrola, S.A. — (14 ) 1 (32 ) Iberdrola Renovables Energía, S.L. — (3 ) — — Iberdrola Energia Monterrey, S.A. de C.V. — — 1 — Other 7 (1 ) 6 (4 )

Supplemental Balance Sheet In42

Supplemental Balance Sheet Information (Tables)	3 Months Ended
	Mar. 31, 2018
Balance Sheet Related Disclosures [Abstract]
Schedule of Accumulated Depreciation and Amortization	The accumulated depreciation and amortization as of March 31, 2018 and December 31, 2017, respectively, were as follows March 31, December 31, As of 2018 2017 (Millions) Property, plant and equipment Accumulated depreciation $ 7,767 $ 7,497 Intangible assets Accumulated amortization $ 280 $ 276

Restructuring Expenses (Tables)

Restructuring Expenses (Tables)	3 Months Ended
	Mar. 31, 2018
Restructuring And Related Activities [Abstract]
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities	For the three months ended March 31, 2018, the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of: Three Months Ended March 31, 2018 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 1 Payments — Ending Balance $ 6

Assets Held for Sale (Tables)

Assets Held for Sale (Tables)	3 Months Ended
	Mar. 31, 2018
Assets Held For Sale Not Part Of Disposal Group [Abstract]
Summary of Current Assets and Current Liabilities Held for Sale	The current assets and current liabilities held for sale relating to our gas trading and storage businesses consisted of the following as of March 31, 2018 and December 31, 2017: March 31, December 31, As of 2018 2017 (Millions) Accounts receivable, net $ 1 $ 137 Derivative assets — 25 Fuel and gas in storage 1 77 Prepayments and other current assets 6 19 Property, plant and equipment 71 71 Intangible assets — 28 Assets held for sale $ 79 $ 357 Accounts payable and accrued liabilities 2 107 Derivative liabilities — 14 Other liabilities 5 16 Liabilities held for sale $ 7 $ 137

Background and Nature Of Oper45

Background and Nature Of Operations - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2018
Nature Of Business [Line Items]
Owned Subsidiaries	81.50%
Enstor Energy Services, LLC [Member]
Nature Of Business [Line Items]
Disposal date	Mar. 1, 2018
Enstor Gas, LLC [Member]
Nature Of Business [Line Items]
Disposal date	May 1, 2018

Significant Accounting Polici46

Significant Accounting Policies and New Accounting Pronouncements - Schedule of Cumulative Effects of Changes to Consolidated Balance Sheet (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Jan. 01, 2018	Dec. 31, 2017
Liabilities
Tax equity financing arrangements - VIEs			$ 60
Deferred income taxes	$ 1,510	$ 1,412	1,452
Equity
Retained earnings	1,579	1,473	1,475
Non-controlling interests	$ 148	159	19
Calculated Under Revenue and Other Income Guidance in Effect (Before Topic 606 and 610-20) [Member]
Liabilities
Tax equity financing arrangements - VIEs			98
Deferred income taxes			1,452
Equity
Retained earnings			1,475
Non-controlling interests			$ 19
Adjustments Due to ASC 610-20 [Member] | Accounting Standards Update 2017-05 [Member]
Liabilities
Tax equity financing arrangements - VIEs		(98)
Deferred income taxes		(40)
Equity
Retained earnings		(2)
Non-controlling interests		$ 140

Significant Accounting Polici47

Significant Accounting Policies and New Accounting Pronouncements - Effect of Change in Retrospective Presentation Related to Net Periodic Cost (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operations and maintenance	$ 527	$ 522
Other income / (expense)	$ (21)	(16)
Improving Presentation of Net Periodic Benefit Costs [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operations and maintenance		522
Other income / (expense)		(16)
Improving Presentation of Net Periodic Benefit Costs [Member] | As Previously Reported [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operations and maintenance		551
Other income / (expense)		13
Improving Presentation of Net Periodic Benefit Costs [Member] | Effect of Change Higher/(Lower) [Member]
New Accounting Pronouncements Or Change In Accounting Principle [Line Items]
Operations and maintenance		(29)
Other income / (expense)		$ (29)

Revenue - Additional Informatio

Revenue - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Utility Revenue [Line Items]
Practical expedient cost incurred to obtain a contract description of amortization term	one year or less
Accounts receivable related to contracts with customers	$ 1,076
Minimum [Member]
Utility Revenue [Line Items]
Capitalized contract cost amortization term	3 years
Maximum [Member]
Utility Revenue [Line Items]
Capitalized contract cost amortization term	20 years
Networks Segment [Member]
Utility Revenue [Line Items]
Customer payment description	one year or less

