Avangrid (AGR) 10-Q 5 May 17 2017 Q1 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	3 Months Ended
	Mar. 31, 2017	May 03, 2017
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Mar. 31, 2017
Document Fiscal Year Focus	2,017
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		309,069,291

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Statement [Abstract]
Operating Revenues	$ 1,758	$ 1,670
Operating Expenses
Purchased power, natural gas and fuel used	465	428
Operations and maintenance	551	551
Depreciation and amortization	197	205
Taxes other than income taxes	147	137
Total Operating Expenses	1,360	1,321
Operating Income	398	349
Other Income and (Expense)
Other income	13	49
Earnings from equity method investments	2	2
Interest expense, net of capitalization	(71)	(84)
Income Before Income Tax	342	316
Income tax expense	103	104
Net Income	239	212
Net Income Attributable to Avangrid, Inc.	$ 239	$ 212
Earnings Per Common Share, Basic	$ 0.77	$ 0.69
Earnings Per Common Share, Diluted	$ 0.77	$ 0.69
Weighted-average Number of Common Shares Outstanding:
Basic	309,508,889	309,538,215
Diluted	309,837,442	309,808,006
Cash Dividends Declared Per Common Share	$ 0.432	$ 0.432

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Statement Of Income And Comprehensive Income [Abstract]
Net Income		$ 239	$ 212
Other Comprehensive Income, Net of Tax Amounts arising during the period:
Gain on defined benefit plans, net of income tax			4
Unrealized gain during the period on derivatives qualifying as cash flow hedges, net of income taxes		2	2
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes	[1]	23	(26)
Other Comprehensive Income (Loss)		25	(20)
Comprehensive Income		264	192
Comprehensive Income Attributable to Avangrid, Inc.		$ 264	$ 192
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement Of Income And Comprehensive Income [Abstract]
Gain on defined benefit plans, income tax expense (benefit)		$ 2.8
Unrealized gain during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	$ 1.3	1.2
Reclassification to net income of losses (gains) on cash flow hedges, income tax expense	$ 13.6	$ (16.6)

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 30	$ 91
Accounts receivable and unbilled revenues, net	1,117	1,119
Accounts receivable from affiliates	17	25
Derivative assets	57	99
Fuel and gas in storage	235	246
Materials and supplies	113	132
Prepayments and other current assets	281	255
Regulatory assets	248	285
Total Current Assets	2,098	2,252
Property, plant and equipment, at cost	27,320	27,063
Less: accumulated depreciation	(7,158)	(6,986)
Net Property, Plant and Equipment in Service	20,162	20,077
Construction work in progress	1,635	1,471
Total Property, Plant and Equipment ($1,101 and $1,144 related to VIEs, respectively)	21,797	21,548
Equity method investments	384	387
Other investments	57	55
Regulatory assets	3,111	3,091
Other Assets
Goodwill	3,124	3,124
Intangible assets	534	538
Derivative assets	76	73
Other	215	241
Total Other Assets	3,949	3,976
Total Assets	31,396	31,309
Current Liabilities
Current portion of debt	325	349
Tax equity financing arrangements - VIEs	81	96
Notes payable	350	151
Notes payable to affiliates	17	10
Interest accrued	65	60
Accounts payable and accrued liabilities	902	1,096
Accounts payable to affiliates	120	218
Dividends payable	134	134
Taxes accrued	61	52
Derivative liabilities	50	75
Other current liabilities	283	279
Regulatory liabilities	200	192
Total Current Liabilities	2,588	2,712
Regulatory liabilities	1,755	1,753
Deferred income taxes regulatory	574	565
Other Non-current Liabilities
Deferred income taxes	3,068	2,976
Deferred income	1,464	1,483
Pension and other postretirement	1,106	1,106
Tax equity financing arrangements - VIEs	95	103
Derivative liabilities	80	78
Asset retirement obligations	167	161
Environmental remediation costs	386	398
Other	354	342
Total Other Non-current Liabilities	6,720	6,647
Non-current Debt	4,507	4,510
Total Non-current Liabilities	13,556	13,475
Total Liabilities	16,144	16,187
Commitments and Contingencies
Stockholders’ Equity:
Common stock	3	3
Additional paid in capital	13,653	13,653
Treasury Stock	(5)	(5)
Retained earnings	1,649	1,544
Accumulated other comprehensive loss	(61)	(86)
Total Stockholders’ Equity	15,239	15,109
Non-controlling interests	13	13
Total Equity	15,252	15,122
Total Liabilities and Equity	$ 31,396	$ 31,309

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment, VIEs	$ 21,797	$ 21,548
Common stock, par value	$ 0.01	$ 0.01
Common stock, authorized	500,000,000	500,000,000
Common stock, issued	309,670,932	309,600,439
Common stock, outstanding	309,069,291	308,993,149
Variable Interest Entity, Primary Beneficiary [Member]
Property, Plant and Equipment, VIEs	$ 1,101	$ 1,144

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Cash Flow from Operating Activities:
Net Income	$ 239	$ 212
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	197	205
Accretion expenses	3	3
Regulatory assets/liabilities amortization	19	41
Regulatory assets/liabilities carrying cost	10	10
Pension cost	28	33
Stock-based compensation	1	1
Earnings from equity method investments	(2)	(2)
Amortization of debt cost (premium)	2	(7)
Gain on disposal of property and equity method investment		(31)
Unrealized (gain) loss on marked-to-market derivative contracts	(27)	29
Deferred taxes	95	106
Other non-cash items	(22)	(3)
Changes in operating assets and liabilities:
Accounts receivable and unbilled revenues	11	16
Inventories	11	75
Other assets/liabilities	64	(129)
Cash distribution from equity method investments	3	3
Accounts payable and accrued liabilities	(155)	(108)
Taxes accrued	9	9
Regulatory assets/liabilities	(45)	(67)
Net Cash Provided by Operating Activities	441	396
Cash Flow from Investing Activities:
Capital expenditures	(525)	(276)
Contributions in aid of construction	6	8
Government grants		1
Proceeds from sale of property, plant and equipment	1
Proceeds from sale of equity method and other investment		54
Receipts from affiliates		6
Cash distribution from equity method investments	2	2
Other investments and equity method investments, net	2	4
Net Cash Used in Investing Activities	(514)	(201)
Cash Flow from Financing Activities:
Repayments of non-current debt	(4)	(42)
Receipts (repayments) of other short-term debt, net	205	(160)
Payments on tax equity financing arrangements	(27)	(17)
Repayments of capital leases	(27)	(1)
Issuance of common stock	(1)
Dividends paid	(134)
Net Cash Provided by (Used in) Financing Activities	12	(220)
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(61)	(25)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	96	434	$ 434
Cash, Cash Equivalents and Restricted Cash, End of Period	35	409	$ 96
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	45	57
Cash paid for income taxes	$ 3	$ 5

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Changes in Equity - 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, 2015		$ 15,066	$ 3		$ 13,653		$ 1,449	$ (52)	$ 15,053	$ 13
Balance, shares at Dec. 31, 2015	[1]		308,864,609
Net Income		212					212		212
Other comprehensive income (loss), net of tax		(20)						(20)	(20)
Comprehensive Income Attributable to Avangrid, Inc.		192
Dividends declared		$ (134)					(134)		(134)
Release of common stock held in trust		132,800	132,800	[1]
Issuance of common stock, shares		97,479	97,479	[1]
Balance at Mar. 31, 2016		$ 15,124	$ 3		13,653		1,527	(72)	15,111	13
Balance, shares at Mar. 31, 2016	[1]		309,094,888
Balance at Dec. 31, 2016		$ 15,122	$ 3		13,653	$ (5)	1,544	(86)	15,109	13
Balance, shares at Dec. 31, 2016		308,993,149	308,993,149	[1]
Net Income		$ 239					239		239
Other comprehensive income (loss), net of tax		25						25	25
Comprehensive Income Attributable to Avangrid, Inc.		264
Dividends declared		$ (134)					(134)		(134)
Release of common stock held in trust		5,649	5,649	[1]
Issuance of common stock		$ (1)			(1)				(1)
Issuance of common stock, shares		70,493	70,493	[1]
Stock-based compensation		$ 1			1				1
Balance at Mar. 31, 2017		$ 15,252	$ 3		$ 13,653	$ (5)	$ 1,649	$ (61)	$ 15,239	$ 13
Balance, shares at Mar. 31, 2017		309,069,291	309,069,291	[1]
[1]	Par value of share amounts is $0.01

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Statement Of Stockholders Equity [Abstract]
Common Stock, Par or Value Per Share	$ 0.01
Other Comprehensive Income (Loss) Taxes	$ 14.9	$ (12.6)

Background and Nature of Operat

Background and Nature of Operations	3 Months Ended
	Mar. 31, 2017
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 and trading 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 81.6% the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was originally organized in 1997 as NGE Resources, Inc. under the laws of New York as the holding company for the principal operating utility companies.

Basis of Presentation

Basis of Presentation	3 Months Ended
	Mar. 31, 2017
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, 2016 and 2015 and for the three years ended December 31, 2016 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016. 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, 2017, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2017.

