Avangrid (AGR) 10-K 10 Mar 17 2016 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Mar. 09, 2017	Jun. 30, 2016
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	FY
Trading Symbol	AGR
Entity Registrant Name	Avangrid, Inc.
Entity Central Index Key	1,634,997
Current Fiscal Year End Date	--12-31
Entity Well-known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		309,068,730
Entity Public Float			$ 2,576

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Operating Revenues	$ 6,018	$ 4,367	$ 4,594
Operating Expenses
Purchased power, natural gas and fuel used	1,286	972	1,181
Operations and maintenance	2,206	1,808	1,560
Impairment of non-current assets		12	25
Depreciation and amortization	804	695	629
Taxes other than income taxes	528	367	314
Total Operating Expenses	4,824	3,854	3,709
Operating Income	1,194	513	885
Other Income and (Expense)
Other income and (expense)	76	55	52
Earnings from equity method investments	7		12
Interest expense, net of capitalization	(268)	(267)	(243)
Income (Loss) Before Income Tax	1,009	301	706
Income tax expense (benefit)	379	34	282
Net Income	630	267	424
Net Income Attributable to Avangrid, Inc.	$ 630	$ 267	$ 424
Earnings Per Common Share, Basic:	$ 2.04	$ 1.05	$ 1.68
Earnings Per Common Share, Diluted:	$ 2.04	$ 1.05	$ 1.68
Weighted-average Number of Common Shares Outstanding:
Basic	309,512,553	254,588,212	252,235,232
Diluted	309,817,322	254,605,111	252,235,232
Cash Dividends Declared Per Common Share	$ 1.728
Avangrid, Inc [Member]
Operating Expenses
Operating expense	$ 5	$ 38	$ 2
Taxes other than income taxes	5	5	2
Total Operating Expenses	10	43	4
Operating Income	(10)	(43)	(4)
Other Income and (Expense)
Other income and (expense)	68	10	(1)
Earnings from equity method investments	565	44	515
Interest expense, net of capitalization	(32)	(14)	(34)
Income (Loss) Before Income Tax	591	(3)	476
Income tax expense (benefit)	(39)	(270)	52
Net Income	630	267	424
Net Income Attributable to Avangrid, Inc.	$ 630	$ 267	$ 424

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Net Income		$ 630	$ 267	$ 424
Other Comprehensive Income, Amounts arising during the year:
Gain on defined benefit plans, net of income taxes		7	4	1
Amortization of pension cost for nonqualified plans, net of income taxes		1	3	(3)
Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes		(26)	33	(2)
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]	(16)	7	5
Other Comprehensive (Loss) Income		(34)	47	1
Comprehensive Income		596	314	425
Comprehensive Income Attributable to Avangrid, Inc.		596	314	425
Avangrid, Inc [Member]
Net Income		630	267	424
Other Comprehensive Income, Amounts arising during the year:
Other Comprehensive (Loss) Income		(34)	47	1
Comprehensive Income		$ 596	$ 314	$ 425
[1]	Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	$ (15.8)	$ 20.9	$ (1.4)
Reclassification to net income of losses on cash flow hedges, income tax expense	11	4.9	4.1
Qualified Pension Plan [Member]
Gain (loss) on defined benefit plans, income tax expense (benefit)	4.3	2.2	0.6
Non-Qualified Pension Plans [Member]
Gain (loss) on defined benefit plans, income tax expense (benefit)	$ 0.4	$ 1.7	$ (1.9)

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2016		Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 91		$ 427
Accounts receivable and unbilled revenues, net	1,119		974
Accounts receivable from affiliates	25		70
Notes receivable from affiliates			6
Derivative assets	99		88
Fuel and gas in storage	246		307
Materials and supplies	132		98
Prepayments and other current assets	255		285
Regulatory assets	285		219
Total Current Assets	2,252		2,474
Property, plant and equipment, at cost	27,063	[1]	25,745	[2]
Less: accumulated depreciation	(6,986)	[3]	(6,372)	[4]
Net Property, Plant and Equipment in Service	20,077		19,373
Construction work in progress	1,471		1,338
Total Property, Plant and Equipment ($1,144 and $1,206 related to VIEs, respectively)	21,548		20,711
Equity method investments	387		385
Other investments	55		64
Regulatory assets	3,091		3,314
Other Assets
Goodwill	3,124		3,115
Intangible assets	538		556
Derivative assets	73		89
Other	241		35
Total Other Assets	3,976		3,795
Total Assets	31,309		30,743
Current Liabilities
Current portion of debt	349		206
Tax equity financing arrangements - VIEs	96		107
Notes payable	151		163
Notes payable to affiliates	10
Interest accrued	60		61
Accounts payable and accrued liabilities	1,096		830
Accounts payable to affiliates	218		90
Dividends payable	134
Taxes accrued	52		55
Derivative liabilities	75		91
Other current liabilities	279		285
Regulatory liabilities	192		147
Total Current Liabilities	2,712		2,035
Regulatory liabilities	1,753		1,841
Deferred income taxes regulatory	565		519
Other Non-current Liabilities
Deferred income taxes	2,976		2,798
Deferred income	1,483		1,553
Pension and other postretirement	1,106		1,202
Tax equity financing arrangements - VIEs	103		185
Derivative liabilities	78		94
Asset retirement obligations	161		184
Environmental remediation costs	398		406
Other	342		330
Total Other Non-current Liabilities	6,647		6,752
Non-current Debt	4,510		4,530
Total Non-current Liabilities	13,475		13,642
Total Liabilities	16,187		15,677
Commitments and Contingencies
Stockholders' Equity:
Common stock	3		3
Additional paid-in capital	13,653		13,653
Treasury Stock	(5)
Retained earnings	1,544		1,449
Accumulated other comprehensive loss	(86)		(52)
Total Stockholders’ Equity	15,109		15,053
Noncontrolling interests	13		13
Total Equity	15,122		15,066
Total Liabilities and Equity	31,309		30,743
Avangrid, Inc [Member]
Current Assets
Cash and cash equivalents	67		125
Accounts receivable from affiliates	66		602
Notes receivable from affiliates	1,908		453
Prepayments and other current assets	11		16
Total Current Assets	2,052		1,196
Other investments	14,097		14,093
Other Assets
Deferred income taxes	220		148
Other	3		4
Total other assets	223		152
Total Assets	16,372		15,441
Current Liabilities
Current portion of debt	8
Notes payable	150
Notes payable to subsidiaries	454		321
Interest accrued	6
Accounts payable and accrued liabilities	4		12
Accounts payable to subsidiaries	3		3
Interest accrued subsidiaries	29		1
Dividends payable	134
Taxes accrued	2		44
Other current liabilities	3		4
Total Current Liabilities	793		385
Other Non-current Liabilities
Other			3
Total Other Non-current Liabilities			3
Non-current Debt	470
Total Non-current Liabilities	470		3
Total Liabilities	1,263		388
Stockholders' Equity:
Common stock	3		3
Additional paid-in capital	13,653		13,653
Treasury Stock	(5)
Retained earnings	1,544		1,449
Accumulated other comprehensive loss	(86)		(52)
Total Stockholders’ Equity	15,109		15,053
Total Liabilities and Equity	$ 16,372		$ 15,441
[1]	Includes capitalized leases of $208 million primarily related to electric generation, distribution, transmission and other.
[2]	Includes capitalized leases of $178 million primarily related to electric generation, distribution, transmission and other.
[3]	Includes accumulated amortization of capitalized leases of $60 million.
[4]	Includes accumulated amortization of capitalized leases of $53 million.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Property, Plant and Equipment, VIEs		$ 21,548	$ 20,711
Common stock, par value		$ 0.01	$ 0.01
Common stock, authorized		500,000,000	500,000,000
Common stock, issued		309,600,439	309,491,082
Common stock, outstanding	[1]	308,993,149	308,864,609
Variable Interest Entity, Primary Beneficiary [Member]
Property, Plant and Equipment, VIEs		$ 1,144	$ 1,206
[1]	Par value of share amounts is $.01

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Flow from Operating Activities
Net Income	$ 630	$ 267	$ 424
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	804	695	629
Impairment of non-current assets		12	25
Accretion expenses	10	14	14
Regulatory assets/liabilities amortization	49	101	(38)
Regulatory assets/liabilities carrying cost	13	41	35
Pension cost	110	115	74
Stock-based compensation	1	6	5
Earnings from equity method investments	(7)		(12)
Amortization of debt (premium) cost	(28)	4	2
Gain on disposal of property and equity method investment	(33)
Unrealized losses (gains) on marked to market derivative contracts	(4)	10	(116)
Deferred taxes	377	87	261
Other non-cash items	(23)	(5)	(3)
Changes in operating assets and liabilities:
Accounts receivable and unbilled revenues	(158)	160	(1)
Inventories	46	4	58
Other assets	107	(39)	(100)
Cash distribution from equity method investments	14
Accounts payable and accrued liabilities	184	(10)	27
Other liabilities	(447)	(194)	(115)
Taxes accrued	(3)	21	(13)
Regulatory assets/liabilities	(81)	74	175
Net Cash Provided by Operating Activities	1,561	1,363	1,331
Cash Flow from Investing Activities
Capital expenditures	(1,707)	(1,082)	(1,030)
Contributions in aid of construction	69	38	43
Government grants		17	4
Acquisition of business, net of $48 million cash acquired		(547)
Proceeds from sale of equity method and other investment	57	3	31
Proceeds from sale of property, plant and equipment	50
Receipts from (payments to) affiliates	6	(6)	10
Cash distribution from equity method investments	6	12	19
Other investments and equity method investments, net	(8)	47	35
Net Cash Used in Investing Activities	(1,527)	(1,518)	(888)
Cash Flow from Financing Activities
Non-current note issuance	493	350
Repayments of non-current debt	(355)	(141)	(27)
Proceeds (repayments) of other short-term debt, net	(2)	10	(14)
Repayments of capital leases	(12)	(12)	(21)
Payments on tax equity financing arrangements	(88)	(102)	(119)
Contribution from noncontrolling interests			4
Dividends to noncontrolling interests		(3)	(3)
Repurchase of common stock	(5)
Issuance of common stock	(2)
Dividends paid	(401)
Net Cash (Used in) Provided by Financing Activities	(372)	102	(180)
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(338)	(53)	263
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	434	487	224
Cash, Cash Equivalents and Restricted Cash, End of Year	96	434	487
Cash and Cash Equivalents, Beginning of Year	427
Cash and Cash Equivalents, End of Year	91	427
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	229	132	133
Cash paid (refund) for income taxes	9	7	21
Avangrid, Inc [Member]
Cash Flow from Operating Activities
Net Income	630	267	424
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Earnings from equity method investments	(565)	(44)	(515)
Changes in operating assets and liabilities:
Net Cash Provided by Operating Activities	324	(380)	(32)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	(627)	317	(478)
Acquisition of subsidiary		(595)
Investments in subsidiaries	(533)
Return of capital from investments in subsidiaries	420	1,111	200
Other investments and equity method investments, net			11
Net Cash Used in Investing Activities	(740)	833	(267)
Cash Flow from Financing Activities
Proceeds (repayments) of short-term notes payable from subsidiaries, net	133	(331)	302
Proceeds from short-term notes payable	150
Non-current note issuance	483
Repurchase of common stock	(5)
Issuance of common stock	(2)
Dividends paid	(401)
Net Cash (Used in) Provided by Financing Activities	358	(331)	302
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(58)	122	3
Cash and Cash Equivalents, Beginning of Year	125	3
Cash and Cash Equivalents, End of Year	67	125	3
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	4	$ 20	25
Cash paid (refund) for income taxes	$ 71		$ (6)

Consolidated Statements of Cas8

Consolidated Statements of Cash Flows (Parenthetical) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)
Statement Of Cash Flows [Abstract]
Cash acquired from acquisition of business	$ 48

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Common stock	Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Stockholders' Equity	Non controlling Interests
Balance at Dec. 31, 2013		$ 12,051	$ 3	$ 11,375		$ 758	$ (100)	$ 12,036	$ 15
Balance, shares at Dec. 31, 2013	[1]	252,235,232
Net Income		$ 424				424		424
Other comprehensive income, net of tax		1					1	1
Comprehensive Income Attributable to Avangrid, Inc.		425
Capital contribution from noncontrolling interests		4							4
Dividends to noncontrolling interests		(3)							(3)
Balance at Dec. 31, 2014		$ 12,477	3	11,375		1,182	(99)	12,461	16
Balance, shares at Dec. 31, 2014	[1]	252,235,232
Net Income		$ 267				267		267
Other comprehensive income, net of tax		47					47	47
Comprehensive Income Attributable to Avangrid, Inc.		314
Issuance of common stock		$ 2,278		2,278				2,278
Issuance of common stock, shares	[1]	57,255,850
Common stock held in trust	[1]	(626,473)
Dividends to noncontrolling interests		$ (3)							(3)
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		$ 630				630		630
Other comprehensive income, net of tax		(34)					(34)	(34)
Comprehensive Income Attributable to Avangrid, Inc.		596
Dividends declared		$ (535)				(535)		(535)
Release of common stock held in trust	[1]	135,014
Issuance of common stock, issuance costs		$ (2)		(2)				(2)
Issuance of common stock, shares	[1]	109,357
Repurchase of common stock		$ (5)			$ (5)			(5)
Repurchase of common stock, shares	[1]	(115,831)
Stock-based compensation		$ 2		2				2
Balance at Dec. 31, 2016		$ 15,122	$ 3	$ 13,653	$ (5)	$ 1,544	$ (86)	$ 15,109	$ 13
Balance, shares at Dec. 31, 2016	[1]	308,993,149
[1]	Par value of share amounts is $.01

Consolidated Statements of Ch10

Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Statement Of Stockholders Equity [Abstract]
Common Stock, Par or Value Per Share	$ 0.01	$ 0.01
Other Comprehensive Income (Loss) Taxes	$ 22.1	$ 29.7	$ 1.4

Background and Nature of Operat

Background and Nature of Operations	12 Months Ended
	Dec. 31, 2016
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). Effective as of April 30, 2016, and its subsidiaries (UIL) were transferred to a wholly-owned subsidiary of Networks Reorganization On November 20, 2013, we completed a series of reorganizations (Reorganization) of entities under common control. The Reorganization included the transfer of ARHI from an affiliate of Iberdrola to AVANGRID, and the transfer of the principal operating utility companies from AVANGRID to Networks. AVANGRID and ARHI were acquired by Iberdrola in 2008 and 2007, respectively, and they have been under common control of Iberdrola for all periods presented. Networks was formed as part of the Reorganization in November 2013. Networks is a public utility sub-holding company operating under the Public Utility Holding Company Act of 2005 with operations in New York, Maine, Connecticut and Massachusetts. The wholly owned subsidiaries and the operating utility companies of Networks include: CMP Group - Central Maine Power Company (CMP), RGS - New York State Electric & Gas Corporation (NYSEG), Rochester Gas and Electric Corporation (RG&E), Maine Natural Gas Company (MNG), The United Illuminating Company (UI), The Southern Connecticut Gas Company (SCG), Connecticut Natural Gas Corporation (CNG) and The Berkshire Gas Company (BGC). UI is also a party to a joint venture with certain affiliates of NRG Energy, Inc. (NRG affiliates) pursuant to which UI holds 50% of the membership interests in GCE Holding LLC, whose wholly owned subsidiary, GenConn Energy LLC (collectively with GCE Holding LLC, GenConn) operates peaking generation plants in Devon, Connecticut (GenConn Devon) and Middletown, Connecticut (GenConn Middletown). ARHI is the sub-holding company of the unregulated energy business that includes the renewable energy and the gas trading and storage businesses. The transfer of a business among entities under common control is accounted for at carrying amount with retrospective adjustment of prior period financial statements similar to the manner in which a pooling-of-interest was accounted for under accounting principles generally accepted in the United States of America (U.S. GAAP). Acquisition of UIL On December 16, 2015 (acquisition date), UIL Holdings Corporation, a Connecticut corporation (UIL), became a wholly-owned subsidiary of AVANGRID as a result of the merger of Green Merger Sub, Inc., a Connecticut corporation and a wholly-owned subsidiary of AVANGRID (Merger Sub), with UIL, with Merger Sub surviving as a wholly-owned subsidiary of AVANGRID (the acquisition). The acquisition was effected pursuant to the Agreement and Plan of Merger, dated as of February 25, 2015, by and among AVANGRID, Merger Sub, and UIL. Following the completion of the acquisition, Merger Sub was renamed “UIL Holdings Corporation.” In connection with the acquisition, we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including those held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per each share of the common stock of UIL issued and outstanding at the acquisition date. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID and Iberdrola owned the remaining shares. See Note 4, Acquisition of UIL, for further details. The regulated utility businesses of UIL consist of the electric distribution and transmission operations of UI and the natural gas transportation, distribution and sales operations of SCG, CNG and BGC. UI is also a party to a joint venture with certain affiliates of NRG Energy, Inc. (NRG affiliates) pursuant to which UI holds 50% of the membership interests in GCE Holding LLC, whose wholly owned subsidiary, GenConn Energy LLC (collectively with GCE Holding LLC, GenConn) operates peaking generation plants in Devon, Connecticut (GenConn Devon) and Middletown, Connecticut (GenConn Middletown).

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2016
Basis of Presentation	Note 2. Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of AVANGRID and its consolidated subsidiaries Networks and ARHI. Consolidated accounts of UIL have been included in the consolidated financial statements of AVANGRID since December 16, 2015, the date of acquisition of UIL. All intercompany transactions and accounts have been eliminated in all periods presented. All share and per share information included in the consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend. Revision of estimated useful lives of wind power station assets at Renewables Renewables’ wind power station assets in service less salvage value, if any, are depreciated using the straight-line method over their estimated useful lives. Renewables’ effective depreciation rate, excluding decommissioning, was 4.0% in both 2015 and 2014. Renewables reviews the estimated useful lives of its fixed assets on an ongoing basis. In the first quarter of 2016, this review indicated that the actual lives of certain assets at wind power stations are expected to be longer than the previously estimated useful lives used for depreciation purposes. As a result, effective January 1, 2016, Renewables changed the estimates of the useful lives of certain assets from 25 years to 40 years, capped at the lease term if lower, to better reflect the estimated periods during which these assets are expected to remain in service. The weighted average useful life of our wind farm assets is now approximately 31 years. 0.12
Avangrid, Inc [Member]
Basis of Presentation	Note 1. Basis of Presentation Avangrid, Inc. (AVANGRID), formerly Iberdrola USA, Inc., is a holding company and conducts substantially all of its business through its subsidiaries. Substantially all of its consolidated assets are held by such subsidiaries. Accordingly, its cash flow and its ability to meet its obligations are largely dependent upon the earnings of these subsidiaries and the distribution of other payment of such earnings to in the form of dividends, loans or advances or repayment of loans and advances from it. These condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of AVANGRID and subsidiaries (AVANGRID Group). AVANGRID indirectly or directly owns all of the ownership interests of its significant subsidiaries. AVANGRID relies on dividends or loans from its subsidiaries to fund dividends to its primary shareholder. AVANGRID’s significant accounting policies are consistent with those of the AVANGRID Group. For the purposes of these condensed financial statements, AVANGRID’s wholly owned and majority owned subsidiaries are recorded based upon its proportionate share of the subsidiaries net assets. AVANGRID will file a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries for the 2016 tax period. Each subsidiary company is treated as a member of the consolidated group and determines its current and deferred taxes separately and settles its current tax liability or benefit each year directly with AVANGRID pursuant to a tax sharing agreement between AVANGRID and its members.