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Segment Reporting Information [Line Items]
Operating Revenues		$ 1,865	$ 1,758
Revenue from Contract with Customer [Member]
Segment Reporting Information [Line Items]
Operating Revenues		1,702
Leasing Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues		90
Derivative Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues		53
Alternative Revenue Programs [Member]
Segment Reporting Information [Line Items]
Operating Revenues		19
Other Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues		1
Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]	17
Regulated Operations [Member] | Electricity [Member]
Segment Reporting Information [Line Items]
Operating Revenues		926
Regulated Operations [Member] | Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues		572
Nonregulated Operation [Member] | Wind [Member]
Segment Reporting Information [Line Items]
Operating Revenues		168
Nonregulated Operation [Member] | Solar [Member]
Segment Reporting Information [Line Items]
Operating Revenues		2
Nonregulated Operation [Member] | Thermal [Member]
Segment Reporting Information [Line Items]
Operating Revenues		13
Nonregulated Operation [Member] | Gas Storage [Member]
Segment Reporting Information [Line Items]
Operating Revenues		4
Network [Member]
Segment Reporting Information [Line Items]
Operating Revenues		1,552
Network [Member] | Revenue from Contract with Customer [Member]
Segment Reporting Information [Line Items]
Operating Revenues		1,523
Network [Member] | Leasing Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues		9
Network [Member] | Alternative Revenue Programs [Member]
Segment Reporting Information [Line Items]
Operating Revenues		19
Network [Member] | Other Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues		1
Network [Member] | Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]	25
Network [Member] | Regulated Operations [Member] | Electricity [Member]
Segment Reporting Information [Line Items]
Operating Revenues		926
Network [Member] | Regulated Operations [Member] | Natural Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues		572
Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues		284
Renewables [Member] | Revenue from Contract with Customer [Member]
Segment Reporting Information [Line Items]
Operating Revenues		160
Renewables [Member] | Leasing Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues		81
Renewables [Member] | Derivative Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues		43
Renewables [Member] | Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]	(23)
Renewables [Member] | Nonregulated Operation [Member] | Wind [Member]
Segment Reporting Information [Line Items]
Operating Revenues		168
Renewables [Member] | Nonregulated Operation [Member] | Solar [Member]
Segment Reporting Information [Line Items]
Operating Revenues		2
Renewables [Member] | Nonregulated Operation [Member] | Thermal [Member]
Segment Reporting Information [Line Items]
Operating Revenues		13
Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[2]	29
Other [Member] | Revenue from Contract with Customer [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[2]	19
Other [Member] | Derivative Revenue [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[2]	10
Other [Member] | Other [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1],[2]	15
Other [Member] | Nonregulated Operation [Member] | Gas Storage [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[2]	$ 4
[1]	Primarily includes certain intra-month trading activities, billing, collection, and administrative charges, sundry billings, and other miscellaneous revenue.
[2]	Does not represent a segment. Includes Corporate, Gas and intersegment eliminations.

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, 2018USD ($)
Utility Revenue [Line Items]
2,019	$ 25
2,020	29
2,021	15
2,022	7
2,023	4
Thereafter	5
Total	85
Capacity and Carbon-free Energy Sale Contracts [Member]
Utility Revenue [Line Items]
2,020	14
2,021	8
2,022	3
2,023	3
Thereafter	4
Total	32
Renewable Energy Credit Sale Contracts [Member]
Utility Revenue [Line Items]
2,019	25
2,020	15
2,021	7
2,022	4
2,023	1
Thereafter	1
Total	$ 53

Regulatory Assets and Liabili51

Regulatory Assets and Liabilities - Additional Information (Detail) $ in Millions	Oct. 16, 2017	Dec. 31, 2016	Mar. 31, 2018USD ($)Station	Mar. 31, 2017USD ($)	Apr. 30, 2019	Dec. 31, 2018	Apr. 30, 2018	Apr. 30, 2017	Dec. 31, 2017USD ($)
Regulatory Assets And Liabilities [Line Items]
Unrecorded Regulatory Assets			$ 1,867
Equity ratio		50.00%
Public utilities regulatory authority distribution rate		9.10%
Unfunded future Income tax expense collection period			50 years
Federal statutory income tax rate			35.00%	35.00%
UIL Holdings [Member]
Regulatory Assets And Liabilities [Line Items]
Business combination merger related rate credits			$ 1	$ 2
NEW YORK
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
NEW YORK | Prior Tax Rate [Member]
Regulatory Assets And Liabilities [Line Items]
Statutory income tax rate, state			7.10%
NEW YORK | Revised Tax Rate [Member]
Regulatory Assets And Liabilities [Line Items]
Statutory income tax rate, state			6.50%
NEW YORK | Oswego [Member]
Regulatory Assets And Liabilities [Line Items]
Number of nuclear generating stations | Station			2
Asset Sale Gain Account [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
Economic Development [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
Merger Capital Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
Positive Benefit Adjustment [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
Post Term Amortization [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Approved return on equity			11.74%
Maximum [Member] | NEW YORK
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period			39 years
Minimum [Member] | NEW YORK
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period			27 years
Scenario, Plan [Member]
Regulatory Assets And Liabilities [Line Items]
Federal statutory income tax rate						21.00%
Electric and Gas Service Rate Plan Year One [Member]
Regulatory Assets And Liabilities [Line Items]
Customer receiving percentage			50.00%
Return on equity								9.50%
Electric and Gas Service Rate Plan Year One [Member] | Scenario, Forecast [Member]
Regulatory Assets And Liabilities [Line Items]
Return on equity					9.75%		9.65%
Electric and Gas Service Rate Plan Year Two [Member]
Regulatory Assets And Liabilities [Line Items]
Customer receiving percentage			75.00%
Return on equity								10.00%
Electric and Gas Service Rate Plan Year Two [Member] | Scenario, Forecast [Member]
Regulatory Assets And Liabilities [Line Items]
Return on equity					10.25%		10.15%
Electric and Gas Service Rate Plan Year Three [Member]
Regulatory Assets And Liabilities [Line Items]
Customer receiving percentage			90.00%
Return on equity								10.50%
Electric and Gas Service Rate Plan Year Three [Member] | Scenario, Forecast [Member]
Regulatory Assets And Liabilities [Line Items]
Return on equity					10.75%		10.65%
New York State Electric And Gas Corporation
Regulatory Assets And Liabilities [Line Items]
Annual amortization of regulatory items			$ 16.5
Regulatory items amortization period			3 years
Approved return on equity			9.00%
Equity ratio			48.00%
New York State Electric And Gas Corporation | Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Equity ratio for earnings sharing			50.00%
New York State Electric And Gas Corporation | Storm Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			10 years
New York State Electric And Gas Corporation | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
New York State Electric And Gas Corporation | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			50 years
RG&E [Member]
Regulatory Assets And Liabilities [Line Items]
Approved return on equity			9.00%
Equity ratio			48.00%
RG&E [Member] | Deferred Property Tax [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
RG&E [Member] | Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Equity ratio for earnings sharing			50.00%
RG&E [Member] | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			50 years
United Illuminating Company (UI)
Regulatory Assets And Liabilities [Line Items]
Public utilities nature of allowance for earnings on equity, description			UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year
SCG [Member]
Regulatory Assets And Liabilities [Line Items]
Equity ratio	52.00%
Public utilities regulatory authority distribution rate	9.25%
Proposed ROE for the year 2018			9.95%
Proposed ROE for the year 2019			9.95%
Proposed ROE for the year 2020			9.95%
Amount of proposed ROE for the year 2018			$ 1.5
Amount of proposed ROE for the year 2019			4.7
Amount of proposed ROE for the year 2020			5
Central Maine Power Company [Member]
Regulatory Assets And Liabilities [Line Items]
Recovery of deferred storm costs			$ 123
Central Maine Power Company [Member] | Storm Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			10 years
Central Maine Power Company [Member] | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years
UI [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets			$ 103						$ 93
UI [Member] | Storm Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred costs			1
Regulatory assets			$ 0
NYSEG [Member] | Deferred Property Tax [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period			5 years