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
Significant Accounting Policies and New Accounting Pronouncements	Note 3. Significant Accounting Policies and New Accounting Pronouncements As of March 31, 2017, there have been no material changes to any significant accounting policies described in our consolidated financial statements as of December 31, 2016 and 2015, and for the three years ended December 31, 2016. The following are new accounting pronouncements issued since December 31, 2016, that we are evaluating to determine their effect on our condensed consolidated interim financial statements. (a) Clarifying the definition of a business and the scope of asset derecognition guidance, and accounting for partial sales of nonfinancial assets The Financial Accounting Standards Board (FASB) The amendments issued in February 2017 clarify the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets, and also define in-substance nonfinancial assets. Those amendments apply to a company that: sells nonfinancial assets (land, buildings, materials and supplies, intangible assets) to noncustomers; sells nonfinancial assets and financial assets (cash, receivables) when the value is concentrated in the nonfinancial assets; or sells partial ownership interests in nonfinancial assets. The amendments do not apply to sales to customers or to sales of businesses. The new guidance in ASC 610-20 on accounting for derecognition of a nonfinancial asset and an in-substance nonfinancial asset applies only when the asset (or asset group) does not meet the definition of a business and is not a not-for-profit activity. The amendments issued in both January 2017 and February 2017 as described above are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We do not plan to early adopt. For the amendments concerning the definition of a business, an entity should apply the amendments prospectively on or after the effective date. For the amendments concerning asset derecognition and partial sales of nonfinancial assets an entity must apply them at the same time that it applies the new ASC 606 revenue recognition standard and may elect to apply the amendments retrospectively following either a full retrospective approach or a modified retrospective approach, but does not have to apply the same transition method as for ASC 606. Regardless of which transition method an entity applies to contracts with noncustomers, such as transactions within the scope of ASC 610-20, it must apply the amended definition of a business to those contracts. We expect the amendments issued in both January 2017 and February 2017 will affect our accounting for tax equity investments, which we expect to classify as noncontrolling interests in accordance with ASC 606. We are currently evaluating how our adoption of the amendments will affect our results of operations, financial position, cash flows, and disclosures. (b) 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. The amendments require an entity to present service cost separately from the other components of net benefit cost, and to report the service cost component in the income statement line item(s) where it reports the corresponding compensation cost. An entity is to present all other components of net benefit cost outside of operating cost, if it presents that subtotal. The amendments also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of a self-constructed asset). The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We do not plan to early adopt. An entity is required to apply the amendments retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets. A practical expedient allows an entity to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in the notes to financial statements for pension and postretirement benefit plans for those periods. We are currently evaluating how our adoption of the amendments will affect our results of operations, financial position, cash flows, and disclosures.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	3 Months Ended
	Mar. 31, 2017
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Note 4. 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. Substantially all assets or liabilities for which funds have been expended or received are either included in the rate base or are accruing a carrying cost until they will be included in the rate base. 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 , 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 (Proposal) in connection with a three-year rate plan for electric and gas service at New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E) effective May 1, 2016. Following the approval of the 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, remains deferred and will not be amortized until future proceedings or will be used to recover costs of the Ginna Reliability Support Services Agreement (Ginna RSSA). In the approved Proposal the allowed rate of return on common equity is 9.0% for all companies. The equity ratio for each company is 48%; however the equity ratio is set at 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% ROE, respectively, in the first year. The rate plans also include the implementation of a rate adjustment mechanism designed to return or collect certain defined reconciled revenues and costs; new depreciation rates; and continuation of the existing revenue decoupling mechanisms for each business. In December 2016, PURA approved new distribution rate schedules for UI for three years which became effective January 1, 2017 and which, among other things, decreased the UI distribution and Competitive Transition Assessment (CTA) allowed ROE from 9.15% to 9.10%, continued UI’s existing earnings sharing mechanism by which UI and 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. Current and non-current regulatory assets as of March 31, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 23 $ 22 Pension and other post-retirement benefits 7 7 Storm costs 40 40 Temporary supplemental assessment surcharge 3 4 Reliability support services 27 27 Revenue decoupling mechanism 13 15 Transmission revenue reconciliation mechanism 14 12 Electric supply reconciliation — 13 Hedges losses 12 10 Contracts for differences 12 14 Hardship programs 16 16 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 1 14 Deferred transmission expense 15 13 Environmental remediation costs 13 14 Other 36 48 Total Current Regulatory Assets 248 285 Non-current Pension and other post-retirement benefits cost deferrals 129 134 Pension and other post-retirement benefits 1,285 1,320 Storm costs 232 187 Deferred meter replacement costs 31 32 Unamortized losses on reacquired debt 19 20 Environmental remediation costs 285 287 Unfunded future income taxes 536 542 Asset retirement obligation 16 18 Deferred property tax 29 33 Federal tax depreciation normalization adjustment 160 161 Merger capital expense target customer credit 11 11 Debt premium 146 151 Reliability support services 49 2 Plant decommissioning 14 14 Contracts for differences 68 61 Hardship programs 14 18 Other 87 100 Total Non-current Regulatory Assets $ 3,111 $ 3,091 “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. The portion of storm costs in the amount of $123 million is being recovered over ten-year period and the remaining portion is being amortized over five years following the approval of the 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, 2017. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “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 Proposal by the NYPSC, these amounts will be collected over a period of fifty years, and the NYPSC Staff will perform an audit 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 New York (NY) amount is being amortized over a five year period following the approval of the 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 NY 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” 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 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. Current and non-current regulatory liabilities as of March 31, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Current Reliability support services (Cayuga) $ 1 $ 3 Non by-passable charges 9 22 Energy efficiency portfolio standard 47 45 Gas supply charge and deferred natural gas cost 14 6 Transmission revenue reconciliation mechanism 9 5 Pension and other post-retirement benefits 1 3 Other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 15 15 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE Refund 22 24 Merger related rate credits 2 3 Revenue decoupling mechanism 3 9 Other 58 38 Total Current Regulatory Liabilities 200 192 Non-current Accrued removal obligations 1,126 1,117 Asset sale gain account 9 9 Carrying costs on deferred income tax bonus depreciation 91 95 Economic development 34 35 Merger capital expense target customer credit account 14 15 Pension and other post-retirement benefits 72 76 Positive benefit adjustment 41 42 New York state tax rate change 8 9 Post term amortization 3 3 Theoretical reserve flow thru impact 23 24 Deferred property tax 18 19 Net plant reconciliation 10 10 Variable rate debt 28 28 Carrying costs on deferred income tax - Mixed Services 263(a) 24 25 Rate refund – FERC ROE proceeding 26 26 Transmission congestion contracts 18 18 Merger-related rate credits 20 21 Accumulated deferred investment tax credits 14 15 Asset retirement obligation 11 13 Earning sharing provisions 22 12 Middletown/Norwalk local transmission network service collections 19 19 Low income programs 48 46 Non-firm margin sharing credits 10 7 Deferred income taxes regulatory 574 565 Other 66 69 Total Non-current Regulatory Liabilities $ 2,329 $ 2,318 “Reliability support services (Cayuga)” represents the difference between actual expenses for reliability support services and the amount provided for in rates. This will be refunded to customers within the next year. “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. 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 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 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 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 Energy East by Iberdrola. The amortization period is five years following the approval of the 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 Energy East. This is being used to moderate increases in rates. The amortization period is five years following the approval of the 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 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 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 Proposal by the NYPSC. “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, 2017 and 2016, respectively, $2 million and $20 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, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Note 5. 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). RG&E hedges 70% of its electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value RG&E’s 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’s electric energy derivative contracts are exchange traded contracts in a NYISO location where an active market exists. The forward market prices used to value NYSEG’s 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. • Contracts for differences (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 6 for further discussion on 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, 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, 2017, and December 31, 2016, which is included in “Other Assets” on the balance sheet. The financial instruments measured at fair value as of March 31, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 40 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 7 66 70 (57 ) 86 Derivative financial instruments - gas 90 16 89 (165 ) 30 Contracts for differences — — 17 — 17 Total 97 82 176 (222 ) 133 Derivative liabilities Derivative financial instruments - power (27 ) (26 ) (5 ) 53 (5 ) Derivative financial instruments - gas (94 ) (18 ) (39 ) 125 (26 ) Contracts for differences — — (98 ) — (98 ) Derivative financial instruments - other — — (1 ) — (1 ) Total $ (121 ) $ (44 ) $ (143 ) $ 178 $ (130 ) As of December 31, 2016 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 40 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 11 48 58 (42 ) 75 Derivative financial instruments - gas 180 32 104 (239 ) 77 Contracts for differences — — 20 — 20 Total 191 80 182 (281 ) 172 Derivative liabilities Derivative financial instruments - power (24 ) (27 ) (3 ) 39 (15 ) Derivative financial instruments - gas (213 ) (34 ) (53 ) 257 (43 ) Contracts for differences — — (95 ) — (95 ) Total $ (237 ) $ (61 ) $ (151 ) $ 296 $ (153 ) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2017 and 2016, respectively, is as follows: Three Months Ended March 31, (Millions) 2017 2016 Fair Value Beginning of Period, $ 31 $ (19 ) Gains recognized in operating revenues 12 9 (Losses) recognized in operating revenues (2 ) (6 ) Total gains recognized in operating revenues 10 3 Gains recognized in OCI 1 1 (Losses) recognized in OCI (1 ) — Total gains recognized in OCI — 1 Net change recognized in regulatory assets and liabilities (5 ) (25 ) Purchases 3 — Settlements (6 ) (5 ) Fair Value as of March 31, $ 33 $ (45 ) 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 $ 10 $ 3 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, Level 2 and Level 3 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, 2017 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 $ 4.15 $ 7.37 $ 1.64 with delivery exceeding two on a corroborated by SP15 $ 42.70 $80.28 $14.25 period > two years discounted market data for Mid C $ 34.04 $83.93 $ (0.50) years basis identical or Cinergy $ 35.91 $77.49 $18.53 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 6 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that 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, 2017 Risk of non-performance 0.58% - 0.66% Discount rate 1.50% - 2.40% Forward pricing ($ per MW) $3.15 - $9.55 Fair Value of Debt As of March 31, 2017 and December 31, 2016 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 $5,243 million and $5,204 million as of March 31, 2017 and December 31, 2016, 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, 2017 and December 31, 2016, 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, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Note 6. 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 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 $20.1 million as of March 31, 2017, and $12.3 million as of December 31, 2016. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a loss of $10.9 million and $34.8 million, for the three months ended March 31, 2017 and 2016, respectively. NYSEG and RG&E 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 liabilities for natural gas hedges was a gain of $0.5 million as of March 31, 2017, and $3.5 million as of December 31, 2016. The amount reclassified from regulatory assets and liabilities into income, which is included in natural gas purchased, was a gain of $0.6 million and a loss $3.4 million, for the three months ended March 31, 2017 and 2016, respectively. Pursuant to PURA, 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). 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, 2017, UI has recorded a gross derivative asset of $17 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $81 million, a gross derivative liability of $98 million ($76 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, 2016, UI had recorded a gross derivative asset of $19 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $75 million, a gross derivative liability of $95 million ($70 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, 2017 and 2016, respectively, were as follows: Three Months Ended March 31, 2017 2016 (Millions) Regulatory Assets - Derivative liabilities $ 5 $ (3 ) Regulatory Liabilities - Derivative assets $ 1 $ (22 ) The net notional volumes of the outstanding derivative instruments associated with Networks activities as of March 31, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Wholesale electricity purchase contracts (MWh) 5.0 5.6 Natural gas purchase contracts (Dth) 6.0 5.8 Fleet fuel purchase contracts (Gallons) 2.3 2.3 The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Networks activities as of March 31, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 16 $ 10 $ 6 $ 1 Derivative liabilities (5 ) (1 ) (39 ) (86 ) 11 9 (33 ) (85 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1 ) — — — (1 ) — Total derivatives before offset of cash collateral 11 9 (34 ) (85 ) Cash collateral receivable — — 12 8 Total derivatives as presented in the balance sheet $ 11 $ 9 $ (22 ) $ (77 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 16 $ 7 $ 5 Derivative liabilities (7 ) (5 ) (40 ) (79 ) 12 11 (33 ) (74 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 12 11 (33 ) (74 ) Cash collateral receivable — — 10 2 Total derivatives as presented in the balance sheet $ 12 $ 11 $ (23 ) $ (72 ) The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2017 and 2016, 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) 2017 Interest rate contracts $ — Interest expense $ 2 Commodity contracts (1 ) Operating expenses — Total $ (1 ) $ 2 2016 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses 1 Total $ — $ 3 (a) The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $74.9 million and $76.7 million as of March 31, 2017 and December 31, 2016, 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, 2017 and 2016, respectively. We will amortize approximately $8.0 million of discontinued cash flow hedges in 2017. During the three months ended March 31, 2017 and 2016, there was no ineffective portion for cash flow hedges. The unrealized loss of $0.8 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable as of March 31, 2017. We expect that $0.8 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 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 AECO 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, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (MWh/Dth in millions) Wholesale electricity purchase contracts 2 3 Wholesale electricity sales contracts 7 7 Natural gas and other fuel purchase contracts 314 329 Financial power contracts 8 8 Basis swaps – purchases 60 49 Basis swaps – sales 76 45 The fair values of derivative contracts associated with Renewables and Gas activities as of March 31, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Wholesale electricity purchase contracts $ (10 ) $ (2 ) Wholesale electricity sales contracts 25 6 Natural gas and other fuel purchase contracts 6 30 Financial power contracts 64 56 Basis swaps – purchases (8 ) 3 Basis swaps – sales 5 (2 ) Total $ 82 $ 91 The effect of trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2017 and 2016, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Wholesale electricity purchase contracts $ (3 ) $ — Wholesale electricity sales contracts 7 (1 ) Financial power contracts (3 ) 1 Financial and natural gas contracts 4 (30 ) Total Gain (Loss) $ 5 $ (30 ) The effect of non-trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2017 and 2016, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Wholesale electricity purchase contracts $ (6 ) $ (3 ) Wholesale electricity sales contracts 11 6 Financial power contracts 16 1 Financial and natural gas contracts (4 ) (9 ) Total Gain (Loss) $ 17 $ (5 ) 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, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 79 $ 117 $ 100 $ 6 Derivative liabilities (30 ) (7 ) (115 ) (10 ) 49 110 (15 ) (4 ) Designated as hedging instruments Derivative assets 16 8 — 1 Derivative liabilities — (2 ) (15 ) (1 ) 16 6 (15 ) — Total derivatives before offset of cash collateral 65 116 (30 ) (4 ) Cash collateral receivable (payable) (19 ) (49 ) 2 1 Total derivatives as presented in the balance sheet $ 46 $ 67 $ (28 ) $ (3 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 198 $ 108 $ 78 $ 7 Derivative liabilities (118 ) (4 ) (132 ) (16 ) 80 104 (54 ) (9 ) Designated as hedging instruments Derivative assets 25 4 — — Derivative liabilities (1 ) — (39 ) (21 ) 24 4 (39 ) (21 ) Total derivatives before offset of cash collateral 104 108 (93 ) (30 ) Cash collateral receivable (payable) (17 ) (46 ) 41 24 Total derivatives as presented in the balance sheet $ 87 $ 62 $ (52 ) $ (6 ) The effect of derivatives in cash flow hedging relationships on OCI and income for the three months ended March 31, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, Gain Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2017 Commodity contracts $ 4 Revenues $ 33 Total $ 4 $ 33 2016 Commodity contracts $ 3 Revenues $ (46 ) Total $ 3 $ (46 ) (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 $0.5 million of gain included in accumulated OCI at March 31, 2017, is expected to be reclassified into earnings within the next 12 months. During the three months ended March 31, 2017 and 2016, we recorded a net loss of $0.3 million and $4.4 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, 2017. This amount 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, 2017, UI would have had to post an aggregate of approximately $11 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 $23 million and $20 million as of March 31, 2017 and December 31, 2016, 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, 2017 is $20.1 million, for which we have posted collateral.