Summary of Significant Accounti

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates	Note 3. Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates Significant Accounting Policies We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our consolidated financial statements: (a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Investments in common stock where we have the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting. (b) Revenue recognition Revenue from the sale of energy by our regulated utilities is recognized in the period during which the sale occurs. The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. Revenues on sales of wholesale energy and energy related products and natural gas are recognized either when the service is provided or the product is delivered. We also provide natural gas storage services to customers. The natural gas remains the property of these customers at all times. Customers pay a two part rate that includes (i) a fixed fee reserving the right to store natural gas in our facilities and, (ii) a per unit rate for volumes actually injected into or withdrawn from storage. The fixed fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are injected into or withdrawn from our storage facilities. (c) Regulatory accounting We account for our regulated utilities operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing regulated services or products, and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the consolidated statements of income consistent with the recovery or refund included in customer rates. We believe that it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates. (d) Business combinations We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred by the acquirer to former owners of acquiree and the equity interests issued by the acquirer. Acquisition related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is recorded as goodwill. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. (e) Equity method investments Joint ventures that do not meet consolidation criteria are accounted for using the equity method. Earnings (losses) recognized under the equity method are reflected in the consolidated statements of income as “Earnings (losses) from equity method investments.” Dividends received from joint ventures are recognized as a reduction in the carrying amount of the investment and are not recognized as dividend income. (f) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment at least annually or more frequently if events occur or circumstances change that will more likely than not reduce the fair value of the reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which goodwill is tested for impairment. In assessing goodwill for impairment we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary (step zero). If it is determined, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass step zero or perform the qualitative assessment, but determine that it is more likely than not that its fair value is less than its carrying amount, a quantitative two step fair value based test is performed. Step one compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an allocation of fair value to the individual assets and liabilities using business combination accounting guidance to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than its carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in the consolidated statements of income as the expense category that is consistent with the function of the intangible assets. (g) Property, plant and equipment Property, plant and equipment are accounted for at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, the estimated cost of removal or reconditioning is recorded as an asset retirement obligation (ARO) and an equal amount is added to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities. Once certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs are capitalized. Development projects in construction are reviewed periodically for any indications of impairment. Assets are transferred from “Construction work in progress” to “Property, plant and equipment” when they are available for service. Wind turbine and related equipment costs, other project construction costs, and interest costs related to the project are capitalized during the construction period through substantial completion. AROs are recorded at the date projects achieve commercial operation. The cost of plant, and equipment in use is depreciated on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35 Hydroelectric power stations 35-90 Plant Wind power stations 25-40 Gas storage 25-40 Transport facilities 40-56 Distribution facilities 30-54 Equipment Conventional meters and measuring devices 15-27 Computer software 3-5 Other Buildings 50-75 Operations offices 4-50 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed of to accumulated depreciation. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs. (h) Impairment of long lived assets We evaluate property, plant, and equipment and other long lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow model. (i) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: ● Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. ● Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. ● Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. (j) Available for sale securities Securities that do not qualify as either securities held-to-maturity or trading securities, and which have a readily available fair value, are classified as securities available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported, net of taxes, in other comprehensive income or loss. (k) Derivatives and hedge accounting Derivatives are recognized on the balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Changes in the fair value of a derivative contract are recognized in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Other Comprehensive Income (OCI) and later reclassified into earnings when the underlying transaction occurs. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, hedge gains and losses previously recorded in OCI are immediately recognized in earnings. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. Changes in the fair value of electric and natural gas hedge contracts are recorded to derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities for our regulated operations. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. (l) Cash and cash equivalents Cash and cash equivalents comprises cash, bank accounts, and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on the consolidated balance sheets. (m) Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances, which are settled on a net basis. Receivables and payables subject to such agreements are presented in our consolidated balance sheets on a net basis. 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 without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 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 short term. The allowance for bad debts account is established by using both historical average loss percentages to project future losses, and a specific allowance is established for known credit issues. Amounts are written off when we believe that a receivable will not be recovered. (n) Tax equity financing arrangements-VIEs We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash and notes receivable. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as a liability in the consolidated balance sheets. Subsequently, this liability is amortized based on the cash and tax benefits provided to the tax equity investors. We evaluate whether an entity is a variable interest entity (VIE) whenever reconsideration events as defined by the accounting guidance occur (See Note 19). An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. (o) Debentures, bonds and bank borrowings Bonds, debentures and bank borrowings are recorded as a liability equal to the proceeds of the borrowings. The difference between the proceeds and the face amount of the issued liability is treated as discount or premium and is amortized as interest expense or income over the life of the instrument. Incremental costs associated with issuance of the debt instruments are deferred and amortized over the same period as debt discount or premium. Bonds, debentures and bank borrowings are presented net of unamortized discount, premium and debt issuance costs on the consolidated balance sheets. (p) Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas trading operations, we own natural gas that is stored in both self-owned and third-party owned underground storage facilities. This gas is recorded as inventory. Injections of inventory into storage are priced at the market purchase cost at the time of injection, and withdrawals of working gas from storage are priced at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at, or below market value. Inventories to support gas operations are reported on the balance sheet within “Fuel and gas in storage.” We also have materials and supplies inventories that are used for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at cost and reported on the balance sheets within “Materials and supplies.” Inventory items are combined for the statement of cash flow presentation purposes. (q) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings consistent with the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, amounts receivable are recognized as an offset to expenses in the consolidated statements of income in the period in which the expenses are incurred. (r) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting obligations arising from the transaction. It is our policy to defer such revenues on the consolidated balance sheets and amortize them to earnings consistent with the obligations. (s) Asset retirement obligations The fair value of the liability for an ARO and a conditional ARO is recorded in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long lived asset. The ARO is associated with our long lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains, and electricity generation facilities. The liability is adjusted periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation will be either settled at its recorded amount or a gain or a loss will be incurred. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. These are classified as accrued removal obligations. (t) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. Our environmental liabilities are recorded on an undiscounted basis. Our environmental liability accruals are expected to be paid through the year 2053. (u) Post employment and other employee benefits We sponsor defined benefit pension plans that cover the majority of our employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. For NYSEG, RG&E and UIL, we amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. For our other companies we use the standard amortization methodology under which amounts in excess of ten percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five year period. (v) Income tax AVANGRID will file a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries for the 2016 tax period. For the 2015 tax year, AVANGRID filed a consolidated federal income tax return, which included the UIL taxable income or loss for the period from December 17, 2015 to December 31, 2015. UIL filed a separate consolidated federal income tax return for the period from January 1, 2015 to December 16, 2015. AVANGRID filed a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries (excluding UIL), which are 80% or more owned for the 2014 tax period. UIL filed separate consolidated federal income tax returns including the income or loss of its subsidiaries for all tax years including the filed 2014 return. AVANGRID (excluding ARHI and UIL), and ARHI filed separate consolidated federal income tax returns that included the taxable income or loss of all their respective subsidiaries, which are 80% or more owned, for all tax periods prior to 2013. We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with generally accepted accounting principles for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. The investment tax credits are deferred when used and amortized over the estimated lives of the related assets. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. Valuation allowances are recorded to reduce deferred tax assets when it is not more-likely-than-not that all or a portion of a tax benefit will be realized. Deferred tax assets and liabilities are classified as non-current in the consolidated balance sheets. The excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital is recorded in “Taxes other than income taxes” and “Taxes accrued” in the accompanying consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” of the consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income. Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements. (w) Stock-based compensation Stock-based compensation represents costs related to stock-based awards granted to employees. In the third quarter of 2016 we early adopted all the amendments to ASC 718, Compensation - Stock Compensation, issued in March 2016, to account for our stock based awards. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begin at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier. Reclassifications Certain amounts have been reclassified in the consolidated statements of cash flow to conform to the 2016 presentation as well as in connection with retrospective adoption of amendments in the accounting standard related to presentation of restricted cash in the statement of cash flow. New Accounting Standards and Interpretations (a) Revenue from contracts with customers In May 2014 the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers (ASC 606), (b) Fair value measurement disclosures for certain investments In May 2015 the FASB issued amendments that affect reporting entities that elect to estimate the fair value of certain investments within scope using the net asset value (NAV) per share (or its equivalent) practical expedient, as specified. The amendments remove the requirement to categorize within the fair value hierarchy all investments for which the fair value is measured at NAV using the practical expedient. They also remove certain disclosure requirements for eligible investments and limit the required disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. Assets that calculate NAV per share (or its equivalent), but for which the practical expedient is not applied will continue to be included in the fair value hierarchy. The amendments are effective for public entities for fiscal years beginning after December 15, 2015, and interim periods w

Acquisition of UIL

Acquisition of UIL	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Acquisition of UIL	Note 4. Acquisition of UIL On December 16, 2015 (acquisition date), we completed our acquisition of UIL, a diversified energy company with its portfolio of regulated utility companies in Connecticut and Massachusetts that is expected to provide us with a greater flexibility to grow the combined regulated businesses through project development and create an enhanced platform to develop transmission and distribution projects in the Northeastern United States. In connection with the consummation of the acquisition we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including those held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $595 million in cash. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares. The acquisition was accounted for as a business combination. This method requires, among other things, that assets acquired and liabilities assumed in a business combination, with certain exceptions, be recognized at their fair values as of the acquisition date. As UIL’s common stock was publicly traded in an active market until the acquisition date, we determined that UIL’s common stock is more reliably measurable than the common stock of AVANGRID to determine the fair value of the consideration transferred in the transaction. The purchase consideration for UIL under the acquisition method is based on the stock price of UIL on the acquisition date multiplied by the number of shares issued by AVANGRID to the UIL shareowners after applying an equity exchange factor to the shares of vested restricted common stock of UIL (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other shares awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The “equity exchange factor” is the sum of one plus a fraction, (i) the numerator of which is the cash consideration and (ii) the denominator of which is the average of the volume weighted averages of the trading prices of UIL common stock on each of the ten consecutive trading days ending on (and including) the trading day that immediately precedes the closing date of the acquisition minus $10.50. The determination of the purchase price is based on a UIL stock price of $50.10 per share, which represents the closing stock price on the acquisition date. The fair value of shares of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business combination, which was computed as follows: (millions, except share and unit data) Common shares (1) 56,629,377 Price per share of UIL common stock as of the acquisition date $ 50.10 Subtotal value of common shares $ 2,837 Restricted stock units (2) 476,198 Other shares (3) 12,999 Equity exchange factor 1.2806 Total restricted and other shares (3) an equity exchange factor 626,473 Price per share used (5) $ 39.60 Subtotal value of restricted and other shares $ 25 Total shares of AVANGRID common stock issued to UIL shareowners (including held in trust as treasury stock) 57,255,850 Performance shares (4) 211,904 Equity exchange factor 1.2806 Total performance shares after applying an equity exchange factor 271,368 Price per share used (5) $ 39.60 Subtotal value of performance shares $ 11 Total consideration $ 2,873 (1) Based on UIL’s common shares outstanding on December 16, 2015. (2) Based on UIL’s shares of vested restricted stock. (3) Based on UIL’s restricted shares that vested upon the change in control. (4) Based on UIL’s vested performance shares award. (5) Based on the closing share price of UIL common stock on December 16, 2015, less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under the UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The following is a summary of the components of the consideration transferred to UIL’s shareowners: (millions, except share data) Cash ($10.50 x number of UIL common shares outstanding at the acquisition date - 56,629,377) $ 595 Equity 2,278 Total consideration $ 2,873 We also paid $37.5 million for transaction costs incurred in this business combination, which are recorded in “Operations and maintenance” in the consolidated statements of income for the year ended December 31, 2015. The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had been completed on January 1, 2014, the beginning of the comparable prior annual reporting period. The unaudited pro forma results include: (i) merger credit adjustments to operating revenue (see Merger Settlement Agreement below for further details); (ii) elimination of accrued transaction costs representing non-recurring expenses directly related to the transaction, and (iii) the associated tax impact on these unaudited pro forma adjustments. The unaudited pro forma results do not reflect any cost saving synergies from operating efficiencies or the effect of the incremental costs incurred in integrating the two companies. Accordingly, these unaudited pro forma results are presented for informational purpose only and are not necessarily indicative of what the actual results of operations of the combined company would have been if the acquisition had occurred at the beginning of the period presented, nor are they indicative of future results of operations: Year Ended December 31, 2015 2014 (millions) Revenue $ 5,958 $ 6,226 Net income $ 468 $ 539 The revenue and net (loss) of UIL since the acquisition date included in the consolidated statements of income for the year ended December 31, 2015 were $36 million and $(36) million, respectively (see Merger Settlement Agreement below for further details). We finalized the valuation of the assets acquired and liabilities assumed within the measurement period during 2016. For the majority of UIL’s assets and liabilities, primarily property, plant and equipment, fair value was determined to be the respective carrying amounts of the predecessor entity. UIL’s operations are conducted in a regulated environment where the regulatory authority allows an approved rate of return on the carrying amount of the regulated asset base. Measurement period adjustments that were recognized in the year ended December 31, 2016 relate to the adjustments of the allocation of the purchase price to the following: equity method investments; contracts; debt; contingent liabilities, including those related to certain environmental sites; income taxes; non-regulated property, plant and equipment and goodwill. The following is a summary of the allocation of the purchase price as of the acquisition date and measurement period adjustments recognized in the year ended December 31, 2016: Provisional amounts reported in 2015 Measurement period adjustments Finalized amounts (millions) Current assets, including cash of $48 million $ 500 $ (7 ) $ 493 Other investments 114 22 136 Property, plant and equipment 3,552 (5 ) 3,547 Regulatory assets 966 36 1,002 Other assets 52 — 52 Current liabilities (493 ) — (493 ) Regulatory liabilities (493 ) — (493 ) Non-current debt (1,878 ) (27 ) (1,905 ) Other liabilities (1,201 ) (30 ) (1,231 ) Total net assets acquired at fair value 1,119 (11 ) 1,108 Goodwill – consideration transferred in excess of fair value assigned 1,754 11 1,765 Total consideration $ 2,873 $ 2,873 Goodwill generated from the acquisition of UIL increased by $11 million to the total amount of $1,765 million as of the acquisition date as a result of the finalization of the purchase price allocation. Goodwill generated from the acquisition of UIL has been assigned to the reporting units under the Networks reportable segment and is primarily attributable to expected future growth of the combined regulated businesses and enhanced platform to develop transmission and distribution projects in the Northeastern United States. The goodwill generated from this acquisition is not deductible for tax purposes. Merger Settlement Agreement As part of the process of seeking and obtaining regulatory approval for the acquisition in Connecticut and Massachusetts, Iberdrola, S.A., AVANGRID and UIL reached settlement agreements with the Office of Consumer Counsel in Connecticut and with the Attorney General of the Commonwealth of Massachusetts and the Department of Energy Resources in Massachusetts, which settlement agreements included commitments of actions to be taken after the transaction closed. As a result, the following commitments have been made in Connecticut, recognized in the period subsequent to the acquisition in 2015 unless otherwise noted, each of which is reasonably expected to be at a cost of $500,000 or more: • A one-time, $20 million rate credit to customers in 2016, allocated among UI, SCG and CNG customers based on the total number of retail customers. • Additional rate credits of $1.25 million/year for ten years (2018-2027) to CNG customers. • Additional rate credits of $0.75 million/year for ten years (2018-2027) to SCG customers. • $1.6 million in savings to SCG customers, associated with SCG making additional infrastructure capital investments over a three-year period without seeking recovery until the next SCG rate case. These amounts will be recorded by the Company as incurred in future periods. • Agreement not to seek to increase UI distribution base rates effective before January 1, 2017, and agreement not to seek to increase CNG and SCG distribution base rates effective before January 1, 2018. • Contribution of $2 million/year for three years to the DEEP, to stimulate investment in energy efficiency and clean energy technologies. • $5 million in benefits to customers resulting from UI recovering only the debt rate rather than the equity return for two years, on an increased $50 million of investment in storm resiliency programs. These amounts will be recorded by the Company as incurred in future periods. • Contribution of $1 million for disaster relief entities. • Maintaining charitable contribution at historical contribution levels (between $500,000 and $800,000) for at least four years. • Upon the resolution of all appeals of the PURA decision approving the acquisition, UI will withdraw its appeals of two PURA dockets relating to PURA’s disallowance of certain reconciliation amounts. The appeals were withdrawn by UI in June 2016. In connection with the acquisition proceeding, UI signed the consent order that, pursuant to the terms and conditions in the consent order, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. To the extent that the investigation and remediation is less than $30 million, UI would remit to the State of Connecticut the difference between such costs and $30 million for a public purpose as determined in the discretion of the Governor the Attorney General of Connecticut and the Commissioner of DEEP. Pursuant to the consent order UI is obligated to comply with the consent order, even if the cost of such compliance exceeds $30 million. 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 (See Note 14, Environmental Liabilities – English Station, for further details). As of December 31, 2016 and 2015 we reserved $28.3 million and $20.5 million, respectively, for this matter and have accrued the remaining $1.7 million and The difference of $7.8 million pre-tax has been reflected as the reversal of an expense in our 2016 results, reversing the amounts recorded in 2015, to adjust the allocation of the purchase price as a measurement period adjustment from the acquisition of UIL. The adjustment to the reserve during 2016 was recorded in the “Operations and maintenance” line of the consolidated statement of income as a measurement period adjustment based on additional information obtained for the site regarding circumstances of the site as of the acquisition date of UIL. As part of the final allocation of the purchase price we have determined a fair value of contingent liabilities of approximately $46.0 million relating to certain environmental sites. The following commitments have been made in Massachusetts, recognized in the period subsequent to the acquisition in 2015 unless otherwise noted, each of which is reasonably expected to be at a cost of $500,000 or more: • Customers of BGC will receive a total of $4.0 million in rate credits, to be spread over the months of November through April 2016-2017 and November through April 2017-2018. • BGC will contribute $1 million to alternative heating programs. • BGC will not seek to increase distribution base rates effective before June 1, 2018. As a result of the merger settlement agreement we have recorded $44 million as regulatory liabilities relating to the rate credits and an additional $19.8 million as liabilities, which primarily resulted in the net loss for UIL in the period following the acquisition date in 2015.