Regulatory Assets and Liabili52

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Regulatory Asset [Line Items]
Current Regulatory Assets	$ 309	$ 307
Non-current Regulatory Assets	2,714	2,738
Deferred income taxes regulatory	20
Regulatory assets including deferred income taxes, noncurrent	2,734	2,738
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	24	24
Non-current Regulatory Assets	111	110
Pension And Other Post-Retirement Benefits [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	11	7
Non-current Regulatory Assets	1,116	1,162
Storm Costs [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	46	46
Non-current Regulatory Assets	284	254
Temporary Supplemental Assessment Surcharge [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	1
Support Services [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	27	27
Non-current Regulatory Assets	4	10
Revenue Decoupling Mechanism [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	19	21
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	3	8
Electric Supply Reconciliation [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	23
Hedges Loss [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	11	3
Contracts For Differences [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	8	9
Non-current Regulatory Assets	95	84
Hardship Programs [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	13	14
Non-current Regulatory Assets	10	13
Deferred Property Tax [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	10	10
Non-current Regulatory Assets	10	14
Plant Decommissioning [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	6	6
Non-current Regulatory Assets	7	9
Deferred Purchased Gas [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	2	31
Deferred Transmission Expense [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	38	37
Environmental Restoration Costs [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	13	13
Non-current Regulatory Assets	280	283
Other [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	54	51
Non-current Regulatory Assets	72	71
Deferred Meter Replacement Costs [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	29	29
Unamortized Loss On Reacquired Debt [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	17	17
Future Income Tax [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	376	376
Asset Retirement Obligation Costs [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	19	18
Federal Tax Depreciation Normalization Adjustment [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	154	155
Merger Capital Expense [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	2	2
Debt Premium [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	$ 128	$ 131

Regulatory Assets and Liabili53

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	$ 202	$ 178
Non-current Regulatory Liabilities	3,287	3,239
Deferred income taxes regulatory		13
Regulatory liabilities including deferred income taxes, noncurrent	3,287	3,252
Non By Passable Charge [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	8	5
Energy Efficiency Services [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	46	37
Gas Supply Charge And Deferred Natural Gas Cost [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	13	4
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	15	14
Pension And Other Post-Retirement Benefits [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	1	1
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	14	14
Non-current Regulatory Liabilities	70	74
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	23	21
Non-current Regulatory Liabilities	66	72
Yankee DOE Refund [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities		4
Merger Related Rate Credits [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities		1
Non-current Regulatory Liabilities	20	20
Carrying Costs On Deferred Income Tax [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	5	5
Non-current Regulatory Liabilities	19	20
Revenue Decoupling Mechanism [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	5	4
Stranded Costs [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	13	17
Other [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	59	51
Non-current Regulatory Liabilities	74	67
Accrued Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	1,143	1,132
Tax Act - Remeasurement [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	1,562	1,515
Asset Sale Gain Account [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	10	10
Economic Development [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	32	32
Merger Capital Expense [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	6	6
Positive Benefit Adjustment [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	38	39
New York State Tax Rate Change [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	6	6
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	18	19
Deferred Property Tax [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	21	19
Net Plant Reconciliation [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	10	10
Variable Rate Debt [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	35	33
Rate Refund [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	27	27
Accumulated Deferred Investment Tax Credits [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	13	13
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	13	13
Transmission Congestion Contracts [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	20	19
Middletown/Norwalk Local Transmission Network Service Collections [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	18	19
Excess Generation Service Charge [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities		2
Low Income Programs [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	39	42
Earning sharing provisions [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	15	22
Non-Firm Margin Sharing Credits [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	$ 12	$ 8

Fair Value of Financial Instr54

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other Assets	$ 83	$ 71
Fair value of debt	5,625	5,799
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of debt	$ 61	61
Minimum [Member]
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 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other Assets	$ 5	$ 5
RG&E [Member]
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 Instr55

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 83	$ 106
Derivative financial instruments, liabilities	(127)	(128)
Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(92)	(195)
Derivative financial instruments, liabilities	59	147
Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	41	40
Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	76	69
Derivative financial instruments, liabilities	(7)	(9)
Derivative Financial Instrument Power [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(40)	(49)
Derivative financial instruments, liabilities	46	37
Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(3)	25
Derivative financial instruments, liabilities	(7)	(15)
Derivative Financial Instrument Gas [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(52)	(146)
Derivative financial instruments, liabilities	13	110
Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	10	12
Derivative financial instruments, liabilities	(113)	(104)
Fair Value, Inputs, Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	4	103
Derivative financial instruments, liabilities	(16)	(94)
Fair Value, Inputs, Level 1 [Member] | Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	41	41
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	4	14
Derivative financial instruments, liabilities	(16)	(14)
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets		89
Derivative financial instruments, liabilities		(80)
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	46	48
Derivative financial instruments, liabilities	(36)	(37)
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	36	30
Derivative financial instruments, liabilities	(21)	(17)
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	10	18
Derivative financial instruments, liabilities	(15)	(20)
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	125	150
Derivative financial instruments, liabilities	(134)	(144)
Level 3 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	76	74
Derivative financial instruments, liabilities	(16)	(15)
Level 3 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	39	64
Derivative financial instruments, liabilities	(5)	(25)
Level 3 [Member] | Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	10	12
Derivative financial instruments, liabilities	$ (113)	$ (104)