Contingencies

Contingencies	3 Months Ended
	Mar. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Contingencies	Note 7. 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. 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 and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and therefore are 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) issued its decision. The Court vacated FERC’s decision on Complaint I and remanded it to FERC. The Court found 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 must first determine 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 10.57%, the point ROE at the midpoint of the upper end of the zone of reasonableness, is a just and reasonable ROE as FERC only explained in its order that the midpoint of 9.39% was not just and reasonable and a higher base ROE was warranted. The parties or FERC could appeal the decision to the United States Supreme Court or FERC could provide additional justification and issue a decision on remand. We cannot predict the outcome of an appeal or other action by FERC . On December 26, 2012, a second ROE complaint (Complaint II) for a subsequent rate period was filed requesting the ROE 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 ROE 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 were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge, relating to the refund periods and going forward period. 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 later in 2017, once FERC has enough commissioners to provide a quorum for decision-making. 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. The CMP and UI total reserve associated with Complaints II and III is $21.9 million and $4.4 million, respectively, as of March 31, 2017, which has not changed since December 31, 2016, 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 base ROE be 8.61% and ROE Cap be 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. On February 1, 2017, the complainants filed their initial testimony recommending a base ROE of 8.59%. On March 23, 2017, the NETOs filed their answering testimony supporting the continuation of the base ROE from Complaint I of 10.57%. A range of possible outcomes is not able to be determined at this time due to the preliminary state of this matter. We cannot predict the outcome of the Complaint IV proceeding. Hearings are being held later this year with an expected Initial Decision from the Administrative Law Judge in November 2017. Yankee Nuclear Spent Fuel Disposal Claim CMP has an ownership interest in Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company, and Yankee Atomic Electric Company (the Yankee Companies), three New England single-unit decommissioned nuclear reactor sites, and UI has an ownership interest in Connecticut Yankee Atomic Power Company. Every six years, pursuant to the statute of limitations, the Yankee Companies file a lawsuit to recover damages from the Department of Energy (DOE or Government) for breach of the Nuclear Spent Fuel Disposal Contract to remove Spent Nuclear Fuel (SNF) and Greater than Class C Waste (GTCC) as required by contract and the Nuclear Waste Policy Act beginning in 1998. The damages are the incremental costs for the Government’s failure to take the spent nuclear fuel. In 2012, the U.S. Court of Appeals issued a favorable decision in the Yankee Companies’ claim for the first six year period (Phase I). Total damages awarded to the Yankee Companies were nearly $160 million. The Yankee Companies won on all appellate points in the U.S. Court of Appeals for the Federal Circuit’s unanimous decision. The Federal Appeals Court affirmed the September 2010 U.S. Court of Federal Claims award of $39.7 million to Connecticut Yankee Atomic Power Company; affirmed the Court of Federal Claims award of $81.7 million to Maine Yankee Atomic Power Company; and increased Yankee Atomic Electric Company’s damages award from $21.4 million to $38.3 million. The Phase I damage award became final on December 4, 2012. The Yankee Companies received payment from DOE in January 2013. CMP’s share of the award was approximately $36.5 million which was credited back to customers. UI’s share of the award was $3.8 million which was credited back to customers. In November 2013 the U.S. Court of Claims issued its decision in the Phase II case (the second six-year period). The court’s decision awarded the Yankee Companies a combined $235.4 million (Connecticut Yankee $126.3 million, Maine Yankee $37.7 million, and Yankee Atomic $73.3 million). The Phase II period covers January 1, 2002, through December 31, 2008, for Connecticut Yankee and Yankee Atomic, and January 1, 2003, through December 31, 2008, for Maine Yankee. Maine Yankee’s damage award was lower because it recovered a larger amount in the Phase I case ($82 million) and its decommissioning was both less expensive and completed sooner than the other Yankee Companies. The damage awards flow through the Yankee Companies to shareholders (including CMP and UI) to reduce retail customer charges. In January 2014 the government informed the Yankee Companies that it would not appeal the Trial Court decision, as a result the Yankee Companies received full payment in April 2014. CMP’s share of the award was approximately $28.2 million which was credited back to customers. UI received approximately $12 million of such award which was applied, in part, against its remaining storm regulatory asset balance. The remaining regulatory liability balance was applied to UI’s generation service charge “working capital allowance” and was returned to customers through the non-by-passable federally mandated congestion charge. In August 2013, the Yankee Companies filed a third round of claims against the Government seeking damages for the years 2009-2014 (Phase III). The Phase III trial was completed in July 2015 and the court issued its decision on March 25, 2016, awarding the Yankee Companies a combined $76.8 million (Connecticut Yankee $32.6 million, Maine Yankee $24.6 million and Yankee Atomic $19.6 million). The damage awards will potentially flow through the Yankee Companies to shareholders, including CMP and UI, upon FERC approval, and will reduce retail customer charges or otherwise as specified by law. CMP and UI will receive their proportionate share of the awards that flow through based on percentage ownership. On July 18, 2016, the notice of appeal period expired and the Phase III trial award became final. On October 14, 2016, the Yankee Companies received the Government's payment of the damage award of a combined $41.6 million (Connecticut Yankee $18.4 million, Maine Yankee $3.6 million and Yankee Atomic $19.6 million). In December 2016 CMP and UI received their proportionate share of $4.2 million of the Phase III damage awards, based on percentage ownership, and CMP received an additional $21.5 million for SNF trust refund relating to excess funds of Maine Yankee unrelated to Phase III. All amounts will flow through to customers. NYPSC Staff Review of Earnings Sharing Calculations and Other Regulatory Deferrals In December 2012, the NYPSC Staff (Staff) informed NYSEG and RG&E that the Staff had conducted an audit of the companies’ annual compliance filings (ACF) for 2009 through August 31, 2010, and the first rate year of the current rate plan, September 1, 2010 through August 31, 2011. The Staff’s preliminary findings indicated adjustments to deferred balances primarily associated with storm costs and the treatment of certain incentive compensation costs for purposes of the 2011 ACF. The Staff’s findings included approximately $9.8 million of adjustments to deferral balances and customer earnings sharing accruals. NYSEG and RG&E reviewed the Staff’s adjustments and work papers and responded in early 2013. NYSEG and RG&E disagreed with certain Staff conclusions and as a result recorded a $3.4 million reserve in December 2012 in anticipation of settling the issues identified by the Staff. In the Proposal approved by the NYPSC (see Note 4) the parties agreed that in full and final resolution of all issues identified for all years through 2012, and in full and final resolution of storm-related deferrals through 2014, the companies will add $2.4 million to the customer share of earnings sharing. The Staff indicated in December 2016 that it had completed its review of 2013 and 2014 ACFs and no additional issues were identified. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm At the direction of Governor Andrew Cuomo, 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 will include a comprehensive review of NYSEG’s and RG&E’s preparation for and response to the windstorm, including the all aspects of the companies’ filed and approved emergency plan. The Department held public hearings on April 12 and 13, 2017. We cannot predict the outcome of this investigation. 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. Guarantee Commitments to Third Parties As of March 31, 2017, we had approximately $2.7 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, 2017, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liabilities

Environmental Liabilities	3 Months Ended
	Mar. 31, 2017
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Note 8. 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 $6 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 $22 million as of March 31, 2017. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the portion of remediation attributed to us. 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; eleven 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 $221 million to $465 million as of March 31, 2017. 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. As of both March 31, 2017 and December 31, 2016, the liability associated with 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 $97 million. The liability to investigate and perform remediation at the known inactive MGP sites was $384 million and $388 million as of March 31, 2017 and December 31, 2016, 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 2053. Certain other 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, 2017 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. 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 MPG sites. In January 2015, NYSEG sent FirstEnergy a demand for $16 million representing FirstEnergy’s share of clean-up expenses incurred by NYSEG at the nine sites from January 2010 to November 2014 while the District Court appeal was pending. Nearly all of this amount has been paid by FirstEnergy. FirstEnergy would also be liable for a share of post 2014 costs, which, based on current projections, would be $26 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 One Beacon 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 and is researching grounds for further appeal if the reconsideration motion is denied. We cannot predict the outcome of this matter; however, any recovery will be flowed through to NYSEG ratepayers. 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 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 and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the property; (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 on or before August 1, 2017. 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. A status report was filed with the court in December 2016 and the next status report is due in May 2017. On August 4, 2016, DEEP issued 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. In connection with the consent order, on August 4, 2016, DEEP also issued a Consent Order to Evergreen Power, Asnat, and certain related parties that provides UI access to investigate and remediate the English Station site consistent with the consent order. 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, 2016, we reserved $30 million for this case. As of March 31, 2017, 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, 2017
Compensation And Retirement Disclosure [Abstract]
Post-retirement and Similar Obligations	Note 9. Post-retirement and Similar Obligations We made no pension contributions for the three months ended March 31, 2017. We expect to make $33 million of contributions for the remainder of 2017. The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Service cost $ 11 $ 11 Interest cost 35 35 Expected return on plan assets (50 ) (51 ) Amortization of: Prior service costs — — Actuarial loss 32 38 Net Periodic Benefit Cost $ 28 $ 33 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Service cost $ 1 $ 1 Interest cost 5 6 Expected return on plan assets (2 ) (3 ) Amortization of: Prior service costs (2 ) (2 ) Actuarial loss 1 2 Net Periodic Benefit Cost $ 3 $ 4