Industry Regulation

Industry Regulation	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Industry Regulation	Note 5. Industry Regulation Electricity and Natural Gas Distribution – Maine and New York The Maine distribution rate stipulation, the Maine transmission Federal Energy Regulatory Commission (FERC) Return on Equity (ROE) case, the New York rate plans, Reforming Energy Vision (REV), and the New York Transmission Company (New York TransCo) filings are some of the most important specific regulatory processes that affect Networks. The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to regulated activities in the U.S. are approved by the regulatory commissions of the different states and are based on the cost of providing service. The revenues of each regulated utility are set to be sufficient to cover all its operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable ROE. Energy costs that are set on the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York revenues that allow a utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting in future tariff reductions. Each of the four Networks’ New York and Maine supply companies must comply with regulatory procedures that differ in form but in all cases conform to the basic framework outlined above. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection, and automatic adjustments for exceptional costs incurred and efficiency incentives. CMP Distribution Rate Stipulation and New Renewable Source Generation On May 1, 2013, CMP submitted its required distribution rate request with the Maine Public Utilities Commission (MPUC). On July 3, 2014, after a fourteen month review process, CMP filed a rate stipulation agreement on the majority of the financial matters with the MPUC. The stipulation agreement was approved by the MPUC on August 25, 2014. The stipulation agreement also noted that certain rate design matters would be litigated, which the MPUC ruled on October 14, 2014. The rate stipulation agreement provided for an annual CMP distribution tariff increase of 10.7% or $24.3 million. The rate increase was based on a 9.45% ROE and 50% equity capital. CMP was authorized to implement a Rate Decoupling Mechanism (RDM) which protects CMP from variations in sales due to energy efficiency and weather. CMP also adjusted its storm costs recovery mechanism whereby it is allowed to collect in rates a storm allowance and to defer actual storm costs when such storm event costs exceed $3.5 million. CMP and customers share storm costs that exceed a certain balance on a fifty-fifty basis, with CMP’s exposure limited to $3.0 million annually. CMP has made a separate regulatory filing for a new customer billing system replacement. In accordance with the stipulation agreement, a new billing system is needed and CMP made its filing on February 27, 2015 to request a separate rate recovery mechanism. On October 20, 2015, the MPUC issued an order approving a stipulation agreement authorizing CMP to proceed with the customer billing system investment. The approved stipulation allows CMP to recover the system costs effective with its implementation, currently expected in mid-2017. The rate stipulation does not have a predetermined rate term. CMP has the option to file for new distribution rates at its own discretion. The rate stipulation does not contain service quality targets or penalties. The rate stipulation also does not contain any earning sharing requirements. Under Maine law 35-A M.R.S.A §§ 3210-C, 3210-D, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of energy, capacity or Renewable Energy Certificates, or RECs, from qualifying resources. The MPUC is further authorized to order Maine Transmission and Distribution Utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreen’s 60 MW Rollins wind farm in Penobscot County, Maine. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. In accordance with subsequent MPUC orders, CMP periodically auctions the purchased Rollins energy to wholesale buyers in the New England regional market. Under applicable law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under M.R.S.A §3210-C and has tentatively accepted long-term proposals from other sellers, these selections have not yet resulted in additional currently effective contracts with CMP. Transmission - FERC ROE Proceeding See Note 13, Commitments and Contingent Liabilities, for a further discussion. CMP’s and UI’s transmission rates are determined by a tariff regulated by the FERC and administered by ISO New England, Inc. (ISO-NE). Transmission rates are set annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses, and for a return of and on investment in assets. On December 28, 2015, the FERC issued an order instituting section 206 proceedings and establishing hearing and settlement judge procedures. Pursuant to section 206 of the FPA, the FERC instituted proceedings because it found that ISO-NE Transmission, Markets, and Services Tariff is unjust, unreasonable, and unduly discriminatory or preferential. The FERC stated that ISO-NE’s Tariff lacks adequate transparency and challenge procedures with regard to the formula rates for ISO-NE Participating Transmission Owners, including UI, Maine Electric Power Corporation (MEPCO) and CMP. The FERC also found that the current Regional Network Service, or RNS and Local Network Service, or LNS, formula rates appear to be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful as the formula rates appear to lack sufficient detail in order to determine how certain costs are derived and recovered in the formula rates. A settlement judge has been appointed and a settlement conference has convened. We are unable to predict the outcome of this proceeding at this time. NYSEG and RG&E Rate Plans On September 16, 2010, the New York Public Service Commission (NYPSC) approved a new rate plan for electric and natural gas service provided by NYSEG and RG&E effective from August 26, 2010 through December 31, 2013. The rate plans contain continuation provisions beyond 2013 if NYSEG and RG&E do not request new rates to go into effect and the current base rates will stay in place. The rates stayed effective until May 1, 2016, at which time a newly approved rate plan became effective. The 2010 revenue requirements were based on a 10% allowed ROE applied to an equity ratio of 48%. If annual earnings exceed the allowed return, a tiered Earnings Sharing Mechanism (ESM) will capture a portion of the excess for the ratepayers’ benefit. The ESM is subject to specified downward adjustments if NYSEG and RG&E fail to meet certain reliability and customer service measures. Key components of the rate plan include electric reliability performance mechanisms, natural gas safety performance measures, customer service quality metrics and targets, and electric distribution vegetation management programs that establish threshold performance targets. There will be downward revenue adjustments if NYSEG and RG&E fail to meet the targets. The 2010 rate plans established revenue decoupling mechanism (RDM), intended to remove company disincentives to promote increased energy efficiency. Under RDM, electric revenues are based on revenue per customer class rather than billed revenue, while natural gas revenues are based on revenue per customer. Any shortfalls or excesses between billed revenues and allowed revenues will be accrued for future recovery or refund. In August 2010, NYSEG began amortizing $15.2 million per year of its $303.9 million theoretical excess depreciation reserve. On September 1, 2012, RG&E began amortizing $5.3 million per year of its $105 million theoretical excess depreciation reserve. Both amortization amounts reflect a twenty year amortization period. Theoretical excess depreciation is the difference between actual accumulated depreciation taken to date and a theoretical reserve. The actual accumulated depreciation is the result of depreciation rates allowed in prior rate orders based on estimates of useful lives and net salvage values as determined in those cases. The theoretical reserve is the amount that would have accumulated if the depreciation rates in the new rate plan had been in place for the entire useful lives of the affected assets. Differences between the actual reserve and the theoretical reserve are normal aspects of utility ratemaking. The usual treatment is to flow any excess or deficiency back as an adjustment to depreciation expense over the remaining life of the property. However, in accordance with the new rate plan, NYSEG and RG&E moderate electric rates by recording the theoretical reserve amortization as a debit to accumulated depreciation and a credit to other revenues, and normalize a portion of the amortization from a tax perspective. On May 20, 2015, NYSEG and RG&E filed electric and gas rate cases with the NYPSC. The companies requested rate increases for NYSEG electric, NYSEG gas and RG&E gas. RG&E electric proposed a rate decrease. On February 19, 2016, NYSEG, RG&E and other signatory parties filed a Joint Proposal (proposal) with the NYPSC for a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2016. The proposal, which was approved by the NYPSC on June 15, 2016, balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The proposal reflects many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increase in the proposal can be summarized as follows: May 1, 2016 May 1, 2017 May 1, 2018 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 29.6 4.10 % $ 29.9 4.10 % $ 30.3 4.10 % NYSEG Gas 13.1 7.30 % 13.9 7.30 % 14.8 7.30 % RG&E Electric 3.0 0.70 % 21.6 5.00 % 25.9 5.70 % RG&E Gas 8.8 5.20 % 7.7 4.40 % 9.5 5.20 % The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas is 9.00%. The equity ratio for each company is 48%. The proposal includes an Earnings sharing mechanism (ESM) applicable to each company. The customer share of earnings would increase at higher ROE levels, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% of ROE, respectively, in the first rate year. Earnings sharing is based on the lower of actual equity of 50%. Earnings thresholds increase in subsequent rate years. The proposal reflects the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($21.4 million annually for NYSEG Electric and $2.5 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds. The proposal maintains NYSEG’s and RG&E’s current electric reliability performance measures (and associated potential negative revenue adjustments for failing to meet established performance levels) which include the system average interruption frequency index (SAIFI) and the customer average interruption duration index (CAIDI). The Proposal also modifies certain gas safety performance measures at the companies, including those relating to the replacement of leak prone main, leak backlog management, emergency response, and damage prevention. The proposal establishes threshold performance levels for designated aspects of customer service quality and continues and expands NYSEG’s and RG&E’s bill reduction and arrears forgiveness Low Income Programs with increased funding levels included in the proposal. The proposal provides for the implementation of NYSEG’s Energy Smart Community (“ESC”) Project in the Ithaca region which will serve as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project will be supported by NYSEG’s planned Distribution Automation upgrades and Advanced Metering Infrastructure (AMI) implementation for customers on circuits in the Ithaca region. The companies will also pursue Non-Wires Alternative projects as described in the proposal. Other REV-related incremental costs and fees will be included in the Rate Adjustment Mechanism (RAM) to the extent cost recovery is not provided for elsewhere. Under the proposal, each company will implement the RAM, which will be applicable to all customers, to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG Electric Pole Attachment revenues. The proposal provides for partial or full reconciliation of certain expenses including, but not limited to: pensions, other postretirement benefits; property taxes; variable rate debt and new fixed rate debt; gas research and development; environmental remediation costs; Major Storms; nuclear electric insurance limited credits; economic development; and Low Income Programs. The proposal also includes a downward-only Net Plant reconciliation. In addition, the proposal includes downward-only reconciliations for the costs of: electric distribution and gas vegetation management; pipeline integrity; and incremental maintenance. The proposal provides that NYSEG and RG&E continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis. Electric and Gas regulated utilities – Connecticut and Massachusetts The distribution rates and allowed ROEs for Networks’ regulated utilities in Connecticut and Massachusetts are subject to regulation by the Connecticut Public Utilities Regulatory Authority (PURA) and the Massachusetts Department of Public Utilities (DPU), respectively. Under Connecticut law, UI’s retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the GSC charge on their bills. UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2017, 80% of its standard service load for the second half of 2017 and 20% of its standard service load for the first half of 2018. Supplier of last resort service is procured on a quarterly basis, however, from time to time there are no bidders in the procurement process for supplier of last resort service and in such cases UI manages the load directly. 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 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. On January 22, 2014, PURA approved new base delivery rates for CNG, with an effective date of January 10, 2014, which, among other things, approved an allowed ROE of 9.18%, a decoupling mechanism, and two separate ratemaking mechanisms that reconcile actual revenue requirements related to CNG’s cast iron and bare steel replacement program and system expansion. Additionally, the final decision requires the establishment of an earnings sharing mechanism by which CNG and customers share on a 50/50 basis all earnings above the allowed ROE in a calendar year. In accordance with the approval by PURA of the acquisition, SCG and CNG agreed not to initiate a rate case for new rates effective before at least January 1, 2018. BGC’s rates are established by the DPU. BGC’s 10-year rate plan, which was approved by the DPU and included an approved ROE of 10.5%, expired on January 31, 2012. BGC continues to charge the rates that were in effect at the end of the rate plan. In accordance with the approval by the DPU of the acquisition, BGC agreed not to initiate a rate case for new rates effective before at least June 1, 2018. REV In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide ranging initiative to reform New York state’s energy industry and regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources, such as micro grids, on-site power supplies and storage. REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this initiative involves a collaborative process to examine the role of distribution utilities in enabling market based deployment of distributed energy resources to promote load management and greater system efficiency, including peak load reductions. NYSEG and RG&E are participating in the initiative with other New York utilities and are providing their unique perspective. The NYPSC issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform (DSP) provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016. The companies filed the DSIP, which also included information regarding the potential deployment of Automated Metering Infrastructure (AMI) across its entire service territory. The companies, in December 2016, filed a petition to the NYPSC requesting approval for cost recovery associated with the full deployment of AMI, and a collaborative associated with this petition is expected to begin in the first quarter of 2017. Other various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include the Clean Energy Standard, Value of DER and Net Energy Metering, Demand Response Tariffs, and Community Choice Aggregation. As part of the Clean Energy Standard proceeding, all electric utilities were ordered to begin payments to NYSERDA for Renewable Energy Credits and Zero Emissions Credits beginning in 2017. Track 2 of the REV initiative is also underway, and through a NYPSC Staff Whitepaper review process, is examining potential changes in current regulatory, tariff, market design and incentive structures which could better align utility interests with achieving New York state and NYPSC’s policy objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in May 2016, and includes guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs, and data utilization and security. The companies, in December 2016, filed a proposal for the implementation of EAMs in the areas of System Efficiency, Energy Efficiency, Interconnections, and Clean Air. A collaborative process to review the companies’ petition is expected to begin in the first quarter of 2017. Ginna Reliability Support Service Agreement Ginna Nuclear Power Plant, LLC (GNPP), which is a subsidiary of Constellation Energy Nuclear Group, LLC (CENG), owns and operates the R.E. Ginna Nuclear Power Plant (Ginna Facility and together with GNPP, Ginna), a 581 MW single-unit pressurized water reactor located in Ontario, New York. In May 2014, the New York Independent System Operator (NYISO) produced a Reliability Study, confirming that the Ginna Facility needs to remain in operation to avoid bulk transmission and non-bulk local distribution system reliability violations in 2015 and 2018. In July, 2014, GNPP filed a petition requesting that the NYPSC initiate a proceeding to examine a proposal for the continued operation of the Ginna Facility. In November 2014, the NYPSC ruled that GNPP had demonstrated that the Ginna Facility is required to maintain system reliability and that its actions with respect to meeting the relevant retirement notice requirements were satisfactory. The NYPSC also accepted the findings of the 2014 Reliability Study and stated that it established “the reliability need for continued operation of the Ginna Facility that is the essential prerequisite to negotiating a Reliability Support Services Agreement (RSSA).” As such, the NYPSC ordered RG&E and GNPP to negotiate an RSSA. On February 13, 2015, RG&E submitted to the NYPSC an executed RSSA between RG&E and GNPP. RG&E requested that the NYPSC accept the RSSA and approve cost recovery by RG&E from its customers of all amounts payable to GNPP under the RSSA utilizing the cost recovery surcharge mechanism. On October 21, 2015, RG&E, GNPP, New York Department of Public Service, Utility Intervention Unit and Multiple Intervenors filed a Joint Proposal with the NYPSC for approval of the RSSA, as modified. The Joint Proposal provides a term of the RSSA from April 1, 2015 through March 31, 2017. RG&E shall make monthly payments to Ginna in the amount of $15.4 million. RG&E will be entitled to 70% of revenues from Ginna’s sales into the NYISO energy and capacity markets, while Ginna will be entitled to 30% of such revenues. The signatory parties recommend that the NYPSC authorize RG&E to implement a rate surcharge effective January 1, 2016, to recover amounts paid to Ginna pursuant to the RSSA. RG&E's payment obligation to Ginna did not begin until the rate surcharge was in effect and FERC issued an order authorizing the FERC Settlement agreement in the Settlement Docket. RG&E will use deferred rate credit amounts (regulatory liabilities) to offset the full amount of the Deferred Collection Amount (including carrying costs), plus credit amounts to offset all RSSA costs that exceed $2.3 million per month, not to exceed a total use of credits in the amount of $110 million, applicable through June 30, 2017. To the extent that the available credits are insufficient to satisfy the final payment from RG&E to Ginna then the RSSA surcharge would continue past March 31, 2017, to recover up to $2.3 million per month until the final payment has been recovered by RG&E from ratepayers. In the month following the expiration of the term on March 31, 2017, Ginna shall prepare and issue an invoice to RG&E for, and RG&E shall pay to Ginna, a one-time payment in the amount of $11.5 million, which will be recovered from ratepayers. If Ginna continues to deliver energy to the NYISO transmission system or makes available capacity to the NYISO markets after seventy-five days following March 31, 2017, Ginna shall pay RG&E a capital recovery balance in eight quarterly installments as long as Ginna is continuing to deliver energy or making available capacity throughout this period. The estimated capital recovery balance that is expected to be in place on March 31, 2017 is $20.1 million and will accrue interest unless amounts are prepaid by Ginna. The capital recovery balance will be refunded to ratepayers, to the extent collected, which is based on the term of the delivery of energy or capacity being made available by Ginna. On February 23, 2016, the NYPSC unanimously adopted the Joint Proposal in the Ginna RSSA proceeding as in the public interest. On March 1, 2016, FERC issued an Order approving the contested Settlement agreement, subject to conditions. New York TransCo Networks holds an approximately 20% ownership interest in the New York TransCo, LLC (New York TransCo). New York TransCo was established by the New York transmission utilities to develop, own, and operate electric transmission in New York. In December 2014, New York TransCo filed for regulatory approval of its rates, terms, and conditions with the FERC. The filing requests a formula base ROE of 10.6%, one-hundred fifty basis points ROE incentives, construction work in progress, a formula rate mechanism, and a proposed cost allocation . Various parties, including the NYPSC, have protested the filing with the FERC, including the base ROE, the ROE incentives, and the cost allocation. New York TransCo will not make final decisions on transmission project development until a FERC decision. On April 2, 2015, the FERC issued an order granting, inter alia, New York TransCo’s owners’ request for a 50 basis point adder for New York TransCo’s membership in the NYISO regional transmission organization (RTO), subject to the adder being capped within the zone of reasonableness after a determination of where within that zone its base level ROE should be set. The FERC also set the formula rate and base ROE issue for hearing and settlement judge procedures. In addition, the FERC rejected New York TransCo’s owners’ cost allocation method for the Transmission Owner Transmission Solutions (TOTS) Projects because it would allocate costs to Power Supply Long Island (LIPA) and New York Power Authority (NYPA) that they did not voluntarily agree to pay. On November 5, 2015, the New York Transco’s owners, filed the Settlement with the FERC to resolve all outstanding issues associated with the TOTS Projects, including issues related to the TOTS Projects that were set for hearing and issues pending on rehearing. The issues regarding certain other projects remain pending. The Settlement addressed the financial terms that are components of New York TransCo’s revenue requirement for the proposed TOTS Projects, including the base ROE of 9.50%, and a 50-basis point ROE adder, the capital structure of 53%, and the cost allocation under the New York Independent System Operator, Inc. (NYISO) Open Access Transmission Tariff (OATT) for the TOTS Projects. On March 17, 2016, the FERC approved the Settlement. Minimum Equity Requirements for Regulated Subsidiaries Our regulated utility subsidiaries of Maine and New York (NYSEG, RG&E, CMP and MNG) are each subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements, each of NYSEG, RG&E, CMP and MNG must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis, each utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that may be paid and may, under certain circumstances, require that the parent contribute equity capital. The regulated utility subsidiaries are prohibited by regulation from lending to unregulated affiliates. The regulated utility subsidiaries have also agreed to minimum equity ratio requirements in certain borrowing agreements. These requirements are lower than the regulatory requirements. Pursuant to agreements with the relevant utility commission, UI, SCG, CNG and BGC are restricted from paying dividends if paying such dividend would result in a common equity ratio lower than 300 basis points below the equity percentage used to set rates in the most recent distribution rate proceeding as measured using a trailing 13-month average calculated as of the most recent quarter end. In addition, UI, SCG, CNG and BGC are prohibited from paying dividends to their parent if the utility’s credit rating as rated by any of the three major credit rating agencies, falls below investment grade, or if the utility’s credit rating, as determined by two of the three major credit rating agencies falls to the lowest investment grade and there is a negative watch or review downgrade notice. We had restricted net assets of approximately $4,291 million associated with the minimum equity requirements as of December 31, 2016. Movement of capital from our wholly owned unregulated subsidiaries is unrestricted. New Renewable Source Generation Under Connecticut law Public Act (PA 11-80), Connecticut electric utilities are required to enter into long-term contracts to purchase Connecticut Class I Renewable Energy Certificates, or RECs, On October 23, 2013, PURA approved UI’s renewable connections program filed in accordance with PA 11-80, through which UI will develop up to 10 MW of renewable generation. The costs for this program will be recovered on a cost of service basis. PURA established a base ROE to be calculated as the greater of: (A) the current UI authorized distribution ROE (currently 9.10%) plus 25 basis points and (B) the current authorized distribution ROE for Connecticut Light and Power Company, or CL&P (currently 9.17%), less target equivalent market revenues (reflected as 25 basis points). In addition, UI will retain a percentage of the market revenues from the project, which percentage is expected to equate to approximately 25 basis points on a levelized basis over the life of the project. UI expects the cost of this program, a planned 2.8 MW fuel cell facility in New Haven, solar photovoltaic and fuel cell facilities totaling 5 MW in Bridgeport, and a 2.2 MW fuel cell facility in Woodbridge to be approximately $47 million. Pursuant to Section 8 of Public Act 13-303, “An Act Concerning Connecticut’s Clean Energy Goals,” (PA 13-303), in January 2014, at DEEP’s direction, UI entered into three contracts for the purchase of RECs associated with an aggregate of 5.7 MW of energy production from biomass plants in New England. The costs of these agreements will be fully recoverable through electric rates. Equity Investment in Peaking Generation UI is party to a 50-50 joint venture with NRG affiliates in GenConn, which operates two peaking generation plants in Connecticut. The two peaking generation plants, GenConn Devon and GenConn Middletown, are both participating in the ISO-New England markets. PURA has approved revenue requirements for the period from January 1, 2017 through December 31, 2017 of $28.8 million and $35.7 million for GenConn Devon and GenConn Middletown, respectively. PURA has ruled previously that GenConn project capital costs incurred were prudently incurred. Such costs are included in the 2017 approved revenue requirements.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Note 6. 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 other 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 NYPSC approved the proposal in connection with a three five ten 16.5 126 fifty Current and non-current regulatory assets as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 22 $ 8 Pension and other post-retirement benefits 7 13 Storm costs 40 8 Temporary supplemental assessment surcharge 4 7 Reliability support services 27 — Revenue decoupling mechanism 15 6 Transmission revenue reconciliation mechanism 12 5 Electric supply reconciliation 13 — Hedges losses 10 37 Contracts for differences 14 18 Hardship programs 16 13 Deferred property tax 10 — Plant decommissioning 6 — Deferred purchased gas 14 12 Deferred transmission expense 13 12 Environmental remediation costs 14 37 Other 48 43 Total Current Regulatory Assets 285 219 Non-current Pension and other post-retirement benefits cost deferrals 134 151 Pension and other post-retirement benefits 1,320 1,509 Storm costs 187 251 Deferred meter replacement costs 32 34 Unamortized losses on reacquired debt 20 23 Environmental remediation costs 287 271 Unfunded future income taxes 542 549 Asset retirement obligations 18 24 Deferred property tax 33 45 Federal tax depreciation normalization adjustment 161 158 Merger capital expense target customer credit 11 15 Debt premium 151 141 Plant decommissioning 14 7 Contracts for differences 61 50 Hardship programs 18 29 Other 102 57 Total Non-current Regulatory Assets $ 3,091 $ 3,314 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG, 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 for 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. CMP’s total deferral, including carrying costs, was $2 million and $12 million as of December 31, 2016 and 2015, respectively. 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 December 31, 2016. “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. “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. “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) represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred 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 “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. “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. “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. “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. “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 December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Current Reliability support services (Cayuga) $ 3 $ 16 Non by-passable charges 22 7 Energy efficiency portfolio standard 45 33 Gas supply charge and deferred natural gas cost 6 6 Transmission revenue reconciliation mechanism 5 16 Pension and other post-retirement benefits 3 3 Pension and other post-retirement benefits cost deferrals 14 — Carrying costs on deferred income tax bonus depreciation 15 — Carrying costs on deferred income tax - Mixed Services 263(a) 5 — Yankee DOE refund 24 5 Merger-related rate credits 3 20 Revenue decoupling mechanism 9 14 Other 38 27 Total Current Regulatory Liabilities 192 147 Non-current Accrued removal obligations 1,117 1,084 Asset sale gain account 9 8 Carrying costs on deferred income tax bonus depreciation 95 116 Economic development 35 36 Merger capital expense target customer credit account 15 17 Pension and other post-retirement benefits 76 90 Positive benefit adjustment 42 51 New York state tax rate change 9 17 Post term amortization 3 25 Theoretical reserve flow thru impact 24 31 Deferred property tax 19 15 Net plant reconciliation 10 10 Variable rate debt 28 32 Carrying costs on deferred income tax - Mixed Services 263(a) 25 31 Rate refund – FERC ROE proceeding 22 21 Transmission congestion contracts 18 — Merger-related rate credits 21 24 Accumulated deferred investment tax credits 15 10 Asset retirement obligation 13 13 Earning sharing provisions 12 — Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge — 21 Low income programs 46 42 Unfunded future income taxes — 27 Non-firm margin sharing credits 7 8 Deferred income taxes regulatory 565 519 Other 73 93 Total Non-current Regulatory Liabilities $ 2,318 $ 2,360 “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 “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 “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 “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 “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 “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 “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five “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 “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. See Merger Settlement Agreement in Note 4 for further details. 20 “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.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 7. Goodwill and Intangible assets Goodwill by reportable segment as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Networks $ 2,744 $ 2,733 Renewables 380 380 Gas — — Other (a) — 2 Total $ 3,124 $ 3,115 (a) Does not represent a reportable segment. It includes Corporate. As of December 31, 2016, the gross amounts of goodwill were $2,744 million, for Networks reportable segment, $3,340 million for Renewables and Gas reportable segments and no goodwill for Corporate, (which does not represent a segment), with accumulated impairment losses of $2,960 million for Renewables and Gas reporting segments. As of December 31, 2015, the gross amounts of goodwill were $2,733 million, for Networks reportable segment, $3,340 million for Renewables and $2 million for Corporate, with accumulated impairment losses of $2,960 million for Renewables and Gas reporting segments. During the year ended December 31, 2015 goodwill in Networks reportable segment increased by $1,754 million due to acquisition of UIL based on preliminary allocation of the purchase price. During the year ended December 31, 2016, upon finalization of the valuation of assets acquired and liabilities assumed, goodwill in Networks reportable segment related to the acquisition of UIL increased by $11 million to a total amount of $1,765 million as of December 31, 2016 (See Note 4 – Acquisition of UIL – for further details). During the year ended December 31, 2016, we reversed $2 million of goodwill in Corporate as a result of the sale of our interest in equity investment (See Note 21). Goodwill Impairment Assessment For impairment testing purposes our reporting units are the same as operating segments, except for Networks, which contained three reporting units, Maine, New York and UIL. The goodwill for the Maine reporting unit resulted from the purchase of CMP by Energy East in 2000 and amounted to $325 million. Separately, the goodwill for the New York reporting unit resulted primarily from the purchase of RG&E by Energy East in 2002 and amounted to $654 million. The goodwill for the UIL reporting unit was generated from the acquisition of UIL on December 16, 2015 and amounted to $1,765 million as of December 31, 2016, based on the finalized valuation of assets acquired and liabilities assumed. Our annual impairment testing takes place as of October 1. Our step zero qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events, and events affecting a reporting unit. Our step one impairment testing includes various assumptions, primarily the discount rate, which is based on an estimate of our marginal, weighted average cost of capital, and forecasted cash flows. We test the reasonableness of the conclusions of our step one impairment testing using a range of discount rates and a range of assumptions for long term cash flows. 2016 We had no impairment of goodwill in 2016 as a result of our impairment testing. Networks Provided recent relevant events (acquisition of UIL in December 2015 and approval of the proposal by the NYPSC, see Note 4 and 5, respectively) we conducted a quantitative analysis (step one) in 2016. Based on the results of our step one impairment test the estimated fair value of each of the Networks reporting units was in excess of their respective carrying values. Renewables Based on the results of our step one impairment test for the Renewables reporting unit conducted in 2016, its estimated fair value was in excess of the carrying value. The assumptions used to estimate fair value were based on projections incorporated in our current operating plans as well as other available information. The current operating plans included significant assumptions and estimates associated with sales growth, profitability and related cash flows, along with cash flows associated with taxes and capital spending. The discount rate used to estimate fair value was risk adjusted in consideration of the economic conditions of the reporting unit. We also considered other assumptions that market participants may use. By their nature, projections are uncertain. Potential events and circumstances, such as declining wind energy output and prices obtained per MWh, changes in incentives established to promote renewable energies and increases in capital expenditures per MW could have an adverse effect on our assumptions. 2015 We had no impairment of goodwill in 2015 as a result of our impairment testing. Networks As a result of our step zero qualitative assessment, it was not more likely than not that the fair value of each of the Networks reporting units was less than its carrying amount and it was not necessary to perform the two-step goodwill impairment test. The step zero qualitative assessment was performed in 2015 considering the substantial excess of fair value over the carrying value that was demonstrated in the 2014 impairment test. The qualitative assessment considered key factors such as the level of interest rates, the regulatory environment including the allowed rate of return, and projections of future sales and capital spending. In 2015 the impairment testing of goodwill for Networks includes Maine and New York reporting units. Renewables Based on the results of our step one impairment test for the Renewables reporting unit conducted in 2015, its estimated fair value exceeded carrying value. The assumptions used to estimate fair value were based on projections incorporated in our current operating plans as well as other available information. The current operating plans included significant assumptions and estimates associated with sales growth, profitability and related cash flows, along with cash flows associated with taxes and capital spending. The discount rate used to estimate fair value was risk adjusted in consideration of the economic conditions of the reporting unit. We also considered other assumptions that market participants may use. By their nature, projections are uncertain. Potential events and circumstances, such as declining wind energy output and prices obtained per MWh, changes in incentives established to promote renewable energies and increases in capital expenditures per MW could have an adverse effect on our assumptions. Intangible assets Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets: As of December 31, 2016 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 319 $ (120 ) $ 199 Wind development 587 (254 ) 333 Other 17 (11 ) 6 Total Intangible Assets $ 923 $ (385 ) $ 538 As of December 31, 2015 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 324 $ (116 ) $ 208 Wind development 584 (243 ) 341 Other 15 (8 ) 7 Total Intangible Assets $ 923 $ (367 ) $ 556 Gas Storage rights are being amortized on a straight-line basis over a 40-year estimated life. Wind development costs, with the exception of future ‘pipeline’ development costs, are amortized on a straight-line basis in accordance with the life of the related assets. Amortization expense for the years ended December 31, 2016, 2015 and 2014 amounted to $25 million, $54 million and $66 million, respectively. We believe our future cash flows will support the recoverability of our intangible assets. We expect amortization expense for the five years subsequent to December 31, 2016, to be as follows: Year ending December 31, (Millions) 2017 $ 16 2018 16 2019 18 2020 17 2021 21 As a result of writing off fully amortized intangible assets relating to Gas Storage rights, $4.1 million and $6.5 million were removed from both cost and accumulated amortization during the years ended December 31, 2016 and 2015, respectively.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2016
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	Note 8. Property, Plant and Equipment Property, plant and equipment as of December 31, 2016, consisted of: As of December 31, 2016 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 10,343 $ 10,384 $ 20,727 Natural gas transportation, distribution and other 4,803 613 5,416 Other common operating property 877 43 920 Total Property, Plant and Equipment in Service (a) 16,023 11,040 27,063 Total accumulated depreciation (b) (3,970 ) (3,016 ) (6,986 ) Total Net Property, Plant and Equipment in Service 12,053 8,024 20,077 Construction work in progress 979 492 1,471 Total Property, Plant and Equipment $ 13,032 $ 8,516 $ 21,548 ( a ) Includes capitalized leases of $208 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $60 million. Property, plant and equipment as of December 31, 2015, consisted of: As of December 31, 2015 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 11,506 $ 10,058 $ 21,564 Natural gas transportation, distribution and other 2,673 651 3,324 Other common operating property 817 40 857 Total Property, Plant and Equipment in Service (a) 14,996 10,749 25,745 Total accumulated depreciation (b) (3,727 ) (2,645 ) (6,372 ) Total Net Property, Plant and Equipment in Service 11,269 8,104 19,373 Construction work in progress 1,094 244 1,338 Total Property, Plant and Equipment $ 12,363 $ 8,348 $ 20,711 ( a ) Includes capitalized leases of $178 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $53 million. Capitalized interest costs were $20 million, $13 million, and $12 million for the years ended December 31, 2016, 2015 and 2014, respectively. There was no impairment or write off recorded during the year ended December 31, 2016. We impaired or wrote off amounts of $12 million and $24 million for the years ended December 31, 2015 and 2014, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects in construction. Depreciation expense for the years ended December 31, 2016, 2015 and 2014, amounted to $779 million, $641 million and $563 million, respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 9. Asset retirement obligations AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities. The reconciliation of ARO carrying amounts for the years ended December 31, 2016 and 2015 consisted of: (Millions) As of December 31, 2014 $ 234 Liabilities settled during the year (16 ) Liabilities incurred during the year — Accretion expense 14 Revisions in estimated cash flows (48 ) As of December 31, 2015 $ 184 Liabilities settled during the year (7 ) Liabilities incurred during the year 3 Accretion expense 10 Revisions in estimated cash flows (29 ) As of December 31, 2016 $ 161 Several of the wind generation facilities have restricted cash for purposes of settling AROs. Restricted cash related to AROs was $2.0 million and $1.8 million as of December 31, 2016 and 2015, respectively. These amounts have been included as other non-current assets in the consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in the consolidated statements of income. We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains. As a result of the revision of the estimated useful lives of wind power station assets in 2016 updated weighted average lease terms were used to value AROs. This revision resulted in lower discounted AROs, which we estimate will result in approximately $3 million annual reduction in expense going forward.