Fair Value of Financial Instr56

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, 2018	Mar. 31, 2017
Debt Instrument Fair Value Carrying Value [Abstract]
Fair Value as of January 1,	$ 6	$ 31
Gains recognized in operating revenues	5	12
(Losses) recognized in operating revenues	(4)	(2)
Total gains recognized in operating revenues	1	10
Gains recognized in OCI		1
(Losses) recognized in OCI	(2)	(1)
Total gains recognized in OCI	(2)
Net change recognized in regulatory assets and liabilities	(11)	(5)
Purchases	(2)	3
Settlements	(1)	(6)
Fair Value as of March 31,	(9)	33
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	$ 1	$ 10

Fair Value of Financial Instr57

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	3 Months Ended
	Mar. 31, 2018$ / MMBTU$ / MWh
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Instruments	Fixed price power and gas swaps with delivery period > two years
Instrument Description	Transactions with delivery periods exceeding two years
Valuation Technique	Transactions are valued against forward market prices on a discounted basis
Valuation Inputs	Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products
CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	NYMEX ($/MMBtu)
CME SWAPS MARKETS (NYMEX) [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	3.02
CME SWAPS MARKETS (NYMEX) [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	3.93
CME SWAPS MARKETS (NYMEX) [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	2.35
Indiana Hub [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Indiana hub ($/MWh)
Indiana Hub [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	31.32
Indiana Hub [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	65.55
Indiana Hub [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	18.53
Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Mid C ($/MWh)
Mid C [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	23.68
Mid C [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	46.50
Mid C [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	(0.50)
Minn Hub [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Minn hub ($/MWh)
Minn Hub [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	25.90
Minn Hub [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	62.33
Minn Hub [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	9.56

Fair Value of Financial Instr58

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Detail) - Contracts For Differences [Member] - Level 3 [Member]	3 Months Ended
	Mar. 31, 2018$ / MWh
Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.66%
Discount rate	2.27%
Forward pricing ($ per MW)	4.30
Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.69%
Discount rate	2.74%
Forward pricing ($ per MW)	9.55

Derivative Instruments and He59

Derivative Instruments and Hedging - Additional Information (Detail) - USD ($)		3 Months Ended		12 Months Ended
		Mar. 31, 2018	Mar. 31, 2017	Mar. 31, 2019	Dec. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities		$ (65,000,000)	$ 45,000,000
Gain (Loss) reclassified from regulatory assets and liabilities into income		4,000,000	5,000,000
Derivative financial instruments, assets		83,000,000				$ 106,000,000
Gross Amounts of Recognized Liabilities		127,000,000				128,000,000
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]	(10,000,000)	23,000,000
UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets		10,000,000				12,000,000
Regulatory Assets		103,000,000				93,000,000
Gross Amounts of Recognized Liabilities		113,000,000				104,000,000
Regulatory liabilities		$ 0				0
Contracts For Differences [Member] | UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers		20.00%
Contracts For Differences [Member] | CL&P [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers		80.00%
Derivative financial instruments, assets		$ 0				0
Gross Amounts of Recognized Liabilities		100,000,000				90,000,000
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	[2]		(1,000,000)
Network [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges		2,000,000	2,000,000
Ineffective portion of Cash flow hedge		0	0
Unrealized gain(loss) from hedging activities reported on OCI		$ (200,000)
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months		12 months
Network [Member] | Cash Flow Hedging [Member] | Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes					$ 8,000,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months				$ 200,000
Network [Member] | forward starting swaps [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps		$ 66,800,000				68,800,000
Network [Member] | Electricity Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities		(11,500,000)				(200,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income		5,800,000				(10,900,000)
Network [Member] | Natural Gas Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities		(200,000)				(2,500,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income		$ (1,700,000)	600,000
Network [Member] | Fuel Derivatives [Member] | Cash Flow Hedging [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges		12 months
Renewables and Gas Activities [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Ineffective portion of Cash flow hedge		$ 100,000	$ (300,000)
Unrealized gain(loss) from hedging activities reported on OCI		$ 3,700,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months		12 months
Net loss in accumulated OCI related to discontinued cash flow hedge		$ 500,000
Amortizable portion of loss on discontinuation of cash flow hedge		200,000
Counter Party [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities		11,700,000
Cash Collateral Pledged		2,000,000				$ 30,000,000
Counter Party [Member] | UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative collateral obligation to be paid in decrease in credit rating below investment grade		$ 15,000,000
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.
[2]	Changes in OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income.