Equity

Equity	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Equity	Note 10. Equity As of March 31, 2017, our share capital consisted of 500,000,000 shares of common stock authorized, 309,670,932 shares issued and 309,069,291 shares outstanding, 81.6% 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 $13,653 million. As of December 31, 2016, our share capital consisted of 500,000,000 shares of common stock authorized, 309,600,439 shares issued and 308,993,149 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 and 491,459 shares of common stock held in trust and no convertible preferred shares outstanding as of March 31, 2017 and December 31, 2016, respectively. 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. During the three months ended March 31, 2016, we issued 97,479 shares of common stock and released 132,800 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. As of March 31, 2017, we have 115,831 shares of common stock of AVANGRID, which were repurchased during 2016 in the open market. The total cost of repurchase, including commissions, was $5 million. Accumulated Other Comprehensive Loss Accumulated OCI for the three months ended March 31, 2017 and 2016, respectively, consisted of: As of December 31, Three Months Ended March 31, As of March 31, As of December 31, Three Months Ended March 31, As of March 31, 2016 2017 2017 2015 2016 2016 (Millions) Gain on revaluation of defined benefit plans, net of income tax expense of $2.8 for 2016 $ (14 ) $ — $ (14 ) $ (21 ) $ 4 $ (17 ) Loss for nonqualified pension plans (7 ) — (7 ) (8 ) — (8 ) Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $1.3 for 2017 and $1.2 for 2016 5 2 7 31 2 33 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $13.6 for 2017 and $(16.6) for 2016(a) (70 ) 23 (47 ) (54 ) (26 ) (80 ) Gain (loss) on derivatives qualifying as cash flow hedges (65 ) 25 (40 ) (23 ) (24 ) (47 ) Accumulated Other Comprehensive Loss $ (86 ) $ 25 $ (61 ) $ (52 ) $ (20 ) $ (72 ) (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, 2017
Earnings Per Share [Abstract]
Net Income Per Share	Note 11. 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, 2017 and 2016, 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, 2017 and 2016. The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 239 $ 212 Denominator: Weighted average number of shares outstanding - basic 309,508,889 309,538,215 Weighted average number of shares outstanding - diluted 309,837,442 309,808,006 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.77 $ 0.69 Earnings Per Common Share, Diluted $ 0.77 $ 0.69

Segment Information

Segment Information	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Segment Information	Note 12. 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 three 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. • Gas: including gas trading and storage businesses carried on by the AVANGRID Group. 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 income tax expense, depreciation and amortization and interest expense net of capitalization, and then subtracting other income and (expense) and earnings from equity method investments per segment. Segment income, expense, and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the condensed consolidated financial statements. Segment information as of and for the three months ended March 31, 2017, consisted of: Three Months Ended March 31, 2017 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,460 $ 285 $ 14 $ (1 ) $ 1,758 Revenue - intersegment (1 ) 2 11 (12 ) — Depreciation and amortization 113 78 6 — 197 Operating income (loss) 336 56 7 (1 ) 398 Adjusted EBITDA 449 133 14 (1 ) 595 Earnings (losses) from equity method investments 4 (2 ) — — 2 Capital expenditures $ 267 $ 257 $ 1 $ — $ 525 As of March 31, 2017 Property, plant and equipment 13,168 8,133 496 — 21,797 Equity method investments 149 235 — — 384 Total assets $ 20,998 $ 9,996 $ 1,041 $ (639 ) $ 31,396 (a) Does not represent a segment. It mainly includes Corporate 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; $4 million from gas storage services and $10 million from gas trading operations of Gas. Segment information for the three months ended March 31, 2016, consisted of: Three Months Ended March 31, 2016 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,390 $ 276 $ 3 $ 1 $ 1,670 Revenue - intersegment — 2 9 (11 ) — Depreciation and amortization 118 80 7 — 205 Operating income (loss) 312 49 (10 ) (2 ) 349 Adjusted EBITDA 430 129 (3 ) (2 ) 554 Earnings (losses) from equity method investments 3 (1 ) — — 2 Capital expenditures $ 206 $ 70 $ — $ — $ 276 As of December 31, 2016 Property, plant and equipment 13,032 8,015 501 — 21,548 Equity method investments 151 236 — — 387 Total assets $ 20,753 $ 9,884 $ 1,124 $ (452 ) $ 31,309 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the three months ended March 31, 2016, are: $913 million from regulated electric operations, $477 million from regulated gas operations and no amounts from other operations of Networks; $276 million from renewable energy generation of Renewables; $7 million from gas storage services and $(4) million from gas trading operations of Gas. Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three months ended March 31, 2017 and 2016, respectively, is as follows: Three Months Ended March 31, 2017 2016 (Millions) Consolidated Adjusted EBITDA $ 595 $ 554 Less: Depreciation and amortization 197 205 Interest expense, net of capitalization 71 84 Income tax expense 103 104 Add: Other income 13 49 Earnings from equity method investments 2 2 Consolidated Net Income $ 239 $ 212

Related Party Transactions

Related Party Transactions	3 Months Ended
	Mar. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 13. 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, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (10 ) $ — $ (5 ) Iberdrola Renovables Energía, S.L. — (2 ) — (3 ) Iberdrola, S.A. — (9 ) — (8 ) Other 16 — 1 — In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which our ultimate parent, Iberdrola, has an 8.1% ownership. The amounts capitalized for these transactions were $66 million and $269 million as of March 31, 2017 and December 31, 2016, respectively. In addition, included in “Other Assets” are $62 million of safe harbor turbine payments we made to Siemens-Gamesa as of March 31, 2017. Related party balances as of March 31, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 December 31, 2016 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ — $ (20 ) $ — $ (14 ) Siemens-Gamesa — (105 ) 1 (181 ) Iberdrola, S.A. — (9 ) — (30 ) Iberdrola Energy Projects, Inc. — — — — Iberdrola Renovables Energía, S.L. — (2 ) 2 — Other 17 (1 ) 22 (3 ) Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. Also included within the Purchases From category are charges for credit support relating to guarantees Iberdrola has provided to third parties guaranteeing our performance. 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 predominantly relate to the purchase of gas for ARHI’s gas-fired cogeneration facility in Klamath, Oregon. 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 March 31, 2017 the amount receivable from New York TransCo was $11 million. AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a notional cash pooling agreement with Bank Mendes Gans, N.V. (BMG), along with certain subsidiaries of Iberdrola. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at BMG. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the notional cash pooling agreement. The BMG balance at both March 31, 2017 and December 31, 2016, was zero.

Accounts Receivable

Accounts Receivable	3 Months Ended
	Mar. 31, 2017
Receivables [Abstract]
Accounts Receivable	Note 14. 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 thirty 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 $58 million and $54 million at March 31, 2017 and December 31, 2016, respectively. The allowance for doubtful accounts for DPAs at March 31, 2017 and December 31, 2016, was $31 million and $30 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for the three months ended March 31, 2017 and 2016 was $1 million and $(1) million, respectively.

Income Tax Expense

Income Tax Expense	3 Months Ended
	Mar. 31, 2017
Income Tax Disclosure [Abstract]
Income Tax Expense	Note 15. Income Tax Expense The effective tax rate for the three months ended March 31, 2017, was 30.1%, which is lower than the 35% statutory federal income tax rate predominantly due to the recognition of production tax credits associated with wind production. Additionally, a $14 million increase in income tax expense is due to unfunded future income tax to reflect the change from a flow through to normalization method, which has been recorded as an increase to revenue, with an offsetting and equal increase to income tax expense. This increase was offset by other discrete tax adjustments during the period. The effective tax rate for the three months ended March 31, 2016, was 32.9%, which is lower than the 35% statutory federal income tax rate primarily due to the recognition of production tax credits associated with wind production.

Stock-Based Compensation Expens

Stock-Based Compensation Expense	3 Months Ended
	Mar. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-Based Compensation Expense	Note 16. Stock-Based Compensation Expense Pursuant to the 2016 Avangrid, Inc. Omnibus Incentive Plan 5,327 additional performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in March 2017. 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 The total stock-based compensation expense, which is included in operations and maintenance of the condensed consolidated statements of income, for the three months ended March 31, 2017 and 2016, was $1.3 million and $1.4 million, respectively. The total liability relating to stock-based compensation, which is included in other non-current liabilities, was $9.6 million and $9.5 million as of March 31, 2017 and December 31, 2016, respectively. Before 2016 the Company’s historical stock-based compensation expense and liabilities were based on shares of Iberdrola and not on shares of the Company. These Iberdrola shares-based awards were early terminated at the end of 2015, and the liability will be settled in two equal installments no later than June 30, 2017 and March 30, 2018.

Tax Equity Financing Arrangemen

Tax Equity Financing Arrangements	3 Months Ended
	Mar. 31, 2017
Tax Equity Financing Arrangements [Abstract]
Tax Equity Financing Arrangements	Note 17. Tax Equity Financing Arrangements The sale of a membership interest in the tax equity financing arrangements (TEFs) represents the sale of an equity interest in a structure that is considered in substance real estate. Under existing guidance for real estate financings, the membership interests in the TEFs we sold to the third-party investors are reflected as a financing obligation in the consolidated balance sheets. We continue to fully consolidate the TEFs’ assets and liabilities in the consolidated balance sheets and to report the results of the TEFs’ operations in the consolidated statements of income. The presentation reflects revenues and expenses from the TEFs’ operations on a fully consolidated basis. We consolidate the TEF’s based on being the primary beneficiary for these variable interest entities (VIEs). The liabilities are increased for cash contributed by the third-party investors, interest accrued, and the federal income tax impact to the third-party investors of the allocation of taxable income. Interest is accrued on the balance using the effective interest method and the third-party investors’ targeted rate of return. The balance accrued interest at an average rate of 5.3% and 5.4% as of March 31, 2017 and December 31, 2016, respectively. The liabilities are reduced by cash distributions to the third-party investors, the allocation of production tax credits to the third-party investors, and the federal income tax impact to the third-party investors of the allocation of taxable losses. This treatment is expected to remain consistent over the terms of the TEFs. The assets and liabilities of these VIEs totaled approximately $1,293 million and $218 million, respectively, at March 31, 2017. As of December 31, 2016, the assets and liabilities of VIEs totaled approximately $1,343 million and $244 million, respectively. At March 31, 2017 and December 31, 2016, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment, equity method investments and TEF liabilities. At March 31, 2017 and December 31, 2016, equity method investments of VIEs were approximately $159 million and $161 million, respectively. At December 31, 2016, we considered the following four structures to be TEFs: (1) Aeolus Wind Power II LLC, (2) Aeolus Wind Power III LLC, (3) Aeolus Wind Power IV LLC, and (4) Locust Ridge Wind Farm, LLC (collectively, Aeolus). In February 2017, we acquired the tax equity investor’s interest in Locust Ridge Wind Farm, LLC for $5 million. This acquisition converted the partnership to a single member limited liability company and it no longer qualifies as 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.