Debt

Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Debt	Note 10. Debt Long- term debt as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2018-2045 $ 1,752 3.07%-10.60% $ 1,815 3.07%-10.60% Unsecured pollution control notes - fixed 2020 200 2.00%-2.375% 200 2.00%-2.375% Unsecured pollution control notes – variable 2032 62 1.32% 219 0.195%-1.181% Other various non-current debt - fixed 2017-2045 2,772 2.89%-10.48% 2,440 2.89%-10.48% Obligations under capital leases 2017-2023 104 4%-4.44% 87 4%-4.44% Unamortized debt issuance costs and discount (31 ) (25 ) Total Debt 4,859 4,736 Less: debt due within one year, included in current liabilities 349 206 Total Non-current Debt $ 4,510 $ 4,530 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $5,886 million. In November 2016, NYSEG issued $500 million in aggregate principal amount of 3.25% notes maturing in 2026. The proceeds of the offering were used to reduce balances owed to AVANGRID under an intercompany revolving demand note agreement, to refinance $100 million of NYSEG debt that matured on December 15, 2016, and to repurchase, at par value, $96 million of outstanding auction rate securities on December 19, 2016. On December 19, 2016, AVANGRID, its subsidiary, UIL, and The Bank of New York Mellon, entered into a supplemental indenture, pursuant to which AVANGRID assumed from UIL all the obligations under the indenture dated as of October 7, 2010 between UIL and The Bank of New York Mellon and all obligations relating to $450 million in aggregate principal amount of 4.625% notes due 2020 issued by the predecessor company to UIL in 2010. On December 27, 2016, UI repurchased, at par value, $64 million of auction rate securities using cash on hand and borrowing under an intercompany demand note agreement with AVANGRID. Non-current debt, including sinking fund obligations and capital lease payments, due over the next five years consists of: (Millions) 2017 2018 2019 2020 2021 Total $ 349 $ 180 $ 358 $ 723 $ 308 $ 1,918 We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were in breach of covenants or of any obligation that could trigger the early redemption of our debt as of December 31, 2016 and 2015. Fair Value of Debt The estimated fair value of debt amounted to $5,204 million and $4,985 million as of December 31, 2016 and 2015, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value 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 and $204 million as of December 31, 2016 and 2015, respectively, 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. Short-term Debt Outstanding Notes Payable AVANGRID had $161 million and $163 million of notes payable as of December 31, 2016 and 2015, respectively. As of December 31, 2015, the balance consisted of $160 million of borrowings under the UIL credit facility and $3 million in other notes payable. As of December 31, 2016 the balance consisted of $150 million of commercial paper, $10 million in notes payable to affiliates and $1 million in other notes payable. AVANGRID’s commercial paper program was established on May 13, 2016, has a limit of $1 billion and is backstopped by the AVANGRID credit facility described below. AVANGRID Credit Facility On April 5, 2016, AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC entered into a revolving credit facility with a syndicate of banks, or the AVANGRID credit facility, that provides for maximum borrowings of up to $1.5 billion in the aggregate. Under the terms of the AVANGRID credit facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit established by the banks. AVANGRID’s maximum sublimit is $1 billion, NYSEG, RG&E, CMP and UI have maximum sublimits of $250 million, CNG, and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $25 million. Under the AVANGRID credit facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. The facility fees will range from 10.0 to 17.5 basis points. The maturity date for the AVANGRID credit facility is April 5, 2021. As a condition of closing on the AVANGRID credit facility, three existing credit facilities were terminated: the AVANGRID revolving credit facility, which provided for maximum borrowings of up to $300M and had a scheduled termination date in May 2019; the joint utility revolving credit facility, to which NYSEG, RG&E and CMP were parties, which provided for borrowings of up to $600 million and which had a scheduled termination date in July 2018; the UIL credit facility, to which UIL, UI, SCG, CNG and BG were parties, which provided for maximum borrowings of $400 million and which had a scheduled termination date in November 2016. As of December 31, 2016 the AVANGRID credit facility is undrawn, but the capacity to borrow under the facility is reduced by the amount of outstanding commercial paper, leaving available credit of $1,350 million.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Note 11. 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 all 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 has a combination of Level 1 and Level 2 fair values for its electric energy derivative contracts. A portion of its electric load obligations 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. A portion of NYSEG’s electric energy derivative contracts are non-exchange traded contracts that are valued using inputs that are directly observable for the asset or liability, or indirectly observable through corroboration with observable market data and therefore we include the fair value in Level 2. ● 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 12 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. The financial instruments measured at fair value as of December 31, 2016 and 2015 consisted of: 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 ) As of December 31, 2015 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 39 $ — $ — $ — $ 39 Derivative assets Derivative financial instruments - power 10 81 48 (71 ) 68 Derivative financial instruments - gas 267 25 68 (280 ) 80 Contracts for differences — — 29 — 29 Total 277 106 145 (351 ) 177 Derivative liabilities Derivative financial instruments - power (43 ) (12 ) (14 ) 55 (14 ) Derivative financial instruments - gas (193 ) (40 ) (51 ) 212 (72 ) Contracts for differences — — (96 ) — (96 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (236 ) $ (52 ) $ (164 ) $ 267 $ (185 ) The reconciliations of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2016, 2015 and 2014 consisted of: (Millions) 2016 2015 2014 Fair value as of January 1, $ (19 ) $ 57 $ 53 Gains for the year recognized in operating revenues 67 33 11 Losses for the year recognized in operating revenues — (8 ) (1 ) Total gains or losses for the period recognized in operating revenues 67 25 10 Gains recognized in OCI 1 2 — Losses recognized in OCI — (3 ) (3 ) Total gains or losses recognized in OCI 1 (1 ) (3 ) Net change recognized in regulatory assets and liabilities (8 ) — — Purchases 3 (73 ) 14 Settlements (9 ) (14 ) (26 ) Transfers out of Level 3 (a) (4 ) (13 ) 9 Fair value as of December 31, $ 31 $ (19 ) $ 57 Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 67 $ 25 $ 10 (a) Transfers out of Level 3 were the result of increased observability of market data. For assets and liabilities that are recognized in the consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the years 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 December 31, 2016 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions with delivery periods Transactions are valued against forward market prices Observable and extrapolated forward gas and power prices not all of which can be NYMEX ($/MMBtu) $ 4.27 $ 7.37 $ 1.64 with delivery exceeding two on a corroborated by SP15 ($/MWh) $ 44.23 $ 80.28 $ 14.25 period > two years discounted market data for Mid C ($/MWh) $ 35.44 $ 83.93 $ 3.60 years basis identical or Cinergy ($/MWh) $ 36.40 $ 77.49 $ 18.53 similar products 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 12 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that 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 December 31, 2016 Risk of non-performance 0.68% - 0.81% Discount rate 1.47% - 2.45% Forward pricing ($ per MW) $3.15 - $9.55

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Note 12. 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 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 $12.3 million and $34.3 million as of December 31, 2016 and 2015, respectively. The loss reclassified from regulatory assets into income, which is included in electricity purchased, was $66.7 million, $46.9 million, and $21.3 million for the years ended December 31, 2016, 2015 and 2014, 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 assets for natural gas hedges was a gain of $3.5 million and a loss of $3.1 million as of December 31, 2016 and 2015, respectively. The loss reclassified from regulatory assets into income, which is included in natural gas purchased, was $1.9 million, $6.3 million, and $2.2 million for the years ended December 31, 2016, 2015 and 2014, respectively. Pursuant to PURA, UI and Connecticut’s other electric utility, CL&P, each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability). For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of December 31, 2016, UI has 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. As of December 31, 2015, UI has recorded a gross derivative asset of $29 million ($1 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $68 million, a gross derivative liability of $96 million ($61 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $1 million. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the year ended December 31, 2016 and for the period from December 17, 2015 to December 31, 2015, respectively, were as follows: Year Ended December 31, 2016 Period from December 17, 2015 to December 31, 2015 (Millions) Regulatory Assets - Derivative liabilities $ 7 $ 1 Regulatory Liabilities - Derivative assets $ 1 $ — The net notional volumes of the outstanding derivative instruments associated with Networks activities as of December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 6.7 Natural gas purchase contracts (Dth) 5.8 4.8 Fleet fuel purchase contracts (Gallons) 2.3 3.8 The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Networks activities as of December 31, 2016 and 2015, respectively, consisted of: 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 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 11 $ 18 $ — $ — Derivative liabilities — — (28 ) (68 ) 11 18 (28 ) (68 ) Designated as hedging instruments Derivative assets 3 6 3 6 Derivative liabilities (3 ) (6 ) (42 ) (7 ) — — (39 ) (1 ) Total derivatives before offset of cash collateral 11 18 (67 ) (69 ) Cash collateral receivable — — 37 — Total derivatives as presented in the balance sheet $ 11 $ 18 $ (30 ) $ (69 ) The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2016, 2015 and 2014, respectively, consisted of: Year Ended December 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) 2016 Interest rate contracts $ — Interest expense $ 8 Commodity contracts — Operating expenses 2 Total $ — $ 10 2015 Interest rate contracts $ — Interest expense $ 9 Commodity contracts (3 ) Operating expenses 3 Total $ (3 ) $ 12 2014 Interest rate contracts $ — Interest expense $ 9 Commodity contracts (4 ) Operating expenses 1 Total $ (4 ) $ 10 (a) Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the consolidated statements of income. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $76.7 million, $84.9 million, and $93.5 million for the years ended December 31, 2016, 2015 and 2014, respectively. We recorded $8.0 million, $8.6 million, and $8.9 million in net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2016, 2015 and 2014, respectively. We will amortize approximately $8.0 million of discontinued cash flow hedges in 2017. During the years ended December 31, 2016, 2015 and 2014, there was no ineffective portion for cash flow hedges. The unrealized loss of $0.4 million on hedge derivatives is reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2016. We expect that $0.4 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 (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 facility. 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 December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (MWh/Dth in Millions) Wholesale electricity purchase contracts 3 3 Wholesale electricity sales contracts 7 6 Foreign exchange forward purchase contracts — 4 Natural gas and other fuel purchase contracts 329 332 Financial power contracts 8 7 Basis swaps - purchases 49 67 Basis swaps - sales 45 80 The fair values of derivative contracts associated with Renewables and Gas activities as of December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (Millions) Wholesale electricity purchase contracts $ (2 ) $ (13 ) Wholesale electricity sales contracts 6 35 Foreign exchange forward purchase contracts — (1 ) Natural gas and other fuel purchase contracts 30 10 Financial power contracts 56 32 Basis swaps- purchases 3 1 Basis swaps- sales (2 ) (2 ) Total $ 91 $ 62 The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of December 31, 2016 and 2015, respectively, consisted of: 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 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 186 $ 113 $ 117 $ 4 Derivative liabilities (85 ) (14 ) (169 ) (29 ) 101 99 (52 ) (25 ) Designated as hedging instruments Derivative assets 56 13 — — Derivative liabilities — — (9 ) — 56 13 (9 ) — Total derivatives before offset of cash collateral 157 112 (61 ) (25 ) Cash collateral receivable (payable) (80 ) (41 ) — — Total derivatives as presented in the balance sheet $ 77 $ 71 $ (61 ) $ (25 ) The effect of trading and non-trading derivatives, respectively, associated with Renewables and Gas activities for the years ended December 31, 2016, 2015 and 2014 consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Wholesale electricity purchase contracts $ 3 $ 6 $ (9 ) Wholesale electricity sales contracts (7 ) (5 ) 9 Financial power contracts 4 — (2 ) Financial and natural gas contracts (22 ) (26 ) 125 Total (Loss) Gain $ (22 ) $ (25 ) $ 123 Years Ended December 31, 2016 2015 2014 (Millions) Wholesale electricity purchase contracts $ 9 $ (8 ) $ (8 ) Wholesale electricity sales contracts (20 ) (5 ) 15 Financial power contracts (10 ) 24 30 Natural gas and other fuel purchase contracts 34 18 (1 ) Total Gain $ 13 $ 29 $ 36 Such gains and losses are included in “Operating revenues” and in “Purchased power, natural gas and fuel used” operating expenses in the consolidated statements of income, depending upon the nature of the transaction. In 2015 we began designating those derivatives contracts at Renewables and Gas businesses that qualify as hedges. This designation was made prospectively, and in accordance with all the requirements of hedge accounting. The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2016 and 2015 consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income (Gain) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2016 Commodity contracts $ (42 ) Revenues $ (43 ) $ (42 ) $ (43 ) 2015 Commodity contracts $ 57 Revenues $ (2 ) Total $ 57 $ (2 ) (a) Changes in OCI are reported on a pre-tax basis. Amounts will be 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 $13.6 million of losses included in accumulated OCI at December 31, 2016 is expected to be reclassified into earnings within the next 12 months. During the years ended December 31, 2016 and 2015, we recorded a net loss of $6.8 million and a net gain $4.8 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges. We recorded $0.4 million and $2.3 million in net derivative gain related to discontinued cash flow hedge for the years ended December 31, 2016 and 2015. (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 December 31, 2016, UI would have had to post an aggregate of approximately $12.8 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 $20 million and $11 million as of December 31, 2016 and 2015, respectively. Derivative instruments settlements and collateral payments are included in “Other assets” and “Other liabilities” of operating activities in the consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of December 31, 2016 is $12 million, for which we have posted collateral.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Note 13. Commitments and Contingent Liabilities We are party to various legal disputes arising as part of our normal business activities. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. MNG Rate Case On March 5, 2015, MNG filed a rate case in order to further recover future investments and provide safe and adequate service. On May 3, 2016, all active parties to the case filed a stipulation that settled all matters at issue in the case and reflected a 10 34.6 9.55 50 15 14.55 6 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 seek 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 will thereby be affected by any FERC order resulting from the filed complaint. On June 19, 2014, the FERC issued its decision in Complaint I, establishing a methodology and setting an issue for a paper hearing. On October 16, 2014, FERC issued its final decision in the Complaint I setting the base ROE at 10.57%, and a maximum total ROE of 11.74% (base plus incentive ROE) 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 a 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 return. In June 2015 the NETOs filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. The appeal is currently pending, and we cannot predict the outcome of this appeal. 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 the 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 in mid-2017. 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 I, II and III is $21.6 million and $4.4 million, respectively, as of December 31, 2016. 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 11.24 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 6 year period). The Trial Court decision awards 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 Yankees to shareholders (including CMP and UI) to reduce retail customer charges. In January 2014 the government informed the Yankee Companies 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 the remaining storm regulatory asset balance. The remaining regulatory liability balance was applied to the GSC “working capital allowance” and will be returned to customers through the non-by-passable federally mandated congestion charge. In August 2013, the Yankees 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 has 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 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 approximate $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 provided a response 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 Staff issues. In the proposal approved by the NYPSC (see Note 5) the parties agreed that in full and final resolution of 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. Staff indicated in December 2016 that it had completed its review 2013 and 2014 compliance filings and no issues were identified. 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 Leases Operating lease expense relating to operational facilities, office building leases, and vehicle and equipment leases was $70.6 million, $47.7 million and $48.7 million for the years ended December 31, 2016, 2015 and 2014, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities was $22.2 million, $22.2 million and $20.4 million for the years ended December 31, 2016, 2015 and 2014, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses. On January 16, 2014, as required by the NYPSC, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga will operate and maintain the RSS units and manage and comply with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and capacity providers and will comply with dispatch instructions. NYSEG will pay Cayuga a monthly fixed price and will also pay for capital expenditures for specified capital projects. NYSEG will be entitled to a share of any capacity and energy revenues earned by Cayuga. We account for this arrangement as an operating lease. The net expense incurred under this operating lease was $37.8 million, $25.5 million and $19.8 million for the years ended December 31, 2016, 2015 and 2014, respectively. On December 31, 2014, we concluded the sale of our ten-percent undivided interest in Unit 1 of the Springerville power plant to Tucson Electric Power for $19.6 million. We had previously accounted for this plant as an operating lease. This transaction was recorded in “Other income and (expense).” On October 21, 2015, RG&E, GNPP and multiple intervenors filed a Joint Proposal with the regulator for approval of the modified RSS Agreement for the continued operation of the Ginna Facility through March 2017. RG&E shall make monthly payments to GNPP in the amount of $15.4 million. RG&E will be entitled to 70% of revenues from GNPP’s sales into the energy and capacity markets, while GNPP will be entitled to 30% of such revenues. We account for this arrangement as an operating lease. The net expense incurred under this operating lease was $114.9 million and $79.9 million for the years ended December 31, 2016 and 2015, respectively. Total future minimum lease payments as of December 31, 2016 consisted of: Year Operating Leases Capital Leases Total (Millions) 2017 $ 106 $ 30 $ 136 2018 28 6 34 2019 28 7 35 2020 26 7 33 2021 28 4 32 2022 and thereafter 487 50 537 Total $ 703 $ 104 $ 807 Power, Gas, and Other Arrangements Power and Gas Supply Arrangements – Networks NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and NYPA are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation. NYSEG, RG&E, SCG, CNG and BGC (collectively the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review. The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the US Gulf of Mexico region, in the Appalachia region and in Canada. The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months. Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system. Other arrangements include UI’s long-term contracts to purchase RECs. Power, Gas, and Other Arrangements – Renewables and Gas Gas purchase commitments include multi-year contracted storage and transport capacity contracts that allow the Gas business to participate in seasonal and locational gas price differentials. The agreements contain fixed payment obligations for the use of both storage and transport capacity throughout the U.S. Power purchase commitments include the following: (i) a 55MW Biomass Power Purchase Agreement (PPA) for 12 years (five years remaining) with a guaranteed output of 34.4MW flat and a schedule of fixed price rates depending on season and time of day, (ii) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers and (iii) a three year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (two years remaining). Power sales commitments include: (i) a 55MW Biomass off-take agreement for 12 years (five years remaining) with guaranteed annual production of 34.4MW flat with a schedule of fixed price rates depending on season and time of day, (ii) fixed price, fixed volume power sales off the Klamath Cogen facility in addition to tolling arrangements that have fixed capacity charges and (iii) fixed price, fixed volume renewable energy credit sales off merchant wind facilities. Forward purchases and sales commitments under power, gas, and other arrangements as of December 31, 2016 consisted of: Purchases Sales Year Gas Power Other Total Gas Power Other Total (Millions) 2017 $ 284 $ 168 $ 35 $ 487 $ 23 $ 132 $ 4 $ 159 2018 245 108 23 376 4 76 4 84 2019 205 68 14 287 5 53 1 59 2020 161 65 12 238 5 42 — 47 2021 127 52 12 191 — 33 — 33 Thereafter 520 379 109 1,008 — 26 — 26 Totals $ 1,542 $ 840 $ 205 $ 2,587 $ 37 $ 362 $ 9 $ 408 Guarantee Commitments to Third Parties As of December 31, 2016, we had approximately $2.6 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 December 31, 2016, neither we nor our subsidiaries have any liabilities recorded for these instruments. Property, Plant and Equipment We have made future commitments to purchase property, plant, and equipment in order to continue to develop and grow our business. The amount of such future commitments was $493 million as of December 31, 2016.