Derivative Instruments and He60

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities)	$ (2)	$ 5
Derivative Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities)	$ (9)	$ 1

Derivative Instruments and He61

Derivative Instruments and Hedging - Net Notional Volume (Detail)	Mar. 31, 2018MWhDTHgal	Dec. 31, 2017MWhDTHgal
Network [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	3,700,000	3,900,000
Network [Member] | Natural Gas Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	6,700,000	6,100,000
Network [Member] | Fleet Fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | gal	2,000,000	2,100,000
Renewables and Gas Activities [Member] | Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	33,000,000	68,000,000
Renewables and Gas Activities [Member] | Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	5,000,000	62,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	4,000,000	4,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	6,000,000	6,000,000
Renewables and Gas Activities [Member] | Natural Gas and Other fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	19,000,000	285,000,000
Renewables and Gas Activities [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	12,000,000	12,000,000

Derivative Instruments and He62

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Network [Member] | UIL Holdings [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	$ 6	$ 7
Total derivatives as presented in the balance sheet	6	7
Network [Member] | UIL Holdings [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	9	20
Derivative liabilities	(3)	(13)
Derivative Fair Value, Net	6	7
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	4	5
Total derivatives as presented in the balance sheet	4	5
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	5	5
Derivative liabilities	(1)
Derivative Fair Value, Net	4	5
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(25)	(19)
Cash collateral receivable	11	3
Total derivatives as presented in the balance sheet	(14)	(16)
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	3	13
Derivative liabilities	(28)	(32)
Derivative Fair Value, Net	(25)	(19)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(100)	(88)
Cash collateral receivable	1
Total derivatives as presented in the balance sheet	(99)	(88)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	1
Derivative liabilities	(101)	(88)
Derivative Fair Value, Net	(100)	(88)
Renewables and Gas Activities [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	26	53
Cash collateral receivable (payable)	(12)	(17)
Total derivatives as presented in the balance sheet	14	36
Renewables and Gas Activities [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	43	111
Derivative liabilities	(21)	(82)
Derivative Fair Value, Net	22	29
Renewables and Gas Activities [Member] | Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	4	24
Derivative Fair Value, Net	4	24
Renewables and Gas Activities [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	96	97
Cash collateral receivable (payable)	(37)	(39)
Total derivatives as presented in the balance sheet	59	58
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	100	99
Derivative liabilities	(7)	(5)
Derivative Fair Value, Net	93	94
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	3	4
Derivative liabilities		(1)
Derivative Fair Value, Net	3	3
Renewables and Gas Activities [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(10)	(23)
Cash collateral receivable (payable)		3
Total derivatives as presented in the balance sheet	(10)	(20)
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	3	31
Derivative liabilities	(13)	(51)
Derivative Fair Value, Net	(10)	(20)
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities		(3)
Derivative Fair Value, Net		(3)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(9)	(7)
Cash collateral receivable (payable)	5	3
Total derivatives as presented in the balance sheet	(4)	(4)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	5	4
Derivative liabilities	(12)	(10)
Derivative Fair Value, Net	(7)	(6)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	3	2
Derivative liabilities	(5)	(3)
Derivative Fair Value, Net	$ (2)	$ (1)

Derivative Instruments and He63

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI on Derivatives	[1]		$ (1)
Loss Reclassified from Accumulated OCI into Income	[1]	$ 2	2
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	[2]	(19)	33
(Loss) Gain Recognized in OCI on Derivatives	[2]	(1)	4
Interest Rate Contract | Network [Member] | Interest Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	[1]	2	2
Commodity Contract | Network [Member] | Operating Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI on Derivatives	[1]		(1)
Commodity Contract | Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	[2]	(1)	4
Commodity Contract | Renewables and Gas Activities [Member] | Revenue [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income	[2]	$ (19)	$ 33
[1]	Changes in OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income.
[2]	Changes in OCI are reported on a pre-tax basis.

Derivative Instruments and He64

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 59	$ 70
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	62	55
Long [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(1)	(3)
Long [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(1)	19
Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(10)	(13)
Short [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 9	8
Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net		$ 4

Derivative Instruments and He65

Derivative Instruments and Hedging - Effect of Trading Derivatives (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 4	$ 5
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	1	(3)
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	1	7
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(1)	(3)
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 3	$ 4

Derivative Instruments and He66

Derivative Instruments and Hedging - Effect of Non-Trading Derivatives (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 4	$ 5
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	9	17
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	1	(6)
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net		11
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	3	16
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Financial and Natural Gas Contracts [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 5	$ (4)

Contingencies - Additional Info

Contingencies - Additional Information (Detail) $ in Millions

Apr. 30, 2018

Mar. 27, 2018

Oct. 06, 2017

Oct. 05, 2017Lawsuit

Apr. 14, 2017

Apr. 29, 2016

Mar. 22, 2016

Jul. 31, 2014

Dec. 26, 2012

Mar. 31, 2018USD ($)

Dec. 31, 2017USD ($)

Mar. 11, 2017Customer

Loss Contingencies [Line Items]

Requested return on equity base percentage

9.20%

Disclosure of Rate Matters

On June 19, 2014, the FERC issued its decision in Complaint I, establishing an ROE methodology and setting an issue for a paper hearing. On October 16, 2014, FERC issued its final decision in Complaint I setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs)

Midpoint of base return on equity warranted percentage

9.39%

Regulatory liabilities

$ 3,287

$ 3,239

Loss contingency, date of dismissal

Oct. 5, 2017

Number of complaints dismissed | Lawsuit

4

Loss contingency dismissal description

On October 5, 2017, the NETOs filed a Motion for Dismissal of Pancaked Return on Equity Complaints in light of the decision by the Court in April 2017 that became effective on June 8, 2017. The NETOs assert that all four complaints should be dismissed because the complainants have not shown that the existing ROE of 11.14% is unjust and unreasonable as the Court decision requires. In addition, the NETOs assert that Complaints II, III and IV should also be dismissed because the Court decision implicitly found that FERC’s acceptance of Pancaked FPA Section 206 complaints was statutorily improper as Congress intended that the 15-month refund period under Section 206 applies whenever FERC does not complete its review of a complaint within the 15-month period.