Subsequent Events

Subsequent Events	3 Months Ended
	Mar. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 18. Subsequent Events On April 20, 2017, 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 3, 2017 to shareholders of record at the close of business on June 9, 2017.

Significant Accounting Polici28

Significant Accounting Policies and New Accounting Pronouncements (Policies)	3 Months Ended
	Mar. 31, 2017
Accounting Policies [Abstract]
New Accounting Pronouncements Issued	The following are new accounting pronouncements issued since December 31, 2016, that we are evaluating to determine their effect on our condensed consolidated interim financial statements. (a) Clarifying the definition of a business and the scope of asset derecognition guidance, and accounting for partial sales of nonfinancial assets The Financial Accounting Standards Board (FASB) The amendments issued in February 2017 clarify the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets, and also define in-substance nonfinancial assets. Those amendments apply to a company that: sells nonfinancial assets (land, buildings, materials and supplies, intangible assets) to noncustomers; sells nonfinancial assets and financial assets (cash, receivables) when the value is concentrated in the nonfinancial assets; or sells partial ownership interests in nonfinancial assets. The amendments do not apply to sales to customers or to sales of businesses. The new guidance in ASC 610-20 on accounting for derecognition of a nonfinancial asset and an in-substance nonfinancial asset applies only when the asset (or asset group) does not meet the definition of a business and is not a not-for-profit activity. The amendments issued in both January 2017 and February 2017 as described above are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We do not plan to early adopt. For the amendments concerning the definition of a business, an entity should apply the amendments prospectively on or after the effective date. For the amendments concerning asset derecognition and partial sales of nonfinancial assets an entity must apply them at the same time that it applies the new ASC 606 revenue recognition standard and may elect to apply the amendments retrospectively following either a full retrospective approach or a modified retrospective approach, but does not have to apply the same transition method as for ASC 606. Regardless of which transition method an entity applies to contracts with noncustomers, such as transactions within the scope of ASC 610-20, it must apply the amended definition of a business to those contracts. We expect the amendments issued in both January 2017 and February 2017 will affect our accounting for tax equity investments, which we expect to classify as noncontrolling interests in accordance with ASC 606. We are currently evaluating how our adoption of the amendments will affect our results of operations, financial position, cash flows, and disclosures. (b) 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. The amendments require an entity to present service cost separately from the other components of net benefit cost, and to report the service cost component in the income statement line item(s) where it reports the corresponding compensation cost. An entity is to present all other components of net benefit cost outside of operating cost, if it presents that subtotal. The amendments also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of a self-constructed asset). The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We do not plan to early adopt. An entity is required to apply the amendments retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets. A practical expedient allows an entity to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in the notes to financial statements for pension and postretirement benefit plans for those periods. We are currently evaluating how our adoption of the amendments will affect our results of operations, financial position, cash flows, and disclosures.

Regulatory Assets and Liabili29

Regulatory Assets and Liabilities (Tables)	3 Months Ended
	Mar. 31, 2017
Regulated Operations [Abstract]
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of March 31, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 23 $ 22 Pension and other post-retirement benefits 7 7 Storm costs 40 40 Temporary supplemental assessment surcharge 3 4 Reliability support services 27 27 Revenue decoupling mechanism 13 15 Transmission revenue reconciliation mechanism 14 12 Electric supply reconciliation — 13 Hedges losses 12 10 Contracts for differences 12 14 Hardship programs 16 16 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 1 14 Deferred transmission expense 15 13 Environmental remediation costs 13 14 Other 36 48 Total Current Regulatory Assets 248 285 Non-current Pension and other post-retirement benefits cost deferrals 129 134 Pension and other post-retirement benefits 1,285 1,320 Storm costs 232 187 Deferred meter replacement costs 31 32 Unamortized losses on reacquired debt 19 20 Environmental remediation costs 285 287 Unfunded future income taxes 536 542 Asset retirement obligation 16 18 Deferred property tax 29 33 Federal tax depreciation normalization adjustment 160 161 Merger capital expense target customer credit 11 11 Debt premium 146 151 Reliability support services 49 2 Plant decommissioning 14 14 Contracts for differences 68 61 Hardship programs 14 18 Other 87 100 Total Non-current Regulatory Assets $ 3,111 $ 3,091
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of March 31, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Current Reliability support services (Cayuga) $ 1 $ 3 Non by-passable charges 9 22 Energy efficiency portfolio standard 47 45 Gas supply charge and deferred natural gas cost 14 6 Transmission revenue reconciliation mechanism 9 5 Pension and other post-retirement benefits 1 3 Other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 15 15 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE Refund 22 24 Merger related rate credits 2 3 Revenue decoupling mechanism 3 9 Other 58 38 Total Current Regulatory Liabilities 200 192 Non-current Accrued removal obligations 1,126 1,117 Asset sale gain account 9 9 Carrying costs on deferred income tax bonus depreciation 91 95 Economic development 34 35 Merger capital expense target customer credit account 14 15 Pension and other post-retirement benefits 72 76 Positive benefit adjustment 41 42 New York state tax rate change 8 9 Post term amortization 3 3 Theoretical reserve flow thru impact 23 24 Deferred property tax 18 19 Net plant reconciliation 10 10 Variable rate debt 28 28 Carrying costs on deferred income tax - Mixed Services 263(a) 24 25 Rate refund – FERC ROE proceeding 26 26 Transmission congestion contracts 18 18 Merger-related rate credits 20 21 Accumulated deferred investment tax credits 14 15 Asset retirement obligation 11 13 Earning sharing provisions 22 12 Middletown/Norwalk local transmission network service collections 19 19 Low income programs 48 46 Non-firm margin sharing credits 10 7 Deferred income taxes regulatory 574 565 Other 66 69 Total Non-current Regulatory Liabilities $ 2,329 $ 2,318

Fair Value of Financial Instr30

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	3 Months Ended
	Mar. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of March 31, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 40 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 7 66 70 (57 ) 86 Derivative financial instruments - gas 90 16 89 (165 ) 30 Contracts for differences — — 17 — 17 Total 97 82 176 (222 ) 133 Derivative liabilities Derivative financial instruments - power (27 ) (26 ) (5 ) 53 (5 ) Derivative financial instruments - gas (94 ) (18 ) (39 ) 125 (26 ) Contracts for differences — — (98 ) — (98 ) Derivative financial instruments - other — — (1 ) — (1 ) Total $ (121 ) $ (44 ) $ (143 ) $ 178 $ (130 ) As of December 31, 2016 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 40 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 11 48 58 (42 ) 75 Derivative financial instruments - gas 180 32 104 (239 ) 77 Contracts for differences — — 20 — 20 Total 191 80 182 (281 ) 172 Derivative liabilities Derivative financial instruments - power (24 ) (27 ) (3 ) 39 (15 ) Derivative financial instruments - gas (213 ) (34 ) (53 ) 257 (43 ) Contracts for differences — — (95 ) — (95 ) Total $ (237 ) $ (61 ) $ (151 ) $ 296 $ (153 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2017 and 2016, respectively, is as follows: Three Months Ended March 31, (Millions) 2017 2016 Fair Value Beginning of Period, $ 31 $ (19 ) Gains recognized in operating revenues 12 9 (Losses) recognized in operating revenues (2 ) (6 ) Total gains recognized in operating revenues 10 3 Gains recognized in OCI 1 1 (Losses) recognized in OCI (1 ) — Total gains recognized in OCI — 1 Net change recognized in regulatory assets and liabilities (5 ) (25 ) Purchases 3 — Settlements (6 ) (5 ) Fair Value as of March 31, $ 33 $ (45 ) 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 $ 10 $ 3 Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input March 31, 2017 Risk of non-performance 0.58% - 0.66% Discount rate 1.50% - 2.40% Forward pricing ($ per MW) $3.15 - $9.55
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	As of March 31, 2017 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 $ 4.15 $ 7.37 $ 1.64 with delivery exceeding two on a corroborated by SP15 $ 42.70 $80.28 $14.25 period > two years discounted market data for Mid C $ 34.04 $83.93 $ (0.50) years basis identical or Cinergy $ 35.91 $77.49 $18.53 similar

Derivative Instruments and He31

Derivative Instruments and Hedging (Tables)	3 Months Ended
	Mar. 31, 2017
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, 2017 and 2016, respectively, were as follows: Three Months Ended March 31, 2017 2016 (Millions) Regulatory Assets - Derivative liabilities $ 5 $ (3 ) Regulatory Liabilities - Derivative assets $ 1 $ (22 )
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, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Wholesale electricity purchase contracts (MWh) 5.0 5.6 Natural gas purchase contracts (Dth) 6.0 5.8 Fleet fuel purchase contracts (Gallons) 2.3 2.3 The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of March 31, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (MWh/Dth in millions) Wholesale electricity purchase contracts 2 3 Wholesale electricity sales contracts 7 7 Natural gas and other fuel purchase contracts 314 329 Financial power contracts 8 8 Basis swaps – purchases 60 49 Basis swaps – sales 76 45
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, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 16 $ 10 $ 6 $ 1 Derivative liabilities (5 ) (1 ) (39 ) (86 ) 11 9 (33 ) (85 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — (1 ) — — — (1 ) — Total derivatives before offset of cash collateral 11 9 (34 ) (85 ) Cash collateral receivable — — 12 8 Total derivatives as presented in the balance sheet $ 11 $ 9 $ (22 ) $ (77 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 16 $ 7 $ 5 Derivative liabilities (7 ) (5 ) (40 ) (79 ) 12 11 (33 ) (74 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 12 11 (33 ) (74 ) Cash collateral receivable — — 10 2 Total derivatives as presented in the balance sheet $ 12 $ 11 $ (23 ) $ (72 ) 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, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 79 $ 117 $ 100 $ 6 Derivative liabilities (30 ) (7 ) (115 ) (10 ) 49 110 (15 ) (4 ) Designated as hedging instruments Derivative assets 16 8 — 1 Derivative liabilities — (2 ) (15 ) (1 ) 16 6 (15 ) — Total derivatives before offset of cash collateral 65 116 (30 ) (4 ) Cash collateral receivable (payable) (19 ) (49 ) 2 1 Total derivatives as presented in the balance sheet $ 46 $ 67 $ (28 ) $ (3 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 198 $ 108 $ 78 $ 7 Derivative liabilities (118 ) (4 ) (132 ) (16 ) 80 104 (54 ) (9 ) Designated as hedging instruments Derivative assets 25 4 — — Derivative liabilities (1 ) — (39 ) (21 ) 24 4 (39 ) (21 ) Total derivatives before offset of cash collateral 104 108 (93 ) (30 ) Cash collateral receivable (payable) (17 ) (46 ) 41 24 Total derivatives as presented in the balance sheet $ 87 $ 62 $ (52 ) $ (6 )
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, 2017 and 2016, 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) 2017 Interest rate contracts $ — Interest expense $ 2 Commodity contracts (1 ) Operating expenses — Total $ (1 ) $ 2 2016 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses 1 Total $ — $ 3 (a) The effect of derivatives in cash flow hedging relationships on OCI and income for the three months ended March 31, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, Gain Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2017 Commodity contracts $ 4 Revenues $ 33 Total $ 4 $ 33 2016 Commodity contracts $ 3 Revenues $ (46 ) Total $ 3 $ (46 ) (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, 2017 and December 31, 2016, respectively, consisted of: March 31, December 31, As of 2017 2016 (Millions) Wholesale electricity purchase contracts $ (10 ) $ (2 ) Wholesale electricity sales contracts 25 6 Natural gas and other fuel purchase contracts 6 30 Financial power contracts 64 56 Basis swaps – purchases (8 ) 3 Basis swaps – sales 5 (2 ) Total $ 82 $ 91
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, 2017 and 2016, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Wholesale electricity purchase contracts $ (3 ) $ — Wholesale electricity sales contracts 7 (1 ) Financial power contracts (3 ) 1 Financial and natural gas contracts 4 (30 ) Total Gain (Loss) $ 5 $ (30 ) The effect of non-trading derivatives associated with Renewables and Gas activities for the three months ended March 31, 2017 and 2016, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Wholesale electricity purchase contracts $ (6 ) $ (3 ) Wholesale electricity sales contracts 11 6 Financial power contracts 16 1 Financial and natural gas contracts (4 ) (9 ) Total Gain (Loss) $ 17 $ (5 )