Environmental Liabilities

Environmental Liabilities	12 Months Ended
	Dec. 31, 2016
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Note 14. 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. 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 December 31, 2016. 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 December 31, 2016. 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 December 31, 2016 and 2015, 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 and $99 million, respectively. The liability to investigate and perform remediation at the known inactive MGP sites was $388 million and $397 million as of December 31, 2016 and 2015, 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 December 31, 2016 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 twenty-two former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share is 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 Idemnity 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. 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 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 and 2015 we reserved $28.3 million and $ 20.5 for this matter and have accrued the remaining $1.7 million and 9.5 The difference of $7.8 million pre-tax has been reflected as the reversal of an expense in our 2016 results, reversing the amounts recorded in 2015, to adjust the allocation of the purchase price as a measurement period adjustment from the acquisition of UIL. The adjustment to the reserve during 2016 was recorded in the “Operations and maintenance” line of the consolidated statement of income as a measurement period adjustment based on additional information obtained for the site regarding circumstances of the site as of the acquisition date of UIL.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Income Taxes	Note 15. Income Taxes Current and deferred taxes charged to (benefit) expense for the years ended December 31, 2016, 2015 and 2014 consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Current Federal $ (6 ) $ (20 ) $ (10 ) State 8 (33 ) 31 Current taxes charged to (benefit) expense 2 (53 ) 21 Deferred Federal 414 136 218 State 2 (6 ) 82 Deferred taxes charged to expense 416 130 300 Production tax credits (38 ) (42 ) (37 ) Investment tax credits (1 ) (1 ) (2 ) Total Income Tax Expense $ 379 $ 34 $ 282 The differences between tax expense per the statements of income and tax expense at the 35% statutory federal tax rate for the years ended December 31, 2016, 2015 and 2014 consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Tax expense at federal statutory rate $ 353 $ 105 $ 247 Depreciation and amortization not normalized 61 15 15 Investment tax credit amortization (1 ) (1 ) (2 ) Tax return related adjustments (2 ) 6 2 Production tax credits (38 ) (42 ) (37 ) Tax equity financing arrangements (25 ) (36 ) (11 ) Change in tax reserves — — 3 Changes in New York tax law — — 41 State tax expense (benefit), net of federal benefit 7 (25 ) 32 Non-deductible acquisition costs — 9 — Other, net 24 3 (8 ) Total Income Tax Expense $ 379 $ 34 $ 282 Deferred tax assets and liabilities as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Non-current Deferred Income Tax Liabilities (Assets) Property related $ 5,195 $ 4,763 Unfunded future income taxes 216 211 Federal and state tax credits (417 ) (367 ) Accumulated deferred investment tax credits 14 15 Federal and state NOL’s (1,397 ) (1,367 ) Joint ventures/partnerships 651 655 Nontaxable grant revenue (581 ) (595 ) Other (171 ) (17 ) Non-current Deferred Income Tax Liabilities 3,510 3,298 Add: Valuation allowance 31 19 Total Non-current Deferred Income Tax Liabilities 3,541 3,317 Less amounts classified as regulatory liabilities Non-current deferred income taxes 565 519 Non-current Deferred Income Tax Liabilities $ 2,976 $ 2,798 Deferred tax assets $ 2,565 $ 2,346 Deferred tax liabilities 6,106 5,663 Net Accumulated Deferred Income Tax Liabilities $ 3,541 $ 3,317 Valuation allowances are recorded to reduce deferred tax assets when it is not more-likely-than not that all or a portion of a tax benefit will be realized. A valuation allowance for the entire $9 million (net of federal benefit) carryforward of Maine Research and Development Super credits generated in tax years 2007 through 2012 was established as of December 31, 2012 with no change in this balance as of December 31, 2015. A valuation allowance of $10 million was established on various state NOLs as of December 31, 2015 and 2016, respectively. The $12 million increase in valuation allowances established in 2016 represents a full valuation allowance of $15 million (net of federal benefit) on Connecticut state tax credits, partially offset by a reduction of $3 million related to the Maine Research and Development Super credits. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2016, 2015 and 2014 consisted of: Years ended December 31, 2016 2015 2014 (Millions) Beginning Balance $ 36 $ 38 $ 41 Increases for tax positions related to prior years 8 1 20 Decreases for tax positions related to prior years (4 ) — — Reduction for tax position related to settlements with taxing authorities — (3 ) (23 ) Ending Balance $ 40 $ 36 $ 38 Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information. Accruals for interest and penalties on tax reserves were $2 million, $2 million, and $3 million for the years ended December 31, 2016, 2015 and 2014, respectively. If recognized, $8 million of the total gross unrecognized tax benefits would affect the effective tax rate. The total amount of unrecognized tax benefits anticipated to result in a net decrease to unrecognized tax benefits within 12 months of December 31, 2016 is estimated to be $9 million primarily relating to anticipation of additional guidance to be released by the IRS. On December 29, 2014, the Joint Committee on Taxation approved the examination of AVANGRID and its subsidiaries, without ARHI, for the tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. All New York and Maine state returns, which were filed without ARHI, are closed through 2011. All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period. As of December 31, 2016, UIL is subject to audit of its federal tax return for years 2013 and 2014. UIL income tax years 2010 through 2014 are open and subject to Connecticut and Massachusetts audit. As of December 31, 2016, we had federal tax net operating losses of $3.6 billion, federal renewable energy and investment tax credits, federal R&D tax credits and other federal credits of $394 million, state tax net operating losses of $241 million in several jurisdictions and miscellaneous state tax credits of $32 million available to carry forward and reduce future income tax liabilities. For state purposes, we recognized a valuation allowance of $31 million. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2023. The more significant state net operating losses begin to expire in 2021.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	12 Months Ended
	Dec. 31, 2016
Compensation And Retirement Disclosure [Abstract]
Post-retirement and Similar Obligations	Note 16. Post-retirement and Similar Obligations Networks has funded noncontributory defined benefit pension plans that cover the majority of Networks employees. The plans provide defined benefits based on years of service and final average salary for employees hired before 2002. Most employees hired in 2002, or later based upon the plan, are covered under a cash balance plan or formula where their benefit accumulates based on a percentage of annual salary and credited interest. During 2013, Networks announced that they would discontinue, effective December 31, 2013, the cash balance accruals for all non-union employees covered under the cash balance plans or formula. At the same time, the plans were closed to newly-hired non-union employees. The plans had been closed to newly-hired union employees in prior years. Networks has other postretirement health care benefit plans covering the majority of Networks employees. The plans were closed to newly-hired non-union employees at the end of 2011. The plans had been closed to union employees in prior years. The pre-Medicare-eligible healthcare plans are contributory and participants’ contributions are adjusted annually. Networks average contribution to these plans is limited at a level determined in prior periods. Except for a small group of “grandfathered” retirees, all Medicare eligible retirees that choose to participate are provided with a subsidy through a Health Reimbursement Account (HRA) to purchase coverage on the individual market. With the acquisition of UIL, Networks also includes pension and other postretirement plans of UIL operating utility companies. The UI pension plan covers the majority of employees of UI and UIL corporate. The plan was closed to newly-hired employees in 2005. The Regulated Gas Companies in Connecticut and Massachusetts have multiple qualified pension plans covering a majority of their union and management employees. These entities also have non‑qualified supplemental pension plans for certain employees. The qualified pension plans are traditional defined benefit plans or cash balance plans for those hired on or after specified dates. In some cases, neither of these plans is offered to new employees and have been replaced with enhanced 401(k) plans for those hired on or after specified dates. In addition to providing pension benefits, UI also provides other postretirement benefits, consisting principally of health care and life insurance benefits, for retired employees and their dependents. The healthcare plans are contributory and participants’ contributions are adjusted annually. SCG and CNG also have plans providing other postretirement benefits for a majority of their employees. These benefits consist primarily of health care, prescription drug and life insurance benefits, for retired employees and their dependents. For Medicare eligible non-union retirees, SCG and CNG provide a subsidy through a HRA for retirees to purchase coverage on the individual market. Medicare eligible union retirees have the option of receiving a subsidy through an HRA or paying contributions and participating in company-sponsored retiree health plans. ARHI has funded defined benefit pension plans for eligible employees hired prior to January 1, 2008. The benefit is based on participant’s age, service, and five years average pay at the time of the freeze date of April 30, 2011. ARHI has other postretirement health care benefit plans covering eligible retirees and employees hired prior to January 1, 2008. Health and life insurance rates are based on age and service points at the time of retirement. Obligations and funded status of Networks and ARHI as of December 31, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2016 2015 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 3,509 $ 2,620 $ 525 $ 435 Acquisition of UIL — 1,019 — 122 Service cost 44 36 5 5 Interest cost 142 99 21 16 Plan participants’ contributions — — 7 4 Plan amendments — — — (1 ) Actuarial gain (43 ) (105 ) (24 ) (31 ) Special termination benefits — 2 — — Benefits paid (204 ) (162 ) (39 ) (25 ) Benefit Obligation as of December 31, 3,448 3,509 495 525 Change in plan assets Fair value of plan assets as of January 1, 2,664 2,143 162 129 Acquisition of UIL — 687 — 39 Actual return on plan assets 169 (31 ) 11 (4 ) Employer contributions 43 27 30 21 Plan participants’ contributions — — 7 4 Benefits paid (204 ) (162 ) (39 ) (25 ) Withdrawals from VEBA — — (11 ) (2 ) Fair Value of Plan Assets as of December 31, 2,672 2,664 160 162 Funded Status as of December 31, $ (776 ) $ (845 ) $ (335 ) $ (363 ) Amounts recognized as of December 31, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2016 2015 (Millions) Current liabilities $ — $ — $ (5 ) $ (5 ) Non-current liabilities (776 ) (845 ) (330 ) (358 ) Total $ (776 ) $ (845 ) $ (335 ) $ (363 ) Networks offered retired employees an option to receive their future pension benefit as a lump sum during 2014. Approximately $118.5 million of payments were made in 2014 as a result of retired employees exercising the lump sum option. The lump sum payments did not trigger settlement accounting. Amounts recognized in OCI for ARHI for the years ended December 31, 2016, 2015 and 2014, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 (Millions) Net (gain) loss $ 23 $ 25 $ 22 $ (3 ) $ (1 ) $ 8 We have determined that all Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans. Amounts recognized as regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2016, 2015 and 2014 for Networks consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 (Millions) Net loss $ 860 $ 994 $ 1,045 $ 44 $ 76 $ 96 Prior service cost (credit) 7 9 12 (40 ) (49 ) (57 ) Our accumulated benefit obligation for all defined benefit pension plans of Networks and ARHI was $3,214 million and $3,261 million as of December 31, 2016 and 2015, respectively. CMP’s and NYSEG’s postretirement benefits were partially funded as of December 31, 2016 and 2015. The projected benefit obligation and the accumulated benefit obligation exceeded the fair value of pension plan assets for all plans of Networks and ARHI as of December 31, 2016 and 2015. The aggregate projected and accumulated benefit obligations and the fair value of plan assets for underfunded plans of Networks and ARHI as of December 31, 2016 and 2015 consisted of: Projected Benefit Obligation Exceeds Fair Value of Plan Assets Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets As of December 31, 2016 2015 2016 2015 (Millions) Projected benefit obligation $ 3,448 $ 3,509 $ 3,448 $ 3,509 Accumulated benefit obligation 3,214 3,261 3,214 3,261 Fair value of plan assets 2,672 2,664 2,672 2,664 Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities as of December 31, 2016, 2015 and 2014 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2014 2016 2015 2014 Net Periodic Benefit Cost: Service cost $ 44 $ 36 $ 30 $ 5 $ 4 $ 4 Interest cost 140 97 107 20 15 17 Expected return on plan assets (199 ) (156 ) (161 ) (8 ) (7 ) (7 ) Amortization of prior service cost (benefit) 2 3 4 (9 ) (9 ) (11 ) Amortization of net loss 123 130 94 8 7 — Special termination benefit charge — 2 — — — — Settlement charge — 2 — — — — Net Periodic Benefit Cost 110 114 74 16 10 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Settlements $ — $ (2 ) $ — $ — $ — $ — Net loss (gain) (11 ) 69 434 (24 ) (12 ) 72 Amortization of net loss (123 ) (130 ) (94 ) (8 ) (7 ) — Current year prior service cost — — — — (1 ) — Amortization of prior service (cost) benefit (2 ) (3 ) (4 ) 9 9 11 Total Other Changes (136 ) (66 ) 336 (23 ) (11 ) 83 Total Recognized $ (26 ) $ 48 $ 410 $ (7 ) $ (1 ) $ 86 Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI as of December 31, 2016, 2015 and 2014 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2014 2016 2015 2014 Net Periodic Benefit Cost: Service cost $ — $ — $ — $ — $ 1 $ 1 Interest cost 2 2 2 1 1 1 Expected return on plan assets (2 ) (2 ) (3 ) — — — Amortization of prior service cost - — — — — 1 Amortization of net loss 1 1 — — — 1 Settlement charge 1 — — — — — Net Periodic Benefit Cost (income) 2 1 (1 ) 1 2 4 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) — 4 6 (2 ) (8 ) (5 ) Amortization of net loss (1 ) (1 ) — — — (1 ) Amortization of prior service (cost) — — — — — (1 ) Total Other Changes (1 ) 3 6 (2 ) (8 ) (7 ) Total Recognized $ 1 $ 4 $ 5 $ (1 ) $ (6 ) $ (3 ) The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the net periodic benefit cost in other operating expenses net of capitalized portion. Amounts expected to be amortized from regulatory assets or liabilities into net periodic benefit cost for the year ending December 31, 2017 consists of: Year Ended December 31, 2017 Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 126 $ 5 Estimated prior service cost (benefit) 2 (9 ) Amounts expected to be amortized from OCI into net periodic benefit cost for the year ending December 31, 2017 consists of: Year Ended December 31, 2017 Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 1 $ — Estimated prior service cost (benefit) — — We expect that no pension benefit or postretirement benefit plan assets will be returned to us during the year ending December 31, 2017. The weighted-average assumptions used to determine benefit obligations for Networks and ARHI as of December 31, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2016 2015 Discount rate - Networks 4.12% / 4.24% 4.10% / 4.24% 4.12% / 4.24% 4.10% / 4.24% Discount rate - ARHI 3.81% 3.90% 3.81% 3.90% Rate of compensation increase - Networks 3.50% - 4.20% 4.00% — — The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit obligations. The weighted-average assumptions used to determine net periodic benefit cost for Networks and ARHI for the years ended December 31, 2016, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Discount rate - Networks 4.12% / 4.24% 3.80% / 4.24% 4.90 % 4.12% / 4.24% 3.80% / 4.24% 4.90 % Discount rate - ARHI 3.90% 3.90% 5.00 % 3.90% 3.90% 5.00 % Expected long-term return on plan assets - Networks 7.40% / 7.75% 7.50% 7.50 % 7.16% — — Expected long-term return on plan assets - ARHI 5.50% 5.50% 6.90 % 5.50% 5.75% 6.50 % Expected long-term return on plan assets - nontaxable trust - Networks — — — 7.00% 7.50% 7.50 % Expected long-term return on plan assets - taxable trust - Networks — — — 4.50% 5.00% 5.00 % Rate of compensation increase - Networks 3.50% - 4.20% 4.10% 4.20 % — — — We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 Health care cost trend rate assumed for next year - Networks 7.00%/9.00% 7.50%/7.00% Health care cost trend rate assumed for next year - ARHI 6.75%/8.50% 7.00%/9.00% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.50% 4.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.50% 4.50% Year that the rate reaches the ultimate trend rate - Networks 2026 / 2028 2027 Year that the rate reaches the ultimate trend rate - ARHI 2026 / 2028 2026 The effects of a one-percent change in the assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (Millions) Effect on total of service and interest cost $ 1 $ (1 ) Effect on postretirement benefit obligation $ 14 $ (12 ) Contributions We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. Networks expect to contribute $33 million to the pension benefit plans during 2017. Estimated Future Benefit Payments Expected benefit payments and Medicare Prescription Drug, Improvement and Modernization Act of 2003 subsidy receipts reflecting expected future service for Networks and ARHI as of December 31, 2016 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2017 $ 211 $ 34 $ — 2018 212 34 — 2019 216 34 — 2020 219 35 — 2021 224 35 — 2022 - 2026 1,125 169 3 Non-Qualified Pension Plans Networks and ARHI also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for these plans, which is included in Other Non-current Liabilities, was $57 million and $59 million at December 31, 2016 and 2015, respectively. Plan Assets Our pension benefits plan assets for Networks and ARHI are held in three master trusts. This provides for a uniform investment manager lineup and an efficient, cost effective means of allocating expenses and investment performance to each plan. Our primary investment objective is to ensure that current and future benefit obligations are adequately funded and with volatility commensurate with our risk tolerance. Preservation of capital and achievement of sufficient total return to fund accrued and future benefits obligations are of highest concern. Our primary means for achieving capital preservation is through diversification of the trusts’ investments while avoiding significant concentrations of risk in any one area of the securities markets. Further diversification is achieved within each asset group through utilizing multiple asset managers and systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income, and alternative investment markets. Networks’ asset allocation policy is the most important consideration in achieving our objective of superior investment returns while minimizing risk. We have established a target asset allocation policy within allowable ranges for our pension benefits plan assets within broad categories of asset classes made up of Return-Seeking and Liability-Hedging investments. Within the Return-Seeking category, we have targets of 35%-54% in equity securities and 3%-20% in equity alternative investments. The Liability-Hedging asset class has a target allocation percentage of 43%-45%. Return-Seeking investments generally consist of domestic, international, global, and emerging market equities invested in companies across all market capitalization ranges. Return-Seeking assets also include investments in real estate, absolute return, and strategic markets. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS, and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. ARHI’s investment portfolio contains a diversified blend of equity, fixed income, and other investments. In ARHI’s asset allocation policy we have established targets of 33% for equity investments, 50% for fixed income investments and 17% for other assets classes. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. Other asset classes, including real estate, absolute return, and real return, are used to enhance long-term returns while improving portfolio diversification. We primarily minimize the risk of large losses through diversification but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews, annual liability measurements, and periodic asset and liability studies. The fair values of pension benefits plan assets, by asset category, as of December 31, 2016 consisted of: As of December 31, 2016 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 49 $ — $ 49 $ — U.S. government securities 172 172 — — Common stocks 120 120 — — Registered investment companies 122 122 — — Corporate bonds 358 — 358 — Preferred stocks 4 — 4 — Common collective trusts 1,192 — 371 821 Partnerships/joint venture interests 5 — — 5 Real estate investments 61 — — 61 Other, principally annuity, fixed income 589 — 315 274 Total $ 2,672 $ 414 $ 1,097 $ 1,161 The fair values of pension benefits plan assets, by asset category, as of December 31, 2015 consisted of: As of December 31, 2015 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 57 $ 3 $ 54 $ — U.S. government securities 171 171 — — Common stocks 314 314 — — Registered investment companies 114 114 — — Corporate bonds 324 — 324 — Preferred stocks 5 — 5 — Common collective trusts 859 — 369 490 Partnership/joint venture interests 84 — — 84 Real estate investments 89 — — 89 Other, principally annuity, fixed income 647 — 329 318 Total $ 2,664 $ 602 $ 1,081 $ 981 Valuation Techniques We value our pension benefits plan assets as follows: ● Cash and cash equivalents - Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings. ● U.S. government securities, common stocks and registered investment companies - at the closing price reported in the active market in which the security is traded. ● Corporate bonds - based on yields currently available on comparable securities of issuers with similar credit ratings. ● Mutual funds - based upon quoted market prices in active markets, which represent the Net Asset Value (NAV) of the shares held. ● Preferred stocks - at the closing price reported in the active market in which the individual investment is traded. ● Common/collective trusts and Partnership/joint ventures - using the NAV provided by the administrator of the fund. The NAV is based on the value of the underlying assets owned by the fund, minus its liabilities, and then divided by the number of shares outstanding. The NAV is classified as Level 2 if the plan has the ability to redeem the investment with the investee at NAV per share at the measurement date. Redemption restrictions or adjustments to NAV based on unobservable inputs result in the fair value measurement being classified as Level 3 if those inputs are significant to the overall fair value measurement. ● Real estate investments - based on a discounted cash flow approach that includes the projected future rental receipts, expenses and residual values because the highest and best use of the real estate from a market participant view is as rental property. ● Other investments, principally annuity and fixed income - Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2: based on yields currently available on comparable securities of issuers with similar credit ratings. Level 3: when quoted prices are not available for identical or similar instruments, under a discounted cash flows approach that maximizes observable inputs such as current yields of similar instruments but includes adjustments for certain risks that may not be observable such as credit and liquidity risks. The reconciliation of changes in fair value of plan assets based on Level 3 inputs for the years ended December 31, 2016 and 2015, consisted of: (Millions) Common Collective Trusts Partnership Joint Venture Interests Real Estate Investments Other Investments Total As of December 31, 2014 $ 449 $ 79 $ 75 $ 342 $ 945 Actual return on plan assets: Relating to assets sold during the year (3 ) (19 ) — 1 (21 ) Relating to assets still held at the reporting date (5 ) 19 10 (21 ) 3 Purchases, sales and settlements 49 5 4 (4 ) 54 As of December 31, 2015 $ 490 $ 84 $ 89 $ 318 $ 981 Actual return on plan assets: Relating to assets sold during the year 6 (19 ) — 1 (12 ) Relating to assets still held at the reporting date 51 — 2 (8 ) 45 Purchases, sales and settlements 274 (60 ) (30 ) (37 ) 147 As of December 31, 2016 $ 821 $ 5 $ 61 $ 274 $ 1,161 Our postretirement benefits plan assets are held with trustees in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements and are invested among and within various asset classes to achieve sufficient diversification in accordance with our risk tolerance. This is achieved for our postretirement benefits plan assets through the utilization of multiple institutional mutual and money market funds, providing exposure to different segments of the fixed income, equity and short-term cash markets. Approximately 37% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes. Networks have established a target asset allocation policy within allowable ranges for postretirement benefits plan assets of 46%-66% for equity securities, 30%-31% for fixed income, and 3%-23% for all other investment types. In ARHI’s asset allocation policy we have established targets of 48% in equity securities, 49% in fixed income and 3% in all other investment types. The target allocations within allowable ranges are further diversified into 27%-66% large cap domestic equities, 5% small cap domestic equities, 8% international developed market, and 6% emerging market equity securities. Fixed income investment targets and ranges are segregated into core fixed income at 24%-31%, global high yield fixed income at 4%, and international developed market debt at 3%. Other alternative investment targets are 6% for real estate, 6% for tangible assets, and 3%-11% for other funds. Systematic rebalancing within target ranges increases the probability that the annualized return on investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair value of other postretirement benefits plan assets, by asset category, as of December 31, 2016 consisted of: As of December 31, 2016 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 6 $ 4 $ 2 $ — Mutual funds, fixed 41 39 2 — Government and corporate bonds 2 — 2 — Mutual funds, equity 72 43 29 — Common stocks 23 23 — — Mutual funds, other 16 9 7 — Total $ 160 $ 118 $ 42 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2015 consisted of: As of December 31, 2015 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 4 $ 4 $ — $ — Mutual funds, fixed 36 36 — — Government and corporate bonds 2 — 2 — Mutual funds, equity 46 46 — — Common stocks 24 24 — — Mutual funds, other 50 43 7 — Total $ 162 $ 153 $ 9 $ — Valuation Techniques We value our postretirement benefits plan assets as follows: ● Money market funds and mutual funds - based upon quoted market prices in active markets, which represent the NAV of shares held. ● Government bonds, and common stocks - at the closing price reported in the active market in which the security is traded. ● Corporate bonds - based on yields currently available on comparable securities of issuers with similar credit ratings. Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2016 and 2015. Defined contribution plans We also have defined contribution plans defined as 401(k)s. The annual contributions made through these plans for Networks and ARHI amounted to $34 million, $17 million and $20 million for 2016, 2015, and 2014 respectively.