Price of the power purchase agreements

$ 259

Standby letters of credit

$ 2,200

Subsequent Event [Member]

Loss Contingencies [Line Items]

Requested renewables delay from preliminary proposed ruling period

2 years

March 2017 Windstorm [Member]

Loss Contingencies [Line Items]

Number of affected customers | Customer

219,000

Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.74%

Requested return on equity base percentage

11.14%

Complaint II [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.70%

Disclosure of Rate Matters

On December 26, 2012, a second ROE complaint (Complaint II) for a subsequent rate period was filed requesting the then effective ROE of 11.14% be reduced to 8.7%. On June 19, 2014, FERC accepted Complaint II, established a 15-month refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in Complaint I.

Requested effective return on equity base percentage

11.14%

Regulatory liabilities

$ 22.7

Complaint II [Member] | Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Complaint III [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.84%

Requested effective return on equity base percentage

11.14%

Regulatory liabilities

$ 4.4

Complaint III [Member] | Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Complaint II and III [Member]

Loss Contingencies [Line Items]

Disclosure of Rate Matters

On November 24, 2014, FERC accepted the Complaint III, established a 15-month refund effective date of July 31, 2014, and set this matter consolidated with Complaint II for hearing in June 2015. Hearings relating to the refund periods and going forward period were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the NETOs filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The FERC Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that: (1) for the 15-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 15-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 is the Administrative Law Judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in 2018.

Reasonably possible loss, in additional reserve, pre tax

$ 17.1

Unfavorable Regulatory Action [Member] | Complaint I [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.57%

Unfavorable Regulatory Action [Member] | Complaint II [Member]

Loss Contingencies [Line Items]

Approved return on equity

9.59%

Unfavorable Regulatory Action [Member] | Complaint III [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Unfavorable Regulatory Action [Member] | Complaint Four [Member]

Loss Contingencies [Line Items]

Approved return on equity

8.61%

Requested existing base return on equity base percentage

10.57%

Rejected currently-filed base return on equity percentage

10.57%

Unfavorable Regulatory Action [Member] | Complaint Four [Member] | Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.74%

11.24%

Before Amendment [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.14%

Environmental Liabilities - Add

Environmental Liabilities - Additional Information (Detail) $ in Millions	Jul. 05, 2017USD ($)	Sep. 11, 2014USD ($)	Aug. 14, 2013USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)	Mar. 31, 2018USD ($)siteLocation	Dec. 31, 2017USD ($)	Aug. 04, 2016USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							25
Number of sites where gas was manufactured in the past | site							53
Number of sites for which we have entered into consent orders to investigate and remediate | site							49
Costs related to investigation and remediation							$ 387	$ 389
Accrual for environmental loss contingencies		$ 27					$ 22
Damages for incurred costs payment amount		$ 22
Refund of environmental remediation cost paid					$ 5
Number of sites with modified decision | site							9
First Energy [Member]
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax						$ 60
Environmental costs paid				$ 30
First Energy [Member] | Past Costs [Member]
Environmental Exit Cost [Line Items]
Accrual for environmental loss contingencies				27
First Energy [Member] | Pre-judgment Interest [Member]
Environmental Exit Cost [Line Items]
Environmental costs paid				$ 3
Century Indemnity and OneBeacon [Member]
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax			$ 89
Number of hazardous waste sites | Location							22
Legal discovery process expected closing year description							Century Indemnity and OneBeacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s
Asnat [Member] | Environmental Remediation Activities [Member]
Environmental Exit Cost [Line Items]
Pretrial memorandum claiming damages	$ 10
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 25	25	$ 30
Maximum [Member] | Century Indemnity and OneBeacon [Member]
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax			$ 282
New York State Registry [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							15
Number of sites where gas was manufactured in the past | site							8
Maine's Uncontrolled Sites Program [Member]
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 [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							1
National Priorities List [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							9
Ten of Twenty-five Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 5
Another Ten Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							8
Another Ten Sites [Member] | Minimum [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							12
Another Ten Sites [Member] | Maximum [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 21
New York Voluntary Cleanup Program [Member]
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site							12
Maine's Voluntary Response Action Program [Member]
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site							3
Manufactured Gas Plants | Connecticut [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 99	$ 100
Manufactured Gas Plants | Minimum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							213
Manufactured Gas Plants | Maximum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 442

Post-Retirement and Similar O69

Post-Retirement and Similar Obligations - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Compensation And Retirement Disclosure [Abstract]
Defined benefit, pension contributions	$ 2
Additional contributions for remainder of fiscal year	$ 46

Post-Retirement and Similar O70

Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 11	$ 11
Interest cost	32	35
Expected return on plan assets	(50)	(50)
Amortization of actuarial loss	38	32
Net Periodic Benefit Cost	31	28
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1
Interest cost	4	5
Expected return on plan assets	(2)	(2)
Amortization of prior service costs	(2)	(2)
Amortization of actuarial loss	1	1
Net Periodic Benefit Cost	$ 2	$ 3

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended		12 Months Ended
	May 31, 2017	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2016	Dec. 31, 2017
Class Of Stock [Line Items]
Common stock, authorized		500,000,000			500,000,000
Common stock, issued		309,752,140			309,670,932
Common stock, outstanding		309,086,480			309,005,272
Common stock, par value		$ 0.01			$ 0.01
Common stock		$ 3			$ 3
Additional paid-in capital		$ 13,654			$ 13,653
Treasury stock, shares		485,810			485,810
Convertible preferred stock, shares outstanding		0			0
Issuance of common stock, shares		81,208	70,493
Release of common stock held in trust		0	5,649
Treasury shares of common stock		179,850
Repurchase of common stock, shares	64,019			115,831
Repurchases of common stock		$ 8			$ 8
Iberdrola Renewables Holding, Inc [Member]
Class Of Stock [Line Items]
Percentage of equity owned by parent		81.50%			81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Gain (Loss) (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Dec. 31, 2017	Mar. 31, 2017	Dec. 31, 2016
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)				$ 2
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense		$ (36)	$ (26)	(40)	$ (65)
Accumulated Other Comprehensive (Loss) Gain		(57)	(46)	(61)	(86)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)	[1]	(10)		23
Net unrealized (loss) gain on derivatives qualifying as cash flow hedges		(10)		25
Accumulated Other Comprehensive (Loss) Gain		(10)		25
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense	[1]	(66)	(56)	(47)	(70)
Designated as Hedging Instrument [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)		30	30	7	5
Adoption of New Accounting standards [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Accumulated Other Comprehensive (Loss) Gain		(1)
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Loss on defined benefit plans		(14)	(14)	(14)	(14)
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Loss on defined benefit plans		(7)	$ (6)	$ (7)	$ (7)
Non-Qualified Pension Plans [Member] | Adoption of New Accounting standards [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Loss on defined benefit plans		$ (1)
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Equity - Accumulated Other Co73