Post-retirement and Similar O32

Post-retirement and Similar Obligations (Tables)	3 Months Ended
	Mar. 31, 2017
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, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Service cost $ 11 $ 11 Interest cost 35 35 Expected return on plan assets (50 ) (51 ) Amortization of: Prior service costs — — Actuarial loss 32 38 Net Periodic Benefit Cost $ 28 $ 33 The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Service cost $ 1 $ 1 Interest cost 5 6 Expected return on plan assets (2 ) (3 ) Amortization of: Prior service costs (2 ) (2 ) Actuarial loss 1 2 Net Periodic Benefit Cost $ 3 $ 4

Equity (Tables)

Equity (Tables)	3 Months Ended
	Mar. 31, 2017
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Loss Accumulated OCI for the three months ended March 31, 2017 and 2016, respectively, consisted of: As of December 31, Three Months Ended March 31, As of March 31, As of December 31, Three Months Ended March 31, As of March 31, 2016 2017 2017 2015 2016 2016 (Millions) Gain on revaluation of defined benefit plans, net of income tax expense of $2.8 for 2016 $ (14 ) $ — $ (14 ) $ (21 ) $ 4 $ (17 ) Loss for nonqualified pension plans (7 ) — (7 ) (8 ) — (8 ) Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $1.3 for 2017 and $1.2 for 2016 5 2 7 31 2 33 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $13.6 for 2017 and $(16.6) for 2016(a) (70 ) 23 (47 ) (54 ) (26 ) (80 ) Gain (loss) on derivatives qualifying as cash flow hedges (65 ) 25 (40 ) (23 ) (24 ) (47 ) Accumulated Other Comprehensive Loss $ (86 ) $ 25 $ (61 ) $ (52 ) $ (20 ) $ (72 ) (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, 2017
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, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 239 $ 212 Denominator: Weighted average number of shares outstanding - basic 309,508,889 309,538,215 Weighted average number of shares outstanding - diluted 309,837,442 309,808,006 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.77 $ 0.69 Earnings Per Common Share, Diluted $ 0.77 $ 0.69

Segment Information (Tables)

Segment Information (Tables)	3 Months Ended
	Mar. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the three months ended March 31, 2017, consisted of: Three Months Ended March 31, 2017 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,460 $ 285 $ 14 $ (1 ) $ 1,758 Revenue - intersegment (1 ) 2 11 (12 ) — Depreciation and amortization 113 78 6 — 197 Operating income (loss) 336 56 7 (1 ) 398 Adjusted EBITDA 449 133 14 (1 ) 595 Earnings (losses) from equity method investments 4 (2 ) — — 2 Capital expenditures $ 267 $ 257 $ 1 $ — $ 525 As of March 31, 2017 Property, plant and equipment 13,168 8,133 496 — 21,797 Equity method investments 149 235 — — 384 Total assets $ 20,998 $ 9,996 $ 1,041 $ (639 ) $ 31,396 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Segment information for the three months ended March 31, 2016, consisted of: Three Months Ended March 31, 2016 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,390 $ 276 $ 3 $ 1 $ 1,670 Revenue - intersegment — 2 9 (11 ) — Depreciation and amortization 118 80 7 — 205 Operating income (loss) 312 49 (10 ) (2 ) 349 Adjusted EBITDA 430 129 (3 ) (2 ) 554 Earnings (losses) from equity method investments 3 (1 ) — — 2 Capital expenditures $ 206 $ 70 $ — $ — $ 276 As of December 31, 2016 Property, plant and equipment 13,032 8,015 501 — 21,548 Equity method investments 151 236 — — 387 Total assets $ 20,753 $ 9,884 $ 1,124 $ (452 ) $ 31,309 (a) Does not represent a segment. It mainly includes Corporate 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, 2017 and 2016, respectively, is as follows: Three Months Ended March 31, 2017 2016 (Millions) Consolidated Adjusted EBITDA $ 595 $ 554 Less: Depreciation and amortization 197 205 Interest expense, net of capitalization 71 84 Income tax expense 103 104 Add: Other income 13 49 Earnings from equity method investments 2 2 Consolidated Net Income $ 239 $ 212

Related Party Transactions (Tab

Related Party Transactions (Tables)	3 Months Ended
	Mar. 31, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three months ended March 31, 2017 and 2016, respectively, consisted of: Three Months Ended March 31, 2017 2016 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (10 ) $ — $ (5 ) Iberdrola Renovables Energía, S.L. — (2 ) — (3 ) Iberdrola, S.A. — (9 ) — (8 ) Other 16 — 1 —
Schedule of Related Party Balances	Related party balances as of March 31, 2017 and December 31, 2016, respectively, consisted of: As of March 31, 2017 December 31, 2016 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ — $ (20 ) $ — $ (14 ) Siemens-Gamesa — (105 ) 1 (181 ) Iberdrola, S.A. — (9 ) — (30 ) Iberdrola Energy Projects, Inc. — — — — Iberdrola Renovables Energía, S.L. — (2 ) 2 — Other 17 (1 ) 22 (3 )

Background and Nature Of Oper37

Background and Nature Of Operations - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2017
Nature Of Business [Line Items]
Owned Subsidiaries	81.60%
NEW YORK
Nature Of Business [Line Items]
Incorporation date of organization	Jan. 1, 1997

Regulatory Assets and Liabili38

Regulatory Assets and Liabilities - Additional Information (Detail) $ in Millions	1 Months Ended	3 Months Ended
	Dec. 31, 2016USD ($)	Mar. 31, 2017USD ($)Station	Mar. 31, 2016USD ($)
Regulatory Assets And Liabilities [Line Items]
Unrecorded Regulatory Assets		$ 2,212
Public utilities regulatory authority distribution rate	9.15%
Increase (decrease) in distribution rates	9.10%
Unfunded future Income tax expense collection period		50 years
Number of nuclear generating stations | Station		2
UIL Holdings [Member]
Regulatory Assets And Liabilities [Line Items]
Business combination merger related rate credits		$ 2	$ 20
Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Approved return on equity		11.74%
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 | Minimum [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period		27 years
NEW YORK | Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period		39 years
Deferred Property Tax [Member] | NEW YORK
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period		5 years
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
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 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 Three [Member]
Regulatory Assets And Liabilities [Line Items]
Customer receiving percentage		90.00%
Return on equity		10.50%
NYSEG [Member]
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%
Equity ratio for earnings sharing		50.00%
NYSEG [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period		5 years
NYSEG [Member] | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period		10 years
NYSEG [Member] | Deferred Income Tax Charge
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period		50 years
RGE Electric [Member]
Regulatory Assets And Liabilities [Line Items]
Approved return on equity		9.00%
Equity ratio		48.00%
Equity ratio for earnings sharing		50.00%
United Illuminating Company (UI)
Regulatory Assets And Liabilities [Line Items]
Public utilities nature of allowance for earnings on equity, description		UI and customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year
Central Maine Power Company [Member]
Regulatory Assets And Liabilities [Line Items]
Recovery of deferred storm costs		$ 123
Central Maine Power Company [Member] | Storm Costs
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	$ 75	$ 81
UI [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Deferred costs		1
Regulatory assets		$ 0

Regulatory Assets and Liabili39

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Regulatory Asset [Line Items]
Regulatory Assets, current	$ 248	$ 285
Regulatory Assets, noncurrent	3,111	3,091
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	23	22
Regulatory Assets, noncurrent	129	134
Pension And Other Post-Retirement Benefits [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	7	7
Regulatory Assets, noncurrent	1,285	1,320
Storm Costs
Regulatory Asset [Line Items]
Regulatory Assets, current	40	40
Regulatory Assets, noncurrent	232	187
Temporary Supplemental Assessment Surcharge [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	3	4
Support Services [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	27	27
Regulatory Assets, noncurrent	49	2
Revenue Decoupling Mechanism [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	13	15
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	14	12
Electric Supply Reconciliation [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current		13
Hedges Loss [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	12	10
Contracts For Differences [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	12	14
Regulatory Assets, noncurrent	68	61
Hardship Programs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	16	16
Regulatory Assets, noncurrent	14	18
Deferred Property Tax [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	10	10
Regulatory Assets, noncurrent	29	33
Plant Decommissioning [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	6	6
Regulatory Assets, noncurrent	14	14
Deferred Purchased Gas [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	1	14
Deferred Transmission Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	15	13
Environmental Restoration Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	13	14
Regulatory Assets, noncurrent	285	287
Other [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	36	48
Regulatory Assets, noncurrent	87	100
Deferred Meter Replacement Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	31	32
Unamortized Loss On Reacquired Debt [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	19	20
Future Income Tax [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	536	542
Asset Retirement Obligation Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	16	18
Federal Tax Depreciation Normalization Adjustment [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	160	161
Merger Capital Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	11	11
Debt Premium [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	$ 146	$ 151

Regulatory Assets and Liabili40

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 200	$ 192
Regulatory liabilities including deferred income taxes, noncurrent	1,755	1,753
Deferred income taxes regulatory	574	565
Regulatory liabilities including deferred income taxes, noncurrent	2,329	2,318
Support Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	1	3
Non By Passable Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	9	22
Energy Efficiency Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	47	45
Gas Supply Charge And Deferred Natural Gas Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	14	6
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	9	5
Pension And Other Post-Retirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	1	3
Regulatory liabilities including deferred income taxes, noncurrent	72	76
Other Post-Retirement Benefits Cost Deferrals [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	14	14
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	15	15
Regulatory liabilities including deferred income taxes, noncurrent	91	95
Yankee DOE Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	22	24
Merger Related Rate Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	2	3
Regulatory liabilities including deferred income taxes, noncurrent	20	21
Carrying Costs On Deferred Income Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	5	5
Regulatory liabilities including deferred income taxes, noncurrent	24	25
Revenue Decoupling Mechanism [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	9
Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	58	38
Regulatory liabilities including deferred income taxes, noncurrent	66	69
Accrued Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	1,126	1,117
Asset Sale Gain Account [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	9	9
Economic Development [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	34	35
Merger Capital Expense [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	14	15
Positive Benefit Adjustment [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	41	42
New York State Tax Rate Change [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	8	9
Post Term Amortization [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	3	3
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	23	24
Deferred Property Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	18	19
Net Plant Reconciliation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	10	10
Variable Rate Debt [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	28	28
Rate Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	26	26
Accumulated Deferred Investment Tax Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	14	15
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	11	13
Transmission Congestion Contracts [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	18	18
Middletown/Norwalk Local Transmission Network Service Collections [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	19	19
Low Income Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	48	46
Earning sharing provisions [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	22	12
Non-Firm Margin Sharing Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	$ 10	$ 7