Equity

Equity	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Equity	Note 17. Equity 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 is owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $3 million and additional paid in capital of $13,653 million. As of December 31, 2015, our share capital consisted of 500,000,000 shares of common stock authorized, 309,491,082 shares issued and 308,864,609 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 of $13,653 million. We had 491,459 and 626,473 shares of common stock held in trust and no convertible preferred shares outstanding as of December 31, 2016 and December 31, 2015, respectively. During the year ended December 31, 2016, we issued 109,357 shares of common stock and released 135,014 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 of Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. 115,831 shares of common stock of AVANGRID in the open market. The total cost of repurchase, including commissions, was $5 million. On December 15, 2015, the board of directors approved our common stock dividend, accounted for as a stock split. The stock split, effected through a stock dividend, resulted in the issuance of 252,234,989 shares, which in addition to the 243 previously existing shares increased the total shares outstanding to 252,235,232. The stock dividend was effective upon the board of directors’ approval. All share and per share information included in the condensed consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend. Accumulated OCI (Loss) Accumulated OCI for the years ended December 31, 2016, 2015 and 2014 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2013 2014 Change As of December 31, 2014 2015 Change As of December 31, 2015 2016 Change As of December 31, 2016 (Millions) Loss on revaluation of defined benefit plans, net of income tax expense of $0.6 for 2014, $2.2 for 2015 and $4.3 for 2016 $ (26 ) $ 1 $ (25 ) $ 4 $ (21 ) $ 7 $ (14 ) Loss for nonqualified pension plans, net of income tax expense (benefit) of $(1.9) for 2014, $1.7 for 2015 and $0.4 for 2016 (8 ) (3 ) (11 ) 3 (8 ) 1 (7 ) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of ($1.4) for 2014, $20.9 for 2015 and $(15.8) for 2016 — (2 ) (2 ) 33 31 (26 ) 5 Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense (benefit) of $4.1 for 2014, $4.9 for 2015 and $(11.0) for 2016 (a) (66 ) 5 (61 ) 7 (54 ) (16 ) (70 ) Net unrealized (loss) gain on derivatives qualifying as cash flow hedges (66 ) 3 (63 ) 40 (23 ) (42 ) (65 ) Accumulated Other Comprehensive (Loss) Income $ (100 ) $ 1 $ (99 ) $ 47 $ (52 ) $ (34 ) $ (86 ) (a) Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Net Income Per Share	Note 18. 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. In 2016 and 2015, while we did have securities that were dilutive, these securities did not result in a change to our earnings per share calculations for the years ended December 31, 2016 and 2015. We did not have any potentially-dilutive securities for the year ended December 31, 2014. In accordance with Accounting Standards Codification (ASC) Topic 260, Earnings per Share, we retroactively applied the stock split to prior periods presented. The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2016, 2015 and 2014, consisted of: Years Ended December 31, 2016 2015 2014 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 630 $ 267 $ 424 Denominator: Weighted average number of shares outstanding - basic 309,512,553 254,588,212 252,235,232 Weighted average number of shares outstanding - diluted 309,817,322 254,605,111 252,235,232 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 2.04 $ 1.05 $ 1.68 Earnings Per Common Share, Diluted $ 2.04 $ 1.05 $ 1.68

Tax Equity Financing Arrangemen

Tax Equity Financing Arrangements	12 Months Ended
	Dec. 31, 2016
Tax Equity Financing Arrangements [Abstract]
Tax Equity Financing Arrangements	Note 19. 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 5.4% and 8.5% as of December 31, 2016 and 2015, 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 $1,343 million and $244 million, respectively, at December 31, 2016. As of December 31, 2015 the assets and liabilities of VIEs totaled approximately $1,401 million and $338 million, respectively. At December 31, 2016 and 2015, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment, equity method investments and TEF liabilities. At December 31, 2016 and 2015, equity method investments of VIEs were approximately $161 million and $169 million, respectively. We consider 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 Farms, LLC, (collectively, Aeolus). 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. During 2014, the investor returns on the Aeolus I structure successfully met the investor requirements, causing the structure to flip back to us and leaving the investor with a ten-percent noncontrolling interest. In October 2015, AVANGRID purchased this remaining interest from the investor with a gain of $5 million recorded within “Other income and (expense)” of the consolidated statements of income.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2016
Deferred Revenue Disclosure [Abstract]
Grants, Government Incentives and Deferred Income	Note 20. Grants, Government Incentives and Deferred Income The changes in deferred income as of December 31, 2016 and 2015 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2014 $ 1,606 $ 15 $ 1,621 Additions — — — Recognized in income (77 ) 9 (68 ) As of December 31, 2015 $ 1,529 $ 24 $ 1,553 Additions — — — Recognized in income (68 ) (2 ) (70 ) As of December 31, 2016 $ 1,461 $ 22 $ 1,483 Within deferred income we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States Department of Treasury (DOT) provides eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the book to tax basis differences related to the property for income tax purposes. We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grant’s terms and conditions, we are required to repay the grant funds to the DOT. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2016 and 2015. Other deferred income relates predominantly to gas storage transactions where revenues are recognized as services are provided. Government grants related to depreciable assets and contributions in aid of construction treated as credits to property, plant and equipment in accordance with FERC requirements were $459 million and $390 million as of December 31, 2016 and 2015, respectively.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2016
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	Note 21. Equity method investments We have a 50-50 joint venture with Shell Wind Energy, Inc., which owns and operates a 162- megawatt (MW) wind farm located in southeast Colorado (Colorado Wind Ventures LLC), which commenced operations in January 2004. We account for this venture under the equity method of accounting. The carrying amount of this investment was $45 million and $41 million as of December 31, 2016 and 2015, respectively. We have two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC and the Flat Rock Wind Power II LLC wind farms located in upstate New York. Flat Rock Wind Power LLC, which commenced operations in January 2006, has a 231-MW capacity. Flat Rock Wind Power II LLC commenced operations in September 2007 and has a 91-MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. The carrying amount of these investments was $128 million and $143 million for Flat Rock Wind Power LLC, and $64 million and $69 million for Flat Rock Wind Power II LLC, as of December 31, 2016 and 2015, respectively. Through UI, we are party to a 50-50 joint venture with NRG affiliates in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is being accounted for as an equity investment, the carrying value of which was $128 million and $110 million as of December 31, 2016 and 2015. Networks holds an approximately 20% ownership interest in New York TransCo, LLC. New York TransCo, LLC was established by the New York transmission utilities to develop, own, and operate electric transmission in New York. The investment in New York TransCo, LLC is being accounted for as an equity investment, the carrying value of which was $22 million as of December 31, 2016 (See Note 24). None of our joint ventures have any contingent liabilities or capital commitments. Distributions received from equity method investments amounted to $20 million, $12 million, and $19 million for the years ended December 31, 2016, 2015, and 2014 respectively, which are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively. As of December 31, 2016, there was an immaterial amount of undistributed earnings from our equity method investments. During the year ended December 31, 2016 we completed the sale of our interest in Iroquois Gas Transmission System L.P. (Iroquois) to an unaffiliated third party for proceeds of $ 53.8 19.0

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2016
Receivables [Abstract]
Other Financial Statements Items	Note 22. Other Financial Statements Items Other income and (expense) Other income and (expense) for the years ended December 31, 2016, 2015 and 2014 consisted of: Years ended December 31, 2016 2015 2014 (Millions) Allowance for funds used during construction $ 26 $ 21 $ 17 Carrying costs on regulatory assets 14 28 29 Other 36 6 6 Total Other income and (expense) $ 76 $ 55 $ 52 Included in “Other” is a gain of $33 million resulted from the sale of our interest in Iroquois in 2016 (See Note 21). Accounts Receivable Accounts receivable as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Trade receivables $ 1,183 $ 1,036 Allowance for bad debts (64 ) (62 ) Total Accounts Receivable $ 1,119 $ 974 The allowance for bad debts relates entirely to gas and electricity consumers and comprises an amount that has been reserved following historical averages of loss percentages. The change in the allowance for bad debts as of December 31, 2016 and 2015 consisted of: (Millions) As of December 31, 2013 58 Current period provision 39 Write-off as uncollectible (48 ) As of December 31, 2014 $ 49 Current period provision 46 Write-off as uncollectible (33 ) As of December 31, 2015 $ 62 Current period provision 48 Write-off as uncollectible (46 ) As of December 31, 2016 $ 64 DPA receivable balances were $54 million and $62 million as of December 31, 2016 and 2015, respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Prepaid other taxes $ 153 $ 130 Broker margin and collateral accounts 32 46 Loans to third parties 3 3 Fixed-term deposits 3 11 Other pledged deposits 8 24 Prepaid expenses 53 53 Other 3 18 Total $ 255 $ 285 Other Non-current Assets Included in “Other non-current assets” are $186 million of safe harbor turbine payments made as of December 31, 2016 for production tax credit qualification purposes. In addition, included in “Other non-current assets”, are $5 million and $7 million, which represent restricted cash as of December 31, 2016 and 2015, respectively. Other current liabilities Other current liabilities as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Advances received $ 107 $ 96 Accrued salaries 84 68 Short-term environmental provisions 34 35 Collateral deposits received 45 59 Pension and other postretirement 5 5 Other 4 22 Total $ 279 $ 285

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Segment Information	Note 23. 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, impairment of non-current assets and interest expense net of capitalization, and then subtracting other income 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 consolidated financial statements. Segment information as of and for the year ended December 31, 2016 consisted of: For the year ended December 31, 2016 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 5,027 $ 1,000 $ (7 ) $ (2 ) $ 6,018 Revenue - intersegment 3 15 39 (57 ) — Depreciation and amortization 466 313 25 — 804 Operating income (loss) from continuing operations 1,086 149 (41 ) — 1,194 Adjusted EBITDA 1,552 462 (16 ) — 1,998 Earnings (loss) from equity method investments 15 (8 ) — — 7 Capital expenditures 1,140 561 6 — 1,707 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. I Included in revenue-external for the year ended December 31, 2016 are: $3,686 million from regulated electric operations, $1,306 million from regulated gas operations and $35 million from other operations of Networks; $1,000 million from renewable energy generation of Renewables; $7 million from gas storage services and $(14) million from gas trading operations of Gas. Segment information as of and for the year ended December 31, 2015 consisted of: For the year ended December 31, 2015 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,386 $ 1,051 $ (71 ) $ 1 $ 4,367 Revenue - intersegment — 16 52 (68 ) — Impairment of noncurrent assets — 12 — — 12 Depreciation and amortization 328 344 23 — 695 Operating income (loss) from continuing operations 537 100 (85 ) (39 ) 513 Adjusted EBITDA 865 456 (62 ) (39 ) 1,220 Earnings (loss) from equity method investments 1 (5 ) — 4 — Capital expenditures 773 304 5 — 1,082 As of December 31, 2015 Property, plant and equipment 12,363 7,835 513 — 20,711 Equity method investments 110 253 — 22 385 Total assets $ 20,126 $ 10,685 $ 1,265 $ (1,333 ) $ 30,743 (a) Does not represent a segment. I Included in revenue-external for the year ended December 31, 2015 are: $2,779 million from regulated electric operations, $605 million from regulated gas operations and $2 million from other operations of Networks; $1,051 million from renewable energy generation of Renewables; $21 million from gas storage services and $(92) million from gas trading operations of Gas. Segment information as of and for the year ended December 31, 2014 consisted of: For the year ended December 31, 2014 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,396 $ 1,180 $ 12 $ 6 $ 4,594 Revenue - intersegment 1 9 72 (82 ) — Impairment of noncurrent assets — 24 — 1 25 Depreciation and amortization 275 332 22 — 629 Operating income (loss) from continuing operations 616 257 16 (4 ) 885 Adjusted EBITDA 891 613 38 (3 ) 1,539 Earnings from equity method investments — 2 — 10 12 Capital expenditures 775 250 5 — 1,030 As of December 31, 2014 Property, plant and equipment 8,389 8,219 525 — 17,133 Equity method investments — 262 — — 262 Total assets $ 12,858 $ 12,328 $ 1,393 $ (2,417 ) $ 24,162 (a) Does not represent a segment. I Included in revenue-external for the year ended December 31, 2014 are: $2,726 million from regulated electric operations, $668 million from regulated gas operations and $2 million from other operations of Networks; $1,180 million from renewable energy generation of Renewables; $8 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 years ended December 31, 2016, 2015 and 2014, respectively, is as follows: Years Ended December 31, 2016 2015 2014 (Millions) Consolidated Adjusted EBITDA $ 1,998 $ 1,220 $ 1,539 Less: Impairment of non-current assets — 12 25 Depreciation and amortization 804 695 629 Interest expense, net of capitalization 268 267 243 Income tax expense 379 34 282 Add: Other income 76 55 52 Earnings from equity method investments 7 — 12 Consolidated Net Income $ 630 $ 267 $ 424

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Note 24. Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the years ended December 31, 2016, 2015 and 2014, respectively, consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Financiación, S.A. $ — $ (2 ) — $ (1 ) — $ (2 ) Iberdrola Renovables Energia, S.L. — (8 ) — (9 ) — (10 ) Iberdrola Canada Energy Services, Ltd — (37 ) — (55 ) — (49 ) Iberdrola, S.A. — (31 ) — (35 ) — (20 ) Other 21 (1 ) 3 (2 ) 12 (10 ) In addition to the statements of income items above we made purchases of turbines for wind farms from Gamesa Corporación Tecnológica, S.A. (Gamesa), in which our ultimate parent Iberdrola has a 20% ownership. The amounts capitalized for these transactions were $269 million and $70 million for the years ended December 31, 2016 and 2015, respectively. In addition, included in “Other non-current assets” are $92 million of safe harbor turbine payments we made to Gamesa as of December 31, 2016 (see Note 22). In June 2016, Siemens AG and Gamesa signed a binding agreement to merge their wind power businesses. After completion of the merger, which is expected in the first quarter of 2017, Iberdrola will have 8.1 Related party balances as of December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd $ — $ (14 ) $ 7 $ (5 ) Gamesa Corporación Tecnológica, S.A. 1 (181 ) 68 (77 ) Iberdrola, S.A. — (30 ) — (3 ) Iberdrola Energy Projects, Inc. — — 1 (3 ) Iberdrola Renovables Energía, S.L. 2 — — — Other 22 (3 ) — (2 ) Transactions with our parent company, Iberdrola, 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 generation facility at Klamath. 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, other than a $10 million write-off related to an arrangement to purchase turbines from Gamesa, which was recorded in impairment of non-current assets in the consolidated statements of income for the year ended December 31, 2015. Networks holds an approximate 20 21 22 67 43 22 2 99 AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a cash pooling agreement with Bank Mendes Gans, N.V., similar to other members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited in the cash pooling account where such funds are available to meet the liquidity needs of other affiliates within the Iberdrola Group. Under the cash pooling agreement, affiliates with credit balances have pledged those balances to cover the debit balances of the other affiliated parties to the agreement.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-Based Compensation	Note 25. Stock-Based Compensation Under the Avangrid, Inc. Omnibus Incentive Plan 1,298,683 performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in July 2016. An additional 11,804 PSUs were granted to officers and employees of AVANGRID in December 2016. 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. As of December 31, 2016, the total number of shares authorized for stock-based compensation plans was 2,500,000. The fair value of the PSUs on the grant date was $31.80 per share, which is expensed on a straight-line basis over the requisite service period of approximately seven years based on expected achievement. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recent quarterly dividend payment and the stock price as of the grant date. In connection with the acquisition of UIL, certain PSUs granted under the UIL 2008 Stock and Incentive Compensation Plan are outstanding, which are payable in our shares in 2017 and 2018 and vest based upon the achievement of certain pre-determined performance objectives. The total stock-based compensation expense, which is included in operations and maintenance of the consolidated statements of income for the years ended December 31, 2016, 2015 and 2014 was $0.6 million, $6.0 million and $4.8, respectively. The total income tax benefit recognized for stock-based compensation arrangements for the years ended December 31, 2016, 2015 and 2014, was $0.2 million, $2.4 million and $1.9 million, respectively. The total liability relating to stock-based compensation, which is included in other non-current liabilities, was $9.5 million and $17.5 million as of December 31, 2016 and 2015, respectively. Before 2016 the Company’s historical stock-based 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. A summary of the status of the AVANGRID's nonvested PSUs as of December 31 , 2016 December 31, 2016 Number of PSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2015 411,207 $ 39.60 Granted 1,335,416 $ 31.92 Forfeited (36,592 ) $ 32.83 Vested (186,050 ) $ 40.84 Nonvested Balance – December 31, 2016 1,523,981 $ 33.01 As of December 31, 2016, total unrecognized costs for non-vested PSUs were $22 million. The weighted-average period over which the PSU costs will be recognized is approximately 5 years. The weighted average grant date fair value of PSUs granted during the year was $31.92 per share for the year ended December 31, 2016.

Quarterly Financial Data (unaud

Quarterly Financial Data (unaudited)	12 Months Ended
	Dec. 31, 2016
Selected Quarterly Financial Information [Abstract]
Quarterly Financial Data (unaudited)	Note 26. Quarterly financial data (unaudited) Selected quarterly financial data for 2016 and 2015 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 2016 Operating revenues $ 1,670 $ 1,439 $ 1,418 $ 1,491 Operating Income $ 349 $ 322 $ 217 $ 306 Net Income $ 212 $ 102 $ 109 $ 207 Net Income attributable to Avangrid, Inc. $ 212 $ 102 $ 109 $ 207 Earnings Per Common Share, Basic and Diluted: (1) $ 0.69 $ 0.33 $ 0.35 $ 0.67 2015 Operating revenues $ 1,227 $ 939 $ 1,048 $ 1,153 Operating Income $ 196 $ 73 $ 161 $ 83 Net Income $ 106 $ 11 $ 54 $ 96 Net Income attributable to Avangrid, Inc. $ 106 $ 11 $ 54 $ 96 Earnings Per Common Share, Basic and Diluted: (1) $ 0.42 $ 0.04 $ 0.22 $ 0.37 (1) Based on weighted average number of 309 million shares outstanding each quarter in 2016 and 252 million shares for each quarter of 2015, except for fourth quarter of 2015, which is based on weighted average of 262 million shares as a result of the acquisition of UIL. The first quarter of 2016 includes a $19.0 million impact to net income from the sale of our interest in Iroquois to an unaffiliated third party for proceeds of $53.8 million. The second quarter of 2016 includes an adjustment of $126 million to unfunded future income tax to reflect the change from a flow through to normalization method following the approval of the proposal by the NYPSC, which was recorded as an increase to income tax expense and an offsetting increase to revenue. The first, second, third and fourth quarters of 2015 include $4 million, $8 million, $7 million and $18.5 million of pre-tax merger related expenses, respectively. Additionally, the fourth quarter of 2015 includes $44 million relating to rate credits, before income taxes, and $63 million tax benefits related to state income tax matters, including the initial impact of the merger on our consolidated tax filings.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 27. Subsequent events In January 2017 we released 5,088 shares of common stock held in trust, each having a par value of $0.01. On February 16, 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 April 3, 2017 to shareholders of record at the close of business on March 10, 2017. On February 16, 2017, the board of directors of AVANGRID adopted an annual cash incentive plan pursuant to the 2016 Omnibus Incentive Plan approved by the shareholders of AVANGRID. On March 1, 2017, we issued 70,493 shares of common stock, each having a par value of $0.01, which was approved by the board of directors of AVANGRID on February 16, 2017.