Equity - Accumulated Other Comprehensive Gain (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Equity [Abstract]
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax expense (benefit)		$ 1.3
Reclassification to net income of losses (gains) on cash flow hedges, income tax expense (benefit)	$ (7.5)	$ 13.6

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Numerator:
Net income attributable to AVANGRID	$ 244	$ 239
Denominator:
Weighted average number of shares outstanding - basic	309,513,640	309,508,889
Weighted average number of shares outstanding - diluted	309,793,064	309,837,442
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$ 0.79	$ 0.77
Earnings Per Common Share, Diluted	$ 0.79	$ 0.77

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)Segment	Mar. 31, 2017USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	2
Operating Revenues	$ 1,865	$ 1,758
Regulated Electric Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	955	921
Regulated Gas Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	600	537
Other Networks [Member]
Segment Reporting Information [Line Items]
Operating Revenues	(6)	2
Renewable Energy Generation Of Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues	$ 283	$ 285
Network [Member]
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	1
Number of operating segments | Segment	8

Segment information (Detail)

Segment information (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenue - external		$ 1,865	$ 1,758
Loss from assets held for sale		5
Depreciation and amortization		203	197
Operating income (loss)		403	427
Adjusted EBITDA		611	624
Earnings (losses) from equity method investments		2	2
Interest expense, net of capitalization		74	71
Income tax expense (benefit)		72	103
Capital expenditures		399	525
Property, plant and equipment		22,757	22,669	$ 22,669
Equity method investments		348	352	352
Total assets		31,483	31,671	$ 31,671
Operating Segments [Member] | Network [Member]
Segment Reporting Information [Line Items]
Revenue - external		1,549	1,460
Revenue - intersegment		3	(1)
Depreciation and amortization		118	113
Operating income (loss)		344	365
Adjusted EBITDA		462	478
Earnings (losses) from equity method investments		2	4
Interest expense, net of capitalization		60	63
Income tax expense (benefit)		64	116
Capital expenditures		282	267
Property, plant and equipment		13,996	13,876
Equity method investments		144	147
Total assets		21,481	21,411
Operating Segments [Member] | Renewables [Member]
Segment Reporting Information [Line Items]
Revenue - external		283	285
Revenue - intersegment		1	2
Depreciation and amortization		85	78
Operating income (loss)		44	56
Adjusted EBITDA		129	133
Earnings (losses) from equity method investments			(2)
Interest expense, net of capitalization		8	7
Income tax expense (benefit)		(8)	(21)
Capital expenditures		116	257
Property, plant and equipment		8,754	8,786
Equity method investments		204	205
Total assets		11,427	11,308
Corporate Gas and Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue - external	[1]	33	13
Revenue - intersegment	[1]	(4)	(1)
Loss from assets held for sale	[1]	5
Depreciation and amortization	[1]		6
Operating income (loss)	[1]	15	6
Adjusted EBITDA	[1]	20	13
Interest expense, net of capitalization	[1]	6	1
Income tax expense (benefit)	[1]	16	8
Capital expenditures	[1]	1	1
Property, plant and equipment	[1]	7	7
Total assets	[1]	$ (1,425)	$ (1,048)
[1]	Includes Corporate, Gas and intersegment eliminations.

Segment information - Reconcili

Segment information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Segment Reporting [Abstract]
Consolidated Adjusted EBITDA	$ 611	$ 624
Loss from assets held for sale	5
Depreciation and amortization	203	197
Interest expense, net of capitalization	74	71
Income tax expense	72	103
Other expense	(21)	(16)
Earnings from equity method investments	2	2
Net Income	$ 238	$ 239

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Purchases From	$ (4)	$ (10)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Purchases From	(3)	(2)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Purchases From	(14)	(9)
Iberdrola Energia Monterrey, S.A. de C.V. [Member]
Related Party Transaction [Line Items]
Sales To	3	15
Other Related Parties [Member]
Related Party Transaction [Line Items]
Sales To	1	$ 1
Purchases From	$ (1)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Related Party Transaction [Line Items]
Deposit balance	$ 0	$ 0
Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Portion of amount receivable from related parties	1,000,000	2,000,000
Iberdrola Canada Energy Services [Member]
Related Party Transaction [Line Items]
Notes payable	31,000,000	29,000,000
Affiliated Entity [Member] | Impairment of non-current assets [Member]
Related Party Transaction [Line Items]
Impairments	$ 0
Iberdrola, S.A. [Member] | Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired	8.10%
Related party transaction, amount	$ 0	266,000,000
Network [Member] | New York Transco [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%
Portion of amount receivable from related parties	$ 6,000,000	$ 6,000,000

Related Party Transactions - 80

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Owed To	$ (31)	$ (31)
Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Owed By	1	2
Owed To	(47)	(51)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Owed By		1
Owed To	(14)	(32)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Owed To	(3)
Iberdrola Energia Monterrey, S.A. de C.V. [Member]
Related Party Transaction [Line Items]
Owed By		1
Other Related Parties [Member]
Related Party Transaction [Line Items]
Owed By	7	6
Owed To	$ (1)	$ (4)