Fair Value of Financial Instr41

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other Assets	$ 215	$ 241
Fair value of debt	5,243	5,204
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 Instr42

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 133	$ 172
Derivative financial instruments, liabilities	(130)	(153)
Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(222)	(281)
Derivative financial instruments, liabilities	178	296
Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	40	40
Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	86	75
Derivative financial instruments, liabilities	(5)	(15)
Derivative Financial Instrument Power [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(57)	(42)
Derivative financial instruments, liabilities	53	39
Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	30	77
Derivative financial instruments, liabilities	(26)	(43)
Derivative Financial Instrument Gas [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(165)	(239)
Derivative financial instruments, liabilities	125	257
Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	17	20
Derivative financial instruments, liabilities	(98)	(95)
Derivative Financial Instrument Other [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	(1)
Fair Value, Inputs, Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	97	191
Derivative financial instruments, liabilities	(121)	(237)
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	40	40
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	7	11
Derivative financial instruments, liabilities	(27)	(24)
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	90	180
Derivative financial instruments, liabilities	(94)	(213)
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	82	80
Derivative financial instruments, liabilities	(44)	(61)
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	66	48
Derivative financial instruments, liabilities	(26)	(27)
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	16	32
Derivative financial instruments, liabilities	(18)	(34)
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	176	182
Derivative financial instruments, liabilities	(143)	(151)
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	70	58
Derivative financial instruments, liabilities	(5)	(3)
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	89	104
Derivative financial instruments, liabilities	(39)	(53)
Level 3 [Member] | Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	17	20
Derivative financial instruments, liabilities	(98)	$ (95)
Level 3 [Member] | Derivative Financial Instrument Other [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	$ (1)

Fair Value of Financial Instr43

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, 2017	Mar. 31, 2016
Debt Instrument Fair Value Carrying Value [Abstract]
Fair Value as of January 1,	$ 31	$ (19)
Gains recognized in operating revenues	12	9
(Losses) recognized in operating revenues	(2)	(6)
Total gains recognized in operating revenues	10	3
Gains recognized in OCI	1	1
(Losses) recognized in OCI	(1)
Total gains recognized in OCI		1
Net change recognized in regulatory assets and liabilities	(5)	(25)
Purchases	3
Settlements	(6)	(5)
Fair Value as of March 31,	33	(45)
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	$ 10	$ 3

Fair Value of Financial Instr44

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	3 Months Ended
	Mar. 31, 2017$ / 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	4.15
CME SWAPS MARKETS (NYMEX) [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	7.37
CME SWAPS MARKETS (NYMEX) [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	1.64
SP15 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	SP15 ($/MWh)
SP15 [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	42.70
SP15 [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	80.28
SP15 [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	14.25
Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Mid C ($/MWh)
Mid C [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	34.04
Mid C [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	83.93
Mid C [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	(0.50)
Cinergy [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Cinergy ($/MWh)
Cinergy [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	35.91
Cinergy [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	77.49
Cinergy [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	18.53

Fair Value of Financial Instr45

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, 2017$ / MWh
Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.58%
Discount rate	1.50%
Forward pricing ($ per MW)	3.15
Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.66%
Discount rate	2.40%
Forward pricing ($ per MW)	9.55

Derivative Instruments and He46

Derivative Instruments and Hedging - Additional Information (Detail) - USD ($)		3 Months Ended		12 Months Ended
		Mar. 31, 2017	Mar. 31, 2016	Mar. 31, 2018	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities		$ 45,000,000	$ 67,000,000
Derivative financial instruments, assets		133,000,000				$ 172,000,000
Gross Amounts of Recognized Liabilities		130,000,000				153,000,000
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]	23,000,000	(26,000,000)
UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets		17,000,000				19,000,000
Regulatory Assets		81,000,000				75,000,000
Gross Amounts of Recognized Liabilities		98,000,000				95,000,000
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		76,000,000				70,000,000
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		$ (800,000)
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				$ 800,000
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		$ 74,900,000				76,700,000
Network [Member] | Electricity Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities		(20,100,000)				(12,300,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income		(10,900,000)	(34,800,000)
Network [Member] | Natural Gas Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities		500,000				3,500,000
Gain (Loss) reclassified from regulatory assets and liabilities into income		$ 600,000	(3,400,000)
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		$ (300,000)	$ (4,400,000)
Unrealized gain(loss) from hedging activities reported on OCI		$ 500,000
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
Counter Party [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities		20,100,000
Cash Collateral Pledged		23,000,000				$ 20,000,000
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		$ 11,000,000
[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 He47

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Regulatory Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory Assets (Liabilities) - Derivative assets (liabilities)	$ 5	$ (3)
Regulatory Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory Assets (Liabilities) - Derivative assets (liabilities)	$ 1	$ (22)

Derivative Instruments and He48

Derivative Instruments and Hedging - Net Notional Volume (Detail)	Mar. 31, 2017MWhDTHgal	Dec. 31, 2016MWhDTHgal
Network [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	5,000,000	5,600,000
Network [Member] | Natural Gas Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	6,000,000	5,800,000
Network [Member] | Fleet Fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | gal	2,300,000	2,300,000
Renewables and Gas Activities [Member] | Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	60,000,000	49,000,000
Renewables and Gas Activities [Member] | Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	76,000,000	45,000,000
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	2,000,000	3,000,000
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	7,000,000	7,000,000
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	314,000,000	329,000,000
Renewables and Gas Activities [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	8,000,000	8,000,000

Derivative Instruments and He49

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Network [Member] | UIL Holdings [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	$ 11	$ 12
Total derivatives as presented in the balance sheet	11	12
Network [Member] | UIL Holdings [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	16	19
Derivative liabilities	(5)	(7)
Derivative Fair Value, Net	11	12
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	9	11
Total derivatives as presented in the balance sheet	9	11
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	10	16
Derivative liabilities	(1)	(5)
Derivative Fair Value, Net	9	11
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(34)	(33)
Cash collateral receivable	12	10
Total derivatives as presented in the balance sheet	(22)	(23)
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	6	7
Derivative liabilities	(39)	(40)
Derivative Fair Value, Net	(33)	(33)
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(1)
Derivative Fair Value, Net	(1)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(85)	(74)
Cash collateral receivable	8	2
Total derivatives as presented in the balance sheet	(77)	(72)
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	5
Derivative liabilities	(86)	(79)
Derivative Fair Value, Net	(85)	(74)
Renewables and Gas Activities [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	65	104
Cash collateral receivable (payable)	(19)	(17)
Total derivatives as presented in the balance sheet	46	87
Renewables and Gas Activities [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(30)	(118)
Derivative Fair Value, Net	49	80
Derivative assets	79	198
Renewables and Gas Activities [Member] | Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities		(1)
Derivative Fair Value, Net	16	24
Derivative assets	16	25
Renewables and Gas Activities [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	116	108
Cash collateral receivable (payable)	(49)	(46)
Total derivatives as presented in the balance sheet	67	62
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(7)	(4)
Derivative Fair Value, Net	110	104
Derivative assets	117	108
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(2)
Derivative Fair Value, Net	6	4
Derivative assets	8	4
Renewables and Gas Activities [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(30)	(93)
Cash collateral receivable (payable)	2	41
Total derivatives as presented in the balance sheet	(28)	(52)
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(115)	(132)
Derivative Fair Value, Net	(15)	(54)
Derivative assets	100	78
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(15)	(39)
Derivative Fair Value, Net	(15)	(39)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(4)	(30)
Cash collateral receivable (payable)	1	24
Total derivatives as presented in the balance sheet	(3)	(6)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(10)	(16)
Derivative Fair Value, Net	(4)	(9)
Derivative assets	6	7
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(1)	(21)
Derivative Fair Value, Net		$ (21)
Derivative assets	$ 1

Derivative Instruments and He50

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Recognized in OCI Derivatives Effective Portion	[1]	$ 4	$ 3
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[2]	(1)
Loss (Gain) Reclassified from Accumulated OCI Income Effective Portion	[2]	2	3
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI Income Effective Portion	[1]	(33)	46
Interest Rate Contract [Member] | Network [Member] | Interest expense [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI Income Effective Portion	[2]	2	2
Commodity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Recognized in OCI Derivatives Effective Portion	[1]	4	3
Commodity Contract [Member] | Network [Member] | Operating expenses [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[2]	(1)
Loss (Gain) Reclassified from Accumulated OCI Income Effective Portion	[2]		1
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Revenue [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI Income Effective Portion	[1]	$ (33)	$ 46
[1]	Changes in OCI are reported on a pre-tax basis.
[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 He51

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 82	$ 91
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	64	56
Long [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(10)	(2)
Long [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	6	30
Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(8)	3
Short [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	25	6
Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 5	$ (2)

Derivative Instruments and He52

Derivative Instruments and Hedging - Effect of Trading Derivatives (Detail) - Renewables and Gas Activities [Member] - Trading Derivatives [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 5	$ (30)
Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(3)
Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	7	(1)
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(3)	1
Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 4	$ (30)

Derivative Instruments and He53

Derivative Instruments and Hedging - Effect of Non-Trading Derivatives (Detail) - Renewables and Gas Activities [Member] - Non-Trading Derivatives [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 17	$ (5)
Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(6)	(3)
Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	11	6
Financial Power Contracts [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	16	1
Financial and Natural Gas Contracts [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (4)	$ (9)

Contingencies - Additional Info

Contingencies - Additional Information (Detail) $ in Millions

Apr. 14, 2017

Feb. 01, 2017

Oct. 14, 2016USD ($)

Apr. 29, 2016

Mar. 25, 2016USD ($)

Mar. 22, 2016

Jul. 31, 2014

Dec. 26, 2012

Nov. 30, 2013USD ($)

Dec. 31, 2012USD ($)

Mar. 31, 2017USD ($)

Dec. 31, 2016USD ($)

Dec. 31, 2012USD ($)

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)

Regulatory liabilities

$ 1,755

$ 1,753

Spent fuel litigation damages awarded, value

$ 76.8

$ 235.4

$ 160

Litigation appeal expiration date

Jul. 18, 2016

Spent fuel litigation damages settlement received

$ 41.6

Adjustment regulatory deferral and earning sharing accruals

$ 9.8

Staff issue settlement reserve

3.4

3.4

Customer share of earnings sharing

2.4

Price of the power purchase agreements

$ 259

Standby letters of credit

2,700

March 2017 Windstorm [Member]

Loss Contingencies [Line Items]

Number of affected customers | Customer

219,000

Connecticut Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Court of Federal Claims award

39.7

39.7

Spent fuel litigation damages awarded, value

32.6

126.3

Spent fuel litigation damages settlement received

18.4

Maine Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Court of Federal Claims award

$ 81.7

81.7

Spent fuel litigation damages awarded, value

24.6

37.7

Spent fuel litigation damages settlement received

3.6

CMP Distribution [Member]

Loss Contingencies [Line Items]

Share of the award credited back to customers

28.2

36.5

Spent fuel litigation damages settlement received

21.5

UI [Member]

Loss Contingencies [Line Items]

Share of the award credited back to customers

12

$ 3.8

Yankee Atomic Energy Corporation [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 19.6

73.3

Spent fuel litigation damages settlement received

$ 19.6

Subsequent Event [Member]

Loss Contingencies [Line Items]

Midpoint of base return on equity warranted percentage

9.39%

Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.74%

Maximum [Member] | Connecticut Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

38.3

Minimum [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 82

Minimum [Member] | Connecticut Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 21.4

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 ROE 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.