Acquisition of UIL and Issuance

Acquisition of UIL and Issuance of Common Stock	12 Months Ended
	Dec. 31, 2016
Acquisition of UIL	Note 4. Acquisition of UIL On December 16, 2015 (acquisition date), we completed our acquisition of UIL, a diversified energy company with its portfolio of regulated utility companies in Connecticut and Massachusetts that is expected to provide us with a greater flexibility to grow the combined regulated businesses through project development and create an enhanced platform to develop transmission and distribution projects in the Northeastern United States. In connection with the consummation of the acquisition we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including those held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $595 million in cash. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares. The acquisition was accounted for as a business combination. This method requires, among other things, that assets acquired and liabilities assumed in a business combination, with certain exceptions, be recognized at their fair values as of the acquisition date. As UIL’s common stock was publicly traded in an active market until the acquisition date, we determined that UIL’s common stock is more reliably measurable than the common stock of AVANGRID to determine the fair value of the consideration transferred in the transaction. The purchase consideration for UIL under the acquisition method is based on the stock price of UIL on the acquisition date multiplied by the number of shares issued by AVANGRID to the UIL shareowners after applying an equity exchange factor to the shares of vested restricted common stock of UIL (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other shares awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The “equity exchange factor” is the sum of one plus a fraction, (i) the numerator of which is the cash consideration and (ii) the denominator of which is the average of the volume weighted averages of the trading prices of UIL common stock on each of the ten consecutive trading days ending on (and including) the trading day that immediately precedes the closing date of the acquisition minus $10.50. The determination of the purchase price is based on a UIL stock price of $50.10 per share, which represents the closing stock price on the acquisition date. The fair value of shares of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business combination, which was computed as follows: (millions, except share and unit data) Common shares (1) 56,629,377 Price per share of UIL common stock as of the acquisition date $ 50.10 Subtotal value of common shares $ 2,837 Restricted stock units (2) 476,198 Other shares (3) 12,999 Equity exchange factor 1.2806 Total restricted and other shares (3) an equity exchange factor 626,473 Price per share used (5) $ 39.60 Subtotal value of restricted and other shares $ 25 Total shares of AVANGRID common stock issued to UIL shareowners (including held in trust as treasury stock) 57,255,850 Performance shares (4) 211,904 Equity exchange factor 1.2806 Total performance shares after applying an equity exchange factor 271,368 Price per share used (5) $ 39.60 Subtotal value of performance shares $ 11 Total consideration $ 2,873 (1) Based on UIL’s common shares outstanding on December 16, 2015. (2) Based on UIL’s shares of vested restricted stock. (3) Based on UIL’s restricted shares that vested upon the change in control. (4) Based on UIL’s vested performance shares award. (5) Based on the closing share price of UIL common stock on December 16, 2015, less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under the UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The following is a summary of the components of the consideration transferred to UIL’s shareowners: (millions, except share data) Cash ($10.50 x number of UIL common shares outstanding at the acquisition date - 56,629,377) $ 595 Equity 2,278 Total consideration $ 2,873 We also paid $37.5 million for transaction costs incurred in this business combination, which are recorded in “Operations and maintenance” in the consolidated statements of income for the year ended December 31, 2015. The following unaudited pro forma financial information presents the combined results of operations as if the acquisition had been completed on January 1, 2014, the beginning of the comparable prior annual reporting period. The unaudited pro forma results include: (i) merger credit adjustments to operating revenue (see Merger Settlement Agreement below for further details); (ii) elimination of accrued transaction costs representing non-recurring expenses directly related to the transaction, and (iii) the associated tax impact on these unaudited pro forma adjustments. The unaudited pro forma results do not reflect any cost saving synergies from operating efficiencies or the effect of the incremental costs incurred in integrating the two companies. Accordingly, these unaudited pro forma results are presented for informational purpose only and are not necessarily indicative of what the actual results of operations of the combined company would have been if the acquisition had occurred at the beginning of the period presented, nor are they indicative of future results of operations: Year Ended December 31, 2015 2014 (millions) Revenue $ 5,958 $ 6,226 Net income $ 468 $ 539 The revenue and net (loss) of UIL since the acquisition date included in the consolidated statements of income for the year ended December 31, 2015 were $36 million and $(36) million, respectively (see Merger Settlement Agreement below for further details). We finalized the valuation of the assets acquired and liabilities assumed within the measurement period during 2016. For the majority of UIL’s assets and liabilities, primarily property, plant and equipment, fair value was determined to be the respective carrying amounts of the predecessor entity. UIL’s operations are conducted in a regulated environment where the regulatory authority allows an approved rate of return on the carrying amount of the regulated asset base. Measurement period adjustments that were recognized in the year ended December 31, 2016 relate to the adjustments of the allocation of the purchase price to the following: equity method investments; contracts; debt; contingent liabilities, including those related to certain environmental sites; income taxes; non-regulated property, plant and equipment and goodwill. The following is a summary of the allocation of the purchase price as of the acquisition date and measurement period adjustments recognized in the year ended December 31, 2016: Provisional amounts reported in 2015 Measurement period adjustments Finalized amounts (millions) Current assets, including cash of $48 million $ 500 $ (7 ) $ 493 Other investments 114 22 136 Property, plant and equipment 3,552 (5 ) 3,547 Regulatory assets 966 36 1,002 Other assets 52 — 52 Current liabilities (493 ) — (493 ) Regulatory liabilities (493 ) — (493 ) Non-current debt (1,878 ) (27 ) (1,905 ) Other liabilities (1,201 ) (30 ) (1,231 ) Total net assets acquired at fair value 1,119 (11 ) 1,108 Goodwill – consideration transferred in excess of fair value assigned 1,754 11 1,765 Total consideration $ 2,873 $ 2,873 Goodwill generated from the acquisition of UIL increased by $11 million to the total amount of $1,765 million as of the acquisition date as a result of the finalization of the purchase price allocation. Goodwill generated from the acquisition of UIL has been assigned to the reporting units under the Networks reportable segment and is primarily attributable to expected future growth of the combined regulated businesses and enhanced platform to develop transmission and distribution projects in the Northeastern United States. The goodwill generated from this acquisition is not deductible for tax purposes. Merger Settlement Agreement As part of the process of seeking and obtaining regulatory approval for the acquisition in Connecticut and Massachusetts, Iberdrola, S.A., AVANGRID and UIL reached settlement agreements with the Office of Consumer Counsel in Connecticut and with the Attorney General of the Commonwealth of Massachusetts and the Department of Energy Resources in Massachusetts, which settlement agreements included commitments of actions to be taken after the transaction closed. As a result, the following commitments have been made in Connecticut, recognized in the period subsequent to the acquisition in 2015 unless otherwise noted, each of which is reasonably expected to be at a cost of $500,000 or more: • A one-time, $20 million rate credit to customers in 2016, allocated among UI, SCG and CNG customers based on the total number of retail customers. • Additional rate credits of $1.25 million/year for ten years (2018-2027) to CNG customers. • Additional rate credits of $0.75 million/year for ten years (2018-2027) to SCG customers. • $1.6 million in savings to SCG customers, associated with SCG making additional infrastructure capital investments over a three-year period without seeking recovery until the next SCG rate case. These amounts will be recorded by the Company as incurred in future periods. • Agreement not to seek to increase UI distribution base rates effective before January 1, 2017, and agreement not to seek to increase CNG and SCG distribution base rates effective before January 1, 2018. • Contribution of $2 million/year for three years to the DEEP, to stimulate investment in energy efficiency and clean energy technologies. • $5 million in benefits to customers resulting from UI recovering only the debt rate rather than the equity return for two years, on an increased $50 million of investment in storm resiliency programs. These amounts will be recorded by the Company as incurred in future periods. • Contribution of $1 million for disaster relief entities. • Maintaining charitable contribution at historical contribution levels (between $500,000 and $800,000) for at least four years. • Upon the resolution of all appeals of the PURA decision approving the acquisition, UI will withdraw its appeals of two PURA dockets relating to PURA’s disallowance of certain reconciliation amounts. The appeals were withdrawn by UI in June 2016. In connection with the acquisition proceeding, UI signed the consent order that, pursuant to the terms and conditions in the consent order, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. To the extent that the investigation and remediation is less than $30 million, UI would remit to the State of Connecticut the difference between such costs and $30 million for a public purpose as determined in the discretion of the Governor the Attorney General of Connecticut and the Commissioner of DEEP. Pursuant to the consent order UI is obligated to comply with the consent order, even if the cost of such compliance exceeds $30 million. 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 (See Note 14, Environmental Liabilities – English Station, for further details). As of December 31, 2016 and 2015 we reserved $28.3 million and $20.5 million, respectively, for this matter and have accrued the remaining $1.7 million and The difference of $7.8 million pre-tax has been reflected as the reversal of an expense in our 2016 results, reversing the amounts recorded in 2015, to adjust the allocation of the purchase price as a measurement period adjustment from the acquisition of UIL. The adjustment to the reserve during 2016 was recorded in the “Operations and maintenance” line of the consolidated statement of income as a measurement period adjustment based on additional information obtained for the site regarding circumstances of the site as of the acquisition date of UIL. As part of the final allocation of the purchase price we have determined a fair value of contingent liabilities of approximately $46.0 million relating to certain environmental sites. The following commitments have been made in Massachusetts, recognized in the period subsequent to the acquisition in 2015 unless otherwise noted, each of which is reasonably expected to be at a cost of $500,000 or more: • Customers of BGC will receive a total of $4.0 million in rate credits, to be spread over the months of November through April 2016-2017 and November through April 2017-2018. • BGC will contribute $1 million to alternative heating programs. • BGC will not seek to increase distribution base rates effective before June 1, 2018. As a result of the merger settlement agreement we have recorded $44 million as regulatory liabilities relating to the rate credits and an additional $19.8 million as liabilities, which primarily resulted in the net loss for UIL in the period following the acquisition date in 2015.
Avangrid, Inc [Member]
Acquisition of UIL	Note 2. Acquisition of UIL and Issuance of Common Stock On December 16, 2015 (acquisition date), UIL Holdings Corporation, a Connecticut corporation (UIL), became a wholly-owned subsidiary of AVANGRID as a result of the merger of Green Merger Sub, Inc., a Connecticut corporation and a wholly-owned subsidiary of AVANGRID (Merger Sub), with UIL, with Merger Sub surviving as a wholly-owned subsidiary of AVANGRID (the acquisition). The acquisition was effected pursuant to the Agreement and Plan of Merger, dated as of February 25, 2015, by and among AVANGRID, Merger Sub, and UIL. Following the completion of the acquisition, Merger Sub was renamed “UIL Holdings Corporation.” In connection with the acquisition, AVANGRID issued 309,490,839 shares of its common stock, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per each share of the common stock of UIL issued and outstanding at the acquisition date. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID and Iberdrola owned the remaining shares. On April 28, 2016, AVANGRID 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 of Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. 115,831 shares of its common stock in the open market. The total cost of repurchase, including commissions, was $5 million. On February 16, 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 April 3, 2017 to shareholders of record at the close of business on March 10, 2017.

Non-current Debt

Non-current Debt	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Non-current Debt	Note 3. Non-current debt Supplemental Indenture On December 19, 2016, AVANGRID, its subsidiary, UIL, and The Bank of New York Mellon, entered into a supplemental indenture, pursuant to which AVANGRID assumed from UIL all the obligations under the indenture dated as of October 7, 2010 between UIL and The Bank of New York Mellon and all obligations relating to $450 million in aggregate principal amount of 4.625% notes due 2020 issued by the predecessor company to UIL in 2010. For the purpose of the supplemental indenture a capital contribution of $483 million was made by AVANGRID to UIL in December 2016.

Cash Dividends Paid by Subsidia

Cash Dividends Paid by Subsidiaries	12 Months Ended
	Dec. 31, 2016
Cash Dividend [Abstract]
Cash Dividends Paid by Subsidiaries	Note 4. Cash dividends paid by subsidiaries Cash dividends paid by subsidiaries are as follows: Years ended December 31, 2016 2015 2014 (In millions) AVANGRID Networks $ 220 $ 59 $ 200 AVANGRID Renewables 200 750 — Other AVANGRID subsidiaries — 302 — $ 420 $ 1,111 $ 200 In December 2016, AVANGRID made a capital contribution of $50 million to its subsidiary, CMP. During 2016, AVANGRID recorded a net non-cash dividend of $827 million from its subsidiaries to zero out their account balances of notes receivables and payables.

Summary of Significant Accoun41

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Policies)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Principles of Consolidation	(a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Investments in common stock where we have the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.
Revenue Recognition	(b) Revenue recognition Revenue from the sale of energy by our regulated utilities is recognized in the period during which the sale occurs. The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. Revenues on sales of wholesale energy and energy related products and natural gas are recognized either when the service is provided or the product is delivered. We also provide natural gas storage services to customers. The natural gas remains the property of these customers at all times. Customers pay a two part rate that includes (i) a fixed fee reserving the right to store natural gas in our facilities and, (ii) a per unit rate for volumes actually injected into or withdrawn from storage. The fixed fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are injected into or withdrawn from our storage facilities.
Regulatory Accounting	(c) Regulatory accounting We account for our regulated utilities operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing regulated services or products, and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the consolidated statements of income consistent with the recovery or refund included in customer rates. We believe that it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
Business Combinations	(d) Business combinations We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred by the acquirer to former owners of acquiree and the equity interests issued by the acquirer. Acquisition related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is recorded as goodwill. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined.
Equity Method Investments	(e) Equity method investments Joint ventures that do not meet consolidation criteria are accounted for using the equity method. Earnings (losses) recognized under the equity method are reflected in the consolidated statements of income as “Earnings (losses) from equity method investments.” Dividends received from joint ventures are recognized as a reduction in the carrying amount of the investment and are not recognized as dividend income.
Goodwill and Other Intangible Assets	(f) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment at least annually or more frequently if events occur or circumstances change that will more likely than not reduce the fair value of the reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which goodwill is tested for impairment. In assessing goodwill for impairment we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary (step zero). If it is determined, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass step zero or perform the qualitative assessment, but determine that it is more likely than not that its fair value is less than its carrying amount, a quantitative two step fair value based test is performed. Step one compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an allocation of fair value to the individual assets and liabilities using business combination accounting guidance to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than its carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in the consolidated statements of income as the expense category that is consistent with the function of the intangible assets.
Property, Plant and Equipment	(g) Property, plant and equipment Property, plant and equipment are accounted for at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, the estimated cost of removal or reconditioning is recorded as an asset retirement obligation (ARO) and an equal amount is added to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities. Once certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs are capitalized. Development projects in construction are reviewed periodically for any indications of impairment. Assets are transferred from “Construction work in progress” to “Property, plant and equipment” when they are available for service. Wind turbine and related equipment costs, other project construction costs, and interest costs related to the project are capitalized during the construction period through substantial completion. AROs are recorded at the date projects achieve commercial operation. The cost of plant, and equipment in use is depreciated on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35 Hydroelectric power stations 35-90 Plant Wind power stations 25-40 Gas storage 25-40 Transport facilities 40-56 Distribution facilities 30-54 Equipment Conventional meters and measuring devices 15-27 Computer software 3-5 Other Buildings 50-75 Operations offices 4-50 Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed of to accumulated depreciation. We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs.
Impairment of Long-lived Assets	(h) Impairment of long lived assets We evaluate property, plant, and equipment and other long lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow model.
Fair Value Measurement	(i) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: ● Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. ● Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. ● Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement.
Available for Sale Securities	(j) Available for sale securities Securities that do not qualify as either securities held-to-maturity or trading securities, and which have a readily available fair value, are classified as securities available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported, net of taxes, in other comprehensive income or loss.
Derivatives and Hedge Accounting	(k) Derivatives and hedge accounting Derivatives are recognized on the balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Changes in the fair value of a derivative contract are recognized in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Other Comprehensive Income (OCI) and later reclassified into earnings when the underlying transaction occurs. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, hedge gains and losses previously recorded in OCI are immediately recognized in earnings. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. Changes in the fair value of electric and natural gas hedge contracts are recorded to derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities for our regulated operations. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.
Cash and Cash Equivalents	(l) Cash and cash equivalents Cash and cash equivalents comprises cash, bank accounts, and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on the consolidated balance sheets.
Accounts Receivable and Unbilled Revenue, Net	(m) Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances, which are settled on a net basis. Receivables and payables subject to such agreements are presented in our consolidated balance sheets on a net basis. 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 without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 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 short term. The allowance for bad debts account is established by using both historical average loss percentages to project future losses, and a specific allowance is established for known credit issues. Amounts are written off when we believe that a receivable will not be recovered.
Tax Equity Financing Arrangements-VIEs	(n) Tax equity financing arrangements-VIEs We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash and notes receivable. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as a liability in the consolidated balance sheets. Subsequently, this liability is amortized based on the cash and tax benefits provided to the tax equity investors. We evaluate whether an entity is a variable interest entity (VIE) whenever reconsideration events as defined by the accounting guidance occur (See Note 19). An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE.
Debentures, Bonds and Bank borrowings	(o) Debentures, bonds and bank borrowings Bonds, debentures and bank borrowings are recorded as a liability equal to the proceeds of the borrowings. The difference between the proceeds and the face amount of the issued liability is treated as discount or premium and is amortized as interest expense or income over the life of the instrument. Incremental costs associated with issuance of the debt instruments are deferred and amortized over the same period as debt discount or premium. Bonds, debentures and bank borrowings are presented net of unamortized discount, premium and debt issuance costs on the consolidated balance sheets.
Inventory	(p) Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas trading operations, we own natural gas that is stored in both self-owned and third-party owned underground storage facilities. This gas is recorded as inventory. Injections of inventory into storage are priced at the market purchase cost at the time of injection, and withdrawals of working gas from storage are priced at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at, or below market value. Inventories to support gas operations are reported on the balance sheet within “Fuel and gas in storage.” We also have materials and supplies inventories that are used for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at cost and reported on the balance sheets within “Materials and supplies.” Inventory items are combined for the statement of cash flow presentation purposes.
Government Grants	(q) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings consistent with the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, amounts receivable are recognized as an offset to expenses in the consolidated statements of income in the period in which the expenses are incurred.
Deferred Income	(r) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting obligations arising from the transaction. It is our policy to defer such revenues on the consolidated balance sheets and amortize them to earnings consistent with the obligations.
Asset Retirement Obligations	(s) Asset retirement obligations The fair value of the liability for an ARO and a conditional ARO is recorded in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long lived asset. The ARO is associated with our long lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains, and electricity generation facilities. The liability is adjusted periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation will be either settled at its recorded amount or a gain or a loss will be incurred. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. These are classified as accrued removal obligations.
Environmental Remediation Liability	(t) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. Our environmental liabilities are recorded on an undiscounted basis. Our environmental liability accruals are expected to be paid through the year 2053.
Post Employment and Other Employee Benefits	(u) Post employment and other employee benefits We sponsor defined benefit pension plans that cover the majority of our employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. For NYSEG, RG&E and UIL, we amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. For our other companies we use the standard amortization methodology under which amounts in excess of ten percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five year period.
Income Tax	(v) Income tax AVANGRID will file a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries for the 2016 tax period. For the 2015 tax year, AVANGRID filed a consolidated federal income tax return, which included the UIL taxable income or loss for the period from December 17, 2015 to December 31, 2015. UIL filed a separate consolidated federal income tax return for the period from January 1, 2015 to December 16, 2015. AVANGRID filed a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries (excluding UIL), which are 80% or more owned for the 2014 tax period. UIL filed separate consolidated federal income tax returns including the income or loss of its subsidiaries for all tax years including the filed 2014 return. AVANGRID (excluding ARHI and UIL), and ARHI filed separate consolidated federal income tax returns that included the taxable income or loss of all their respective subsidiaries, which are 80% or more owned, for all tax periods prior to 2013. We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with generally accepted accounting principles for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. The investment tax credits are deferred when used and amortized over the estimated lives of the related assets. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. Valuation allowances are recorded to reduce deferred tax assets when it is not more-likely-than-not that all or a portion of a tax benefit will be realized. Deferred tax assets and liabilities are classified as non-current in the consolidated balance sheets. The excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital is recorded in “Taxes other than income taxes” and “Taxes accrued” in the accompanying consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” of the consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income. Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.
Stock-based Compensation	(w) Stock-based compensation Stock-based compensation represents costs related to stock-based awards granted to employees. In the third quarter of 2016 we early adopted all the amendments to ASC 718, Compensation - Stock Compensation, issued in March 2016, to account for our stock based awards. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begin at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier.
Reclassifications	Reclassifications Certain amounts have been reclassified in the consolidated statements of cash flow to conform to the 2016 presentation as well as in connection with retrospective adoption of amendments in the accounting standard related to presentation of restricted cash in the statement of cash flow.
New Accounting Standards and Interpretations	New Accounting Standards and Interpretations (a) Revenue from contracts with customers In May 2014 the Financial Accounting Standards Board (FASB) issued ASC 606, Revenue from Contracts with Customers (ASC 606), (b) Fair value measurement disclosures for certain investments In May 2015 the FASB issued amendments that affect reporting entities that elect to estimate the fair value of certain investments within scope using the net asset value (NAV) per share (or its equivalent) practical expedient, as specified. The amendments remove the requirement to categorize within the fair value hierarchy all investments for which the fair value is measured at NAV using the practical expedient. They also remove certain disclosure requirements for eligible investments and limit the required disclosures to investments for which the entity has elected to measure the fair value using the practical expedient. Assets that calculate NAV per share (or its equivalent), but for which the practical expedient is not applied will continue to be included in the fair value hierarchy. The amendments are effective for public entities for fiscal years beginning after December 15, 2015, and interim periods within those fiscal years. The amendments permit early application, and require retrospective application to all periods presented. Retrospective application requires investments for which fair value is measured at NAV using the practical expedient to be removed from the fair value hierarchy in all periods presented. Our adoption of the amendments in 2016 did not affect our results of operations, financial position, or cash flows. (c) Simplifying the measurement of inventory In July 2015 the FASB issued amendments that require entities to measure inventory at the lower of cost and net realizable value, rather than the lower of cost or market. The amendments do not apply to inventory measured using last-in, first-out or the retail inventory method but apply to all other inventory, including inventory measured using first-in, first-out or average cost. Prior to this update, market value could be replacement cost, net realizable value, or net realizable value less an approximately normal profit margin. Net realizable value is the “estimated selling prices in the ordinary course of business, less reasonably predictable costs of completion, disposal, and transportation.” The amendments do not change the methods of estimating the cost of inventory under U.S. GAAP. The amendments are effective for public entities for fiscal years beginning after December 15, 2016, including interim periods within those fiscal years. The amendments require prospective application and permit earlier application. We expect our adoption of the amendments will not affect our results of operations, financial position, or cash flows. (d) Classifying and measuring financial instruments In January 2016 the FASB issued final guidance on the classification and measurement of financial instruments. The new guidance requires that all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings. There will no longer be an available-for-sale classification (changes in fair value reported in other comprehensive income) for equity securities with readily determinable fair values. For equity investments without readily determinable fair values, the cost method is also eliminated. However, entities (other than those following “specialized” accounting models, such as investment companies and broker-dealers) are able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes. Changes in the basis of these equity investments will be reported in current earnings. That election only applies to equity investments that do not qualify for the NAV practical expedient. When the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk will be recognized separately in other comprehensive income. The accumulated gains and losses due to those changes will be reclassified from accumulated other comprehensive income to earnings if the financial liability is settled before maturity. Public entities are required to use the exit price notion when measuring the fair value of financial instruments measured at amortized cost for disclosure purposes. In addition, the new guidance requires financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category (e.g., fair value, amortized cost, lower of cost or market) and form of financial asset (e.g., loans, securities). The classification and measurement guidance is effective for public entities in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. An entity will record a cumulative-effect adjustment to beginning retained earnings as of the beginning of the first reporting period in which the guidance is adopted, with two exceptions. The amendments related to equity investments without readily determinable fair values (including disclosure requirements) will be effective prospectively. The requirement to use the exit price notion to measure the fair value of financial instruments for disclosure purposes will also be applied prospectively. We expect our adoption of the guidance will not materially affect our results of operations, financial position, or cash flows. (e) Business combinations: simplifying the accounting for measurement-period adjustments In September 2015 the FASB issued amendments that require an acquirer to recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. As a result, the acquirer is required to record, in the same period’s financial statements, the effect on earnings of changes in depreciation, amortization, or other income effects, if any, as a result of the change to the provisional amounts, calculated as if the accounting had been completed at the acquisition date. The entity is required to present separately on the face of the income statement or disclose in the notes the portion of the amount recorded in current-period earnings by line item that would have been recorded in previous reporting periods if the adjustment to the provisional amounts had been recognized as of the acquisition date. The amendments are effective for public entities for fiscal years beginning after December 15, 2015, including interim periods within those fiscal years. The amendments require prospective application to provisional amounts that occur after the effective date of the amendment and permit earlier application. The effects of our adoption of the amendments on our results of operation, financial position, or cash flows as it relates to the business combination with UIL have been disclosed in Note 4, Acquisition of UIL. (f) Leases In February 2016 the FASB issued new guidance that affects all companies and organizations that lease assets, and requires them to record on their balance sheet assets and liabilities for the rights and obligations created by those leases. A lease is an arrangement that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. Concerning lease expense recognition, after extensive consultation, the FASB has ultimately concluded that the economics of leases can vary for a lessee, and those economics should be reflected in the financial statements. As a result, the amendments retain a distinction between finance leases and operating leases, while requiring both types of leases to be recognized on the balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the criteria for distinguishing between capital leases and operating leases in current GAAP. By retaining a distinction between finance leases and operating leases, the effect of leases on the statement of comprehensive income and the statement of cash flows is largely unchanged from previous GAAP. Lessor accounting will remain substantially the same as current GAAP, but with some targeted improvements to align lessor accounting with the lessee accounting model and with the revised revenue recognition guidance issued in 2014. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We are currently reviewing our contracts and are in the process of determining the proper application of the standard to these contracts in order to determine the impact that the adoption will have on our consolidated financial statements. We expect our adoption of the new guidance will materially affect our financial position through the recording of operating leases on the balance sheet as a right-of-use asset. (g) Derivative contract novations In March 2016 the FASB issued amendments concerning the effect of derivative contract novations on existing hedge accounting relationships. As it relates to derivative instruments, novation refers to replacing one of the parties to a derivative instrument with a new party, which may occur for a variety of reasons such as: financial institution mergers, intercompany transactions, an entity exiting a particular derivatives business or relationship, or because of laws or regulatory requirements. The amendments clarify that a change in the counterparty to a derivative instrument that has been designated as the hedging instrument under the guidance for Derivatives and Hedging (Topic 815) does not, in and of itself, require dedesignation of that hedge accounting relationship provided that all other hedge accounting criteria continue to be met. The amendments are effective for public entities for financial statements issued for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. The amendments may be applied on either a prospective basis or a modified retrospective basis and early application is permitted. We expect our adoption will not materially affect our results of operations, financial position, and cash flows. (h) Improvements to employee share-based payment accounting The FASB issued amendments in March 2016 regarding the simplification of several aspects of accounting for share-based payment transactions, including income tax consequences, classification of awards as either equity or liabilities, policy election on accounting for forfeitures and classification on the statement of cash flows. Some areas of simplification apply only to nonpublic entities. The amendments are effective for public entities for fiscal years beginning after December 15, 2016, and interim periods within those fiscal years. Early adoption permitted in any interim or annual period, but must adopt all of the amendments in the same period. For the purpose of accounting for the stock-based compensation plans, in the third quarter of 2016 we early adopted all the above amendments and elected to account for forfeitures when they occur. Our adoption of the amendments did not materially affect our results of operations, financial position, or cash flows. (i) Measurement of credit losses on financial instruments The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments. The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectibility of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The amendments are effective for public entities that are SEC filers for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. Entities are to apply the amendments on a modified retrospective basis for most instruments. We expect our adoption will not materially affect our results of operations, financial position, and cash flows. (j) Certain classifications in the statement of cash flows The FASB issued the amendments in August 2016 to address existing diversity in practice concerning eight cash flows issues. The guidance addresses classification as operating, investing or financing activities in the statement of cash flows for these issues: 1) Debt prepayment or debt extinguishment costs (financing), 2) Settlement of zero-coupon bonds (interest is operating, principal is financing), 3) Contingent consideration payments made after a business combination (investing or financing based on timing, or operating, as specified), 4) Proceeds from the settlement of insurance claims (based on the nature of the loss), 5) Proceeds from the settlement of corporate-owned life insurance policies (COLI) (investing; with cash payments for COLI premiums as investing, operating or a combination of investing/operating), 6) Distributions received from equity method investees (based on an entity’s accounting policy election: either cumulative earnings or nature of distribution), 7) Beneficial interests in securitization transactions (noncash or investing as specified), 8) Separately identifiable cash flows and application of the predominance principle (cash receipts/payments with aspects of more than one classification by applying specific GAAP guidance; or if there is no guidance, based on the nature of the related activity or the activity that is the predominant source or use of the cash flows). The amendments are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. The amendments are to be applied retrospectively to each prior period presented, unless impracticable for some issues and then the application would be prospective for those affected issues. We expect our adoption will not materially affect cash flows. (k) Presentation of restricted cash in the statement of cash flows The FASB issued the amendment in November 2016 to address existing diversity in the classification and presentation of changes in restricted cash on the statement of cash flows. The amendment requires that a statement of cash flows explain the change during the period in the total of cash, cash equivalents, and amounts generally described as restricted cash or restricted cash equivalents. Therefore, amounts generally described as restricted cash and restricted cash equivalents should be included with cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows. The amendment does not provide a definition of restricted cash or restricted cash equivalents. The amendment is effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. The amendment should be applied using a retrospective transition method to each period presented. As permitted, we have early adopted the amendment as of the beginning of the fourth quarter of 2016 and have applied it retrospectively to all periods presented. Accordingly, the changes in restricted cash and restricted cash equivalents, presented previously in other assets of operating activities, were included in cash and cash equivalents when reconciling the beginning-of-period and end-of-period total amounts shown on the statement of cash flows, which increased by $2 million and had no change in net cash provided by operating activities in the consolidated statements of cash flow, for both of the years ended December 31, 2015 and 2014, respectively.
Use of Estimates and Assumptions	Use of Estimates and Assumptions The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for doubtful accounts and unbilled revenues; (2) asset impairments, including goodwill; (3) depreciable lives of assets; (4) income tax valuation allowances; (5) uncertain tax positions; (6) reserves for professional, workers’ compensation, and comprehensive general insurance liability risks; (7) contingency and litigation reserves; (8) fair value measurements; (9) earnings sharing mechanisms; (10) environmental remediation liabilities; and (11) AROs. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates used in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates.
Union Collective Bargaining Agreements	Union collective bargaining agreements We have approximately 48% of the employees covered by a collective bargaining agreement. Agreements which will expire within the coming year apply to approximately 6% of our employees.