Supplemental Balance Sheet In81

Supplemental Balance Sheet Information - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Dec. 31, 2017
Supplemental Balance Sheet Information [Line Items]
Prepaid other taxes	$ 151	$ 194
Deferred Payment Arrangements [Member]
Supplemental Balance Sheet Information [Line Items]
Accounts receivable	59	55
Allowance for doubtful accounts, deferred payment arrangement	31	30
Provision for doubtful accounts, accounts receivable	$ 1	$ 1

Supplemental Balance Sheet In82

Supplemental Balance Sheet Information - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Balance Sheet Related Disclosures [Abstract]
Accumulated depreciation	$ 7,767	$ 7,497
Accumulated amortization	$ 280	$ 276

Income Tax Expense - Additional

Income Tax Expense - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2018
Income Taxes [Line Items]
Effective income tax rate before elimination of unfunded future income tax	23.20%	30.10%
Statutory federal income tax rate	35.00%	35.00%
Income tax expense due to unfunded future income tax		$ 14
Scenario, Plan [Member]
Income Taxes [Line Items]
Statutory federal income tax rate			21.00%

Stock-Based Compensation Expe84

Stock-Based Compensation Expense - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Mar. 31, 2018$ / sharesshares	Mar. 31, 2018USD ($)Installment	Mar. 31, 2017USD ($)	Dec. 31, 2017USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation (credit) expense		$ (0.1)	$ 1.3
Stock-based compensation other current liabilities				$ 5.5
Iberdrola [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employee related remaining liabilities settlement date		2018-03
Performance Shares Units [Member] | Officers and Employees [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of PSUs granted | shares	21,532
Number of installment payments of employee related payables | Installment		3
Share-based payment award options grant date fair value, per share | $ / shares	$ 31.80
Share-based Compensation Award, Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance stock units vested amount installment payment year		2,020
Share-based Compensation Award, Tranche Two
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance stock units vested amount installment payment year		2,021
Share-based Compensation Award, Tranche Three
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance stock units vested amount installment payment year		2,022

Variable Interest Entities - Ad

Variable Interest Entities - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Mar. 31, 2018	Mar. 31, 2017
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)	$ 1,441,000,000	$ 1,432,000,000
Liabilities of variable interest entities (VIEs)	185,000,000	91,000,000
Equity method investments of variable interest entities (VIEs)	352,000,000	348,000,000	$ 352,000,000
Upfront cash payments	0
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Equity method investments of variable interest entities (VIEs)	$ 107,000,000	$ 106,000,000

Restructuring Expenses - Additi

Restructuring Expenses - Additional Information (Detail) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Restructuring And Related Cost [Line Items]
Severance agreement description	The remaining costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods through December 2018.
Operations and Maintenance [Member]
Restructuring And Related Cost [Line Items]
Severance expenses	$ 1.2

Restructuring Expenses - Summar

Restructuring Expenses - Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities (Details) $ in Millions	3 Months Ended
	Mar. 31, 2018USD ($)
Restructuring And Related Activities [Abstract]
Beginning Balance	$ 5
Restructuring and severance related expenses	1
Ending Balance	$ 6

Assets Held for Sale - Addition

Assets Held for Sale - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2018	Mar. 31, 2017	May 01, 2018	Mar. 01, 2018
Assets Held For Sale Not Discontinued Operations [Line Items]
Loss on assets held for sale	$ 5
(Loss)/income before income tax, adjusted to corporate overhead	$ 310	$ 342
Enstor Energy Services, LLC [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Disposal date	Mar. 1, 2018
Enstor Gas, LLC [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Disposal date	May 1, 2018
Gas Trading and Storage Businesses [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Loss on assets held for sale	$ 5.3
(Loss)/income before income tax, adjusted to corporate overhead	18.3	$ 2.6
Gas Trading Business [Member] | Enstor Energy Services, LLC [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale, consideration receivable				$ 66
Gas Storage Business [Member] | Enstor Gas, LLC [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Change in estimated fair value of assets held for sale	$ 9
Gas Storage Business [Member] | Enstor Gas, LLC [Member] | Subsequent Event [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale, consideration receivable			$ 66

Assets Held for Sale - Summary

Assets Held for Sale - Summary of Current Assets and Current Liabilities Held for Sale (Detail) - USD ($) $ in Millions	Mar. 31, 2018	Dec. 31, 2017
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale	$ 79	$ 357
Liabilities held for sale	7	137
Assets Held for Sale, Not Discontinued Operations [Member] | Gas Trading and Storage Businesses [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Accounts receivable, net	1	137
Derivative assets		25
Fuel and gas in storage	1	77
Prepayments and other current assets	6	19
Property, plant and equipment	71	71
Intangible assets		28
Assets held for sale	79	357
Accounts payable and accrued liabilities	2	107
Derivative liabilities		14
Other liabilities	5	16
Liabilities held for sale	$ 7	$ 137

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	May 02, 2018	Apr. 25, 2018	May 31, 2017	Mar. 31, 2018	Mar. 31, 2017	Dec. 31, 2016	May 01, 2018	Dec. 31, 2017
Subsequent Event [Line Items]
Cash Dividends Declared Per Common Share				$ 0.432	$ 0.432
Repurchase of common stock, shares			64,019			115,831
Repurchases of common stock				$ 8				$ 8
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividend declared date		Apr. 25, 2018
Cash Dividends Declared Per Common Share		$ 0.432
Dividend payment date		Jul. 2, 2018
Dividend record date		Jun. 8, 2018
Repurchase of common stock, shares	81,208
Repurchases of common stock							$ 4