Regulatory liabilities

$ 21.9

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%

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 were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge, relating to the refund periods and going forward period. 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 later in 2017, once FERC has enough commissioners to provide a quorum for decision-making.

Reasonably possible loss, in additional reserve, pre tax

$ 17.1

Phase III [Member] | CMP and UI [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages settlement received

$ 4.2

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

8.59%

8.61%

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

Loss Contingencies [Line Items]

Approved return on equity

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	Sep. 11, 2014USD ($)	Aug. 14, 2013USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)	Mar. 31, 2017USD ($)siteLocation	Dec. 31, 2016USD ($)	Aug. 04, 2016USD ($)	Jan. 31, 2015USD ($)
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						$ 384	$ 388
Accrual for environmental loss contingencies	$ 27					$ 26
Damages for incurred costs payment amount	$ 22
Refund of environmental remediation cost paid				$ 5
Number of sites with modified decision | site						9
Future costs that have been recorded as a receivable									$ 16
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 One Beacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 30	30	$ 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						$ 6
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						$ 22
New York Voluntary Cleanup Program [Member]
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site						11
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						$ 97	$ 97
Manufactured Gas Plants | Minimum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						221
Manufactured Gas Plants | Maximum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 465

Post-Retirement and Similar O56

Post-Retirement and Similar Obligations - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2017USD ($)
Compensation And Retirement Disclosure [Abstract]
Defined benefit, pension contributions	$ 0
Contributions for remainder of fiscal year	$ 33,000,000

Post-Retirement and Similar O57

Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 11	$ 11
Interest cost	35	35
Expected return on plan assets	(50)	(51)
Amortization of actuarial loss	32	38
Net Periodic Benefit Cost	28	33
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1
Interest cost	5	6
Expected return on plan assets	(2)	(3)
Amortization of prior service costs	(2)	(2)
Amortization of actuarial loss	1	2
Net Periodic Benefit Cost	$ 3	$ 4

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Class Of Stock [Line Items]
Common stock, authorized	500,000,000		500,000,000
Common stock, issued	309,670,932		309,600,439
Common stock, outstanding	309,069,291		308,993,149
Common stock, par value	$ 0.01		$ 0.01
Common stock	$ 3		$ 3
Additional paid-in capital	$ 13,653		$ 13,653
Treasury stock, shares	485,810		491,459
Convertible preferred stock, shares outstanding	0		0
Issuance of common stock, shares	70,493	97,479
Release of common stock held in trust	5,649	132,800
Repurchase of common stock, shares	115,831
Repurchase of common stock	$ 5
Iberdrola Renewables Holding, Inc [Member]
Class Of Stock [Line Items]
Percentage of equity owned by parent	81.60%		81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		3 Months Ended
		Mar. 31, 2017	Dec. 31, 2016	Mar. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense		$ 2		$ 2
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)		(40)	$ (65)	(47)	$ (23)
Accumulated other comprehensive loss		(61)	(86)	(72)	(52)
Gain on defined benefit plans, net of income tax				4
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes	[1]	23		(26)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax		25		(24)
Other comprehensive income (loss), net of tax		25		(20)
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 expense (benefit)	[1]	(47)	(70)	(80)	(54)
Designated as Hedging Instrument [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense		7	5	33	31
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, net of income tax expense		(14)	(14)	(17)	(21)
Gain on defined benefit plans, net of income tax				4
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, net of income tax expense		$ (7)	$ (7)	$ (8)	$ (8)
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Equity - Accumulated Other Co60

Equity - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense		$ 2.8
Unrealized gain during period on derivatives qualified as cash flow hedges, income tax expense	$ 1.3	1.2
Reclassification to net income of losses (gains) on cash flow hedges, income tax expense	$ 13.6	(16.6)
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense		$ 2.8

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, 2017	Mar. 31, 2016
Numerator:
Net income attributable to AVANGRID	$ 239	$ 212
Denominator:
Weighted average number of shares outstanding - basic	309,508,889	309,538,215
Weighted average number of shares outstanding - diluted	309,837,442	309,808,006
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$ 0.77	$ 0.69
Earnings Per Common Share, Diluted	$ 0.77	$ 0.69

Segment Information - Additiona

Segment Information - Additional Information (Detail)	3 Months Ended
	Mar. 31, 2017USD ($)Segment	Mar. 31, 2016USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	3
Operating Revenues	$ 1,758,000,000	$ 1,670,000,000
Regulated Electric Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	921,000,000	913,000,000
Regulated Gas Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	537,000,000	477,000,000
Other Networks [Member]
Segment Reporting Information [Line Items]
Operating Revenues	2,000,000	0
Renewable Energy Generation Of Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues	285,000,000	276,000,000
Gas Storage Services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	4,000,000	7,000,000
Gas Trading Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	$ 10,000,000	$ (4,000,000)
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, 2017	Mar. 31, 2016	Dec. 31, 2016
Segment Reporting Information [Line Items]
Revenue - external		$ 1,758	$ 1,670
Depreciation and amortization		197	205
Operating income (loss)		398	349
Adjusted EBITDA		595	554
Earnings (losses) from equity method investments		2	2
Capital expenditures		525	276
Property, plant and equipment		21,797		$ 21,548
Equity method investments		384		387
Total assets		31,396		31,309
Operating Segments [Member] | Network [Member]
Segment Reporting Information [Line Items]
Revenue - external		1,460	1,390
Revenue - intersegment		(1)
Depreciation and amortization		113	118
Operating income (loss)		336	312
Adjusted EBITDA		449	430
Earnings (losses) from equity method investments		4	3
Capital expenditures		267	206
Property, plant and equipment		13,168		13,032
Equity method investments		149		151
Total assets		20,998		20,753
Operating Segments [Member] | Renewables [Member]
Segment Reporting Information [Line Items]
Revenue - external		285	276
Revenue - intersegment		2	2
Depreciation and amortization		78	80
Operating income (loss)		56	49
Adjusted EBITDA		133	129
Earnings (losses) from equity method investments		(2)	(1)
Capital expenditures		257	70
Property, plant and equipment		8,133		8,015
Equity method investments		235		236
Total assets		9,996		9,884
Operating Segments [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Revenue - external		14	3
Revenue - intersegment		11	9
Depreciation and amortization		6	7
Operating income (loss)		7	(10)
Adjusted EBITDA		14	(3)
Capital expenditures		1
Property, plant and equipment		496		501
Total assets		1,041		1,124
Corporate and Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue - external	[1]	(1)	1
Revenue - intersegment	[1]	(12)	(11)
Operating income (loss)	[1]	(1)	(2)
Adjusted EBITDA	[1]	(1)	$ (2)
Total assets	[1]	$ (639)		$ (452)
[1]	Does not represent a segment. It mainly includes Corporate 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, 2017	Mar. 31, 2016
Segment Reporting [Abstract]
Consolidated Adjusted EBITDA	$ 595	$ 554
Depreciation and amortization	197	205
Interest expense, net of capitalization	71	84
Income tax expense	103	104
Other income	13	49
Earnings from equity method investments	2	2
Net Income	$ 239	$ 212

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Purchases From	$ (10)	$ (5)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Purchases From	(2)	(3)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Purchases From	(9)	(8)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Sales To	$ 16	$ 1

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended	12 Months Ended
	Mar. 31, 2017	Dec. 31, 2016
Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Portion of amount receivable from related parties		$ 1,000,000
Affiliated Entity [Member] | Impairment of non-current assets [Member]
Related Party Transaction [Line Items]
Impairments	$ 0
BMG [Member]
Related Party Transaction [Line Items]
Deposit balance	$ 0	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	$ 66,000,000	$ 269,000,000
Payments to related party	$ 62,000,000
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	$ 11,000,000

Related Party Transactions - 67

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Mar. 31, 2017	Dec. 31, 2016
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Owed To	$ (20)	$ (14)
Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Owed By		1
Owed To	(105)	(181)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Owed To	(9)	(30)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Owed By		2
Owed To	(2)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Owed By	17	22
Owed To	$ (1)	$ (3)

Accounts Receivable - Additiona

Accounts Receivable - Additional Information (Detail) - DPA [Member] - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016	Dec. 31, 2016
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, net	$ 58		$ 54
Allowance for doubtful accounts, deferred payment arrangement	31		$ 30
Provision for doubtful accounts, accounts receivable	$ 1	$ (1)

Income Tax Expense - Additional

Income Tax Expense - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2017	Mar. 31, 2016
Income Tax Disclosure [Abstract]
Effective income tax rate before elimination of unfunded future income tax and sale of equity investment	30.10%	32.90%
Increase in income tax expense due to unfunded future income tax	$ 14
Statutory federal income tax rate	35.00%	35.00%

Stock-Based Compensation Expe70

Stock-Based Compensation Expense - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended	3 Months Ended
	Mar. 31, 2017USD ($)$ / sharesshares	Mar. 31, 2017USD ($)Installment	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Stock-based compensation expense | $		$ 1.3	$ 1.4
Stock-based compensation other non-current liabilities | $	$ 9.6	$ 9.6		$ 9.5
Iberdrola [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of installment payments of employee related payables | Installment		2
Iberdrola [Member] | Installment One [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employee related liabilities settlement date		Jun. 30, 2017
Iberdrola [Member] | Installment Two [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employee related liabilities settlement date		Mar. 30, 2018
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
Performance Shares Units [Member] | Officers and Employees [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Additional number of PSUs granted | shares	5,327
Number of installment payments of employee related payables | Installment		3
Share-based payment award options grant date fair value, per share | $ / shares	$ 31.80

Tax Equity Financing Arrangem71

Tax Equity Financing Arrangements - Additional Information (Detail) - USD ($)	1 Months Ended	3 Months Ended
	Feb. 28, 2017	Mar. 31, 2017	Dec. 31, 2016
Tax Equity Financing Arrangements [Line Items]
Accrued interest average rate		5.30%	5.40%
Assets of variable interest entities (VIEs)		$ 1,293,000,000	$ 1,343,000,000
Liabilities of variable interest entities (VIEs)		218,000,000	244,000,000
Equity method investments of variable interest entities (VIEs)		384,000,000	387,000,000
Upfront cash payments		0
Variable Interest Entity, Primary Beneficiary [Member]
Tax Equity Financing Arrangements [Line Items]
Equity method investments of variable interest entities (VIEs)		$ 159,000,000	$ 161,000,000
Locust Ridge Wind Farm, LLC [Member]
Tax Equity Financing Arrangements [Line Items]
Acquisition of equity investor's interest	$ 5,000,000

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - $ / shares	Apr. 20, 2017	Mar. 31, 2017	Mar. 31, 2016
Subsequent Event [Line Items]
Quarterly dividend payable, per share		$ 0.432	$ 0.432
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividend declared date	Apr. 20, 2017
Quarterly dividend payable, per share	$ 0.432
Dividend payment date	Jul. 3, 2017
Dividend record date	Jun. 9, 2017