Summary of Significant Accoun42

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2016
Accounting Policies [Abstract]
Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35 Hydroelectric power stations 35-90 Plant Wind power stations 25-40 Gas storage 25-40 Transport facilities 40-56 Distribution facilities 30-54 Equipment Conventional meters and measuring devices 15-27 Computer software 3-5 Other Buildings 50-75 Operations offices 4-50

Acquisition of UIL (Tables)

Acquisition of UIL (Tables)	12 Months Ended
	Dec. 31, 2016
Business Combinations [Abstract]
Summary of Fair Value of Purchase Consideration	The fair value of shares of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business combination, which was computed as follows: (millions, except share and unit data) Common shares (1) 56,629,377 Price per share of UIL common stock as of the acquisition date $ 50.10 Subtotal value of common shares $ 2,837 Restricted stock units (2) 476,198 Other shares (3) 12,999 Equity exchange factor 1.2806 Total restricted and other shares (3) an equity exchange factor 626,473 Price per share used (5) $ 39.60 Subtotal value of restricted and other shares $ 25 Total shares of AVANGRID common stock issued to UIL shareowners (including held in trust as treasury stock) 57,255,850 Performance shares (4) 211,904 Equity exchange factor 1.2806 Total performance shares after applying an equity exchange factor 271,368 Price per share used (5) $ 39.60 Subtotal value of performance shares $ 11 Total consideration $ 2,873 (1) Based on UIL’s common shares outstanding on December 16, 2015. (2) Based on UIL’s shares of vested restricted stock. (3) Based on UIL’s restricted shares that vested upon the change in control. (4) Based on UIL’s vested performance shares award. (5) Based on the closing share price of UIL common stock on December 16, 2015, less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under the UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.
Summary of Components of Estimated Consideration Transferred	The following is a summary of the components of the consideration transferred to UIL’s shareowners: (millions, except share data) Cash ($10.50 x number of UIL common shares outstanding at the acquisition date - 56,629,377) $ 595 Equity 2,278 Total consideration $ 2,873
Schedule of Unaudited Pro Forma Results	Accordingly, these unaudited pro forma results are presented for informational purpose only and are not necessarily indicative of what the actual results of operations of the combined company would have been if the acquisition had occurred at the beginning of the period presented, nor are they indicative of future results of operations: Year Ended December 31, 2015 2014 (millions) Revenue $ 5,958 $ 6,226 Net income $ 468 $ 539
Summary of Allocation of Purchase Price	The following is a summary of the allocation of the purchase price as of the acquisition date and measurement period adjustments recognized in the year ended December 31, 2016: Provisional amounts reported in 2015 Measurement period adjustments Finalized amounts (millions) Current assets, including cash of $48 million $ 500 $ (7 ) $ 493 Other investments 114 22 136 Property, plant and equipment 3,552 (5 ) 3,547 Regulatory assets 966 36 1,002 Other assets 52 — 52 Current liabilities (493 ) — (493 ) Regulatory liabilities (493 ) — (493 ) Non-current debt (1,878 ) (27 ) (1,905 ) Other liabilities (1,201 ) (30 ) (1,231 ) Total net assets acquired at fair value 1,119 (11 ) 1,108 Goodwill – consideration transferred in excess of fair value assigned 1,754 11 1,765 Total consideration $ 2,873 $ 2,873

Industry Regulation (Tables)

Industry Regulation (Tables)	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Electric and Gas Delivery Rate Increase	The delivery rate increase in the proposal can be summarized as follows: May 1, 2016 May 1, 2017 May 1, 2018 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 29.6 4.10 % $ 29.9 4.10 % $ 30.3 4.10 % NYSEG Gas 13.1 7.30 % 13.9 7.30 % 14.8 7.30 % RG&E Electric 3.0 0.70 % 21.6 5.00 % 25.9 5.70 % RG&E Gas 8.8 5.20 % 7.7 4.40 % 9.5 5.20 %

Regulatory Assets and Liabili45

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Regulated Operations [Abstract]
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 22 $ 8 Pension and other post-retirement benefits 7 13 Storm costs 40 8 Temporary supplemental assessment surcharge 4 7 Reliability support services 27 — Revenue decoupling mechanism 15 6 Transmission revenue reconciliation mechanism 12 5 Electric supply reconciliation 13 — Hedges losses 10 37 Contracts for differences 14 18 Hardship programs 16 13 Deferred property tax 10 — Plant decommissioning 6 — Deferred purchased gas 14 12 Deferred transmission expense 13 12 Environmental remediation costs 14 37 Other 48 43 Total Current Regulatory Assets 285 219 Non-current Pension and other post-retirement benefits cost deferrals 134 151 Pension and other post-retirement benefits 1,320 1,509 Storm costs 187 251 Deferred meter replacement costs 32 34 Unamortized losses on reacquired debt 20 23 Environmental remediation costs 287 271 Unfunded future income taxes 542 549 Asset retirement obligations 18 24 Deferred property tax 33 45 Federal tax depreciation normalization adjustment 161 158 Merger capital expense target customer credit 11 15 Debt premium 151 141 Plant decommissioning 14 7 Contracts for differences 61 50 Hardship programs 18 29 Other 102 57 Total Non-current Regulatory Assets $ 3,091 $ 3,314
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Current Reliability support services (Cayuga) $ 3 $ 16 Non by-passable charges 22 7 Energy efficiency portfolio standard 45 33 Gas supply charge and deferred natural gas cost 6 6 Transmission revenue reconciliation mechanism 5 16 Pension and other post-retirement benefits 3 3 Pension and other post-retirement benefits cost deferrals 14 — Carrying costs on deferred income tax bonus depreciation 15 — Carrying costs on deferred income tax - Mixed Services 263(a) 5 — Yankee DOE refund 24 5 Merger-related rate credits 3 20 Revenue decoupling mechanism 9 14 Other 38 27 Total Current Regulatory Liabilities 192 147 Non-current Accrued removal obligations 1,117 1,084 Asset sale gain account 9 8 Carrying costs on deferred income tax bonus depreciation 95 116 Economic development 35 36 Merger capital expense target customer credit account 15 17 Pension and other post-retirement benefits 76 90 Positive benefit adjustment 42 51 New York state tax rate change 9 17 Post term amortization 3 25 Theoretical reserve flow thru impact 24 31 Deferred property tax 19 15 Net plant reconciliation 10 10 Variable rate debt 28 32 Carrying costs on deferred income tax - Mixed Services 263(a) 25 31 Rate refund – FERC ROE proceeding 22 21 Transmission congestion contracts 18 — Merger-related rate credits 21 24 Accumulated deferred investment tax credits 15 10 Asset retirement obligation 13 13 Earning sharing provisions 12 — Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge — 21 Low income programs 46 42 Unfunded future income taxes — 27 Non-firm margin sharing credits 7 8 Deferred income taxes regulatory 565 519 Other 73 93 Total Non-current Regulatory Liabilities $ 2,318 $ 2,360

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2016
Goodwill And Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Networks $ 2,744 $ 2,733 Renewables 380 380 Gas — — Other (a) — 2 Total $ 3,124 $ 3,115 (a) Does not represent a reportable segment. It includes Corporate.
Schedule of Intangible Assets Acquired and Developed	Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets: As of December 31, 2016 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 319 $ (120 ) $ 199 Wind development 587 (254 ) 333 Other 17 (11 ) 6 Total Intangible Assets $ 923 $ (385 ) $ 538 As of December 31, 2015 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 324 $ (116 ) $ 208 Wind development 584 (243 ) 341 Other 15 (8 ) 7 Total Intangible Assets $ 923 $ (367 ) $ 556
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2016, to be as follows: Year ending December 31, (Millions) 2017 $ 16 2018 16 2019 18 2020 17 2021 21

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2016
Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35 Hydroelectric power stations 35-90 Plant Wind power stations 25-40 Gas storage 25-40 Transport facilities 40-56 Distribution facilities 30-54 Equipment Conventional meters and measuring devices 15-27 Computer software 3-5 Other Buildings 50-75 Operations offices 4-50
Regulated and Unregulated [Member]
Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives	Property, plant and equipment as of December 31, 2016, consisted of: As of December 31, 2016 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 10,343 $ 10,384 $ 20,727 Natural gas transportation, distribution and other 4,803 613 5,416 Other common operating property 877 43 920 Total Property, Plant and Equipment in Service (a) 16,023 11,040 27,063 Total accumulated depreciation (b) (3,970 ) (3,016 ) (6,986 ) Total Net Property, Plant and Equipment in Service 12,053 8,024 20,077 Construction work in progress 979 492 1,471 Total Property, Plant and Equipment $ 13,032 $ 8,516 $ 21,548 ( a ) Includes capitalized leases of $208 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $60 million. Property, plant and equipment as of December 31, 2015, consisted of: As of December 31, 2015 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 11,506 $ 10,058 $ 21,564 Natural gas transportation, distribution and other 2,673 651 3,324 Other common operating property 817 40 857 Total Property, Plant and Equipment in Service (a) 14,996 10,749 25,745 Total accumulated depreciation (b) (3,727 ) (2,645 ) (6,372 ) Total Net Property, Plant and Equipment in Service 11,269 8,104 19,373 Construction work in progress 1,094 244 1,338 Total Property, Plant and Equipment $ 12,363 $ 8,348 $ 20,711 ( a ) Includes capitalized leases of $178 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $53 million.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Table Text Block Supplement [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2016 and 2015 consisted of: (Millions) As of December 31, 2014 $ 234 Liabilities settled during the year (16 ) Liabilities incurred during the year — Accretion expense 14 Revisions in estimated cash flows (48 ) As of December 31, 2015 $ 184 Liabilities settled during the year (7 ) Liabilities incurred during the year 3 Accretion expense 10 Revisions in estimated cash flows (29 ) As of December 31, 2016 $ 161

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2016
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long- term debt as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2018-2045 $ 1,752 3.07%-10.60% $ 1,815 3.07%-10.60% Unsecured pollution control notes - fixed 2020 200 2.00%-2.375% 200 2.00%-2.375% Unsecured pollution control notes – variable 2032 62 1.32% 219 0.195%-1.181% Other various non-current debt - fixed 2017-2045 2,772 2.89%-10.48% 2,440 2.89%-10.48% Obligations under capital leases 2017-2023 104 4%-4.44% 87 4%-4.44% Unamortized debt issuance costs and discount (31 ) (25 ) Total Debt 4,859 4,736 Less: debt due within one year, included in current liabilities 349 206 Total Non-current Debt $ 4,510 $ 4,530 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $5,886 million.
Schedule of Maturities and Repayments of Long-term Debt	Non-current debt, including sinking fund obligations and capital lease payments, due over the next five years consists of: (Millions) 2017 2018 2019 2020 2021 Total $ 349 $ 180 $ 358 $ 723 $ 308 $ 1,918

Fair Value of Financial Instr50

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2016 and 2015 consisted of: 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 ) As of December 31, 2015 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 39 $ — $ — $ — $ 39 Derivative assets Derivative financial instruments - power 10 81 48 (71 ) 68 Derivative financial instruments - gas 267 25 68 (280 ) 80 Contracts for differences — — 29 — 29 Total 277 106 145 (351 ) 177 Derivative liabilities Derivative financial instruments - power (43 ) (12 ) (14 ) 55 (14 ) Derivative financial instruments - gas (193 ) (40 ) (51 ) 212 (72 ) Contracts for differences — — (96 ) — (96 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (236 ) $ (52 ) $ (164 ) $ 267 $ (185 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliations of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2016, 2015 and 2014 consisted of: (Millions) 2016 2015 2014 Fair value as of January 1, $ (19 ) $ 57 $ 53 Gains for the year recognized in operating revenues 67 33 11 Losses for the year recognized in operating revenues — (8 ) (1 ) Total gains or losses for the period recognized in operating revenues 67 25 10 Gains recognized in OCI 1 2 — Losses recognized in OCI — (3 ) (3 ) Total gains or losses recognized in OCI 1 (1 ) (3 ) Net change recognized in regulatory assets and liabilities (8 ) — — Purchases 3 (73 ) 14 Settlements (9 ) (14 ) (26 ) Transfers out of Level 3 (a) (4 ) (13 ) 9 Fair value as of December 31, $ 31 $ (19 ) $ 57 Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 67 $ 25 $ 10 (a) Transfers out of Level 3 were the result of increased observability of market data. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input December 31, 2016 Risk of non-performance 0.68% - 0.81% Discount rate 1.47% - 2.45% Forward pricing ($ per MW) $3.15 - $9.55
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	As of December 31, 2016 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions with delivery periods Transactions are valued against forward market prices Observable and extrapolated forward gas and power prices not all of which can be NYMEX ($/MMBtu) $ 4.27 $ 7.37 $ 1.64 with delivery exceeding two on a corroborated by SP15 ($/MWh) $ 44.23 $ 80.28 $ 14.25 period > two years discounted market data for Mid C ($/MWh) $ 35.44 $ 83.93 $ 3.60 years basis identical or Cinergy ($/MWh) $ 36.40 $ 77.49 $ 18.53 similar products

Derivative Instruments and He51

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2016
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 year ended December 31, 2016 and for the period from December 17, 2015 to December 31, 2015, respectively, were as follows: Year Ended December 31, 2016 Period from December 17, 2015 to December 31, 2015 (Millions) Regulatory Assets - Derivative liabilities $ 7 $ 1 Regulatory Liabilities - Derivative assets $ 1 $ —
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks activities as of December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (Millions) Wholesale electricity purchase contracts (MWh) 5.6 6.7 Natural gas purchase contracts (Dth) 5.8 4.8 Fleet fuel purchase contracts (Gallons) 2.3 3.8 The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (MWh/Dth in Millions) Wholesale electricity purchase contracts 3 3 Wholesale electricity sales contracts 7 6 Foreign exchange forward purchase contracts — 4 Natural gas and other fuel purchase contracts 329 332 Financial power contracts 8 7 Basis swaps - purchases 49 67 Basis swaps - sales 45 80
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Consolidated Balance Sheet and Amounts	The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Networks activities as of December 31, 2016 and 2015, respectively, consisted of: 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 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 11 $ 18 $ — $ — Derivative liabilities — — (28 ) (68 ) 11 18 (28 ) (68 ) Designated as hedging instruments Derivative assets 3 6 3 6 Derivative liabilities (3 ) (6 ) (42 ) (7 ) — — (39 ) (1 ) Total derivatives before offset of cash collateral 11 18 (67 ) (69 ) Cash collateral receivable — — 37 — Total derivatives as presented in the balance sheet $ 11 $ 18 $ (30 ) $ (69 ) The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of December 31, 2016 and 2015, respectively, consisted of: 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 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 186 $ 113 $ 117 $ 4 Derivative liabilities (85 ) (14 ) (169 ) (29 ) 101 99 (52 ) (25 ) Designated as hedging instruments Derivative assets 56 13 — — Derivative liabilities — — (9 ) — 56 13 (9 ) — Total derivatives before offset of cash collateral 157 112 (61 ) (25 ) Cash collateral receivable (payable) (80 ) (41 ) — — Total derivatives as presented in the balance sheet $ 77 $ 71 $ (61 ) $ (25 )
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 OCI and income for the years ended December 31, 2016, 2015 and 2014, respectively, consisted of: Year Ended December 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) 2016 Interest rate contracts $ — Interest expense $ 8 Commodity contracts — Operating expenses 2 Total $ — $ 10 2015 Interest rate contracts $ — Interest expense $ 9 Commodity contracts (3 ) Operating expenses 3 Total $ (3 ) $ 12 2014 Interest rate contracts $ — Interest expense $ 9 Commodity contracts (4 ) Operating expenses 1 Total $ (4 ) $ 10 (a) Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the consolidated statements of income. The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2016 and 2015 consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income (Gain) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2016 Commodity contracts $ (42 ) Revenues $ (43 ) $ (42 ) $ (43 ) 2015 Commodity contracts $ 57 Revenues $ (2 ) Total $ 57 $ (2 ) (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 December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (Millions) Wholesale electricity purchase contracts $ (2 ) $ (13 ) Wholesale electricity sales contracts 6 35 Foreign exchange forward purchase contracts — (1 ) Natural gas and other fuel purchase contracts 30 10 Financial power contracts 56 32 Basis swaps- purchases 3 1 Basis swaps- sales (2 ) (2 ) Total $ 91 $ 62
Effect of Trading and Non-trading Derivatives Associated with Renewables and Gas Activities	The effect of trading and non-trading derivatives, respectively, associated with Renewables and Gas activities for the years ended December 31, 2016, 2015 and 2014 consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Wholesale electricity purchase contracts $ 3 $ 6 $ (9 ) Wholesale electricity sales contracts (7 ) (5 ) 9 Financial power contracts 4 — (2 ) Financial and natural gas contracts (22 ) (26 ) 125 Total (Loss) Gain $ (22 ) $ (25 ) $ 123 Years Ended December 31, 2016 2015 2014 (Millions) Wholesale electricity purchase contracts $ 9 $ (8 ) $ (8 ) Wholesale electricity sales contracts (20 ) (5 ) 15 Financial power contracts (10 ) 24 30 Natural gas and other fuel purchase contracts 34 18 (1 ) Total Gain $ 13 $ 29 $ 36

Commitments and Contingent Li52

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2016
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Lease Payments	Total future minimum lease payments as of December 31, 2016 consisted of: Year Operating Leases Capital Leases Total (Millions) 2017 $ 106 $ 30 $ 136 2018 28 6 34 2019 28 7 35 2020 26 7 33 2021 28 4 32 2022 and thereafter 487 50 537 Total $ 703 $ 104 $ 807
Forward Purchase and Sales Commitment Arrangement	Forward purchases and sales commitments under power, gas, and other arrangements as of December 31, 2016 consisted of: Purchases Sales Year Gas Power Other Total Gas Power Other Total (Millions) 2017 $ 284 $ 168 $ 35 $ 487 $ 23 $ 132 $ 4 $ 159 2018 245 108 23 376 4 76 4 84 2019 205 68 14 287 5 53 1 59 2020 161 65 12 238 5 42 — 47 2021 127 52 12 191 — 33 — 33 Thereafter 520 379 109 1,008 — 26 — 26 Totals $ 1,542 $ 840 $ 205 $ 2,587 $ 37 $ 362 $ 9 $ 408

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2016
Income Tax Disclosure [Abstract]
Schedule of Current and Deferred Taxes Charged to (Benefit) Expense	Current and deferred taxes charged to (benefit) expense for the years ended December 31, 2016, 2015 and 2014 consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Current Federal $ (6 ) $ (20 ) $ (10 ) State 8 (33 ) 31 Current taxes charged to (benefit) expense 2 (53 ) 21 Deferred Federal 414 136 218 State 2 (6 ) 82 Deferred taxes charged to expense 416 130 300 Production tax credits (38 ) (42 ) (37 ) Investment tax credits (1 ) (1 ) (2 ) Total Income Tax Expense $ 379 $ 34 $ 282
Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate	The differences between tax expense per the statements of income and tax expense at the 35% statutory federal tax rate for the years ended December 31, 2016, 2015 and 2014 consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Tax expense at federal statutory rate $ 353 $ 105 $ 247 Depreciation and amortization not normalized 61 15 15 Investment tax credit amortization (1 ) (1 ) (2 ) Tax return related adjustments (2 ) 6 2 Production tax credits (38 ) (42 ) (37 ) Tax equity financing arrangements (25 ) (36 ) (11 ) Change in tax reserves — — 3 Changes in New York tax law — — 41 State tax expense (benefit), net of federal benefit 7 (25 ) 32 Non-deductible acquisition costs — 9 — Other, net 24 3 (8 ) Total Income Tax Expense $ 379 $ 34 $ 282
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Non-current Deferred Income Tax Liabilities (Assets) Property related $ 5,195 $ 4,763 Unfunded future income taxes 216 211 Federal and state tax credits (417 ) (367 ) Accumulated deferred investment tax credits 14 15 Federal and state NOL’s (1,397 ) (1,367 ) Joint ventures/partnerships 651 655 Nontaxable grant revenue (581 ) (595 ) Other (171 ) (17 ) Non-current Deferred Income Tax Liabilities 3,510 3,298 Add: Valuation allowance 31 19 Total Non-current Deferred Income Tax Liabilities 3,541 3,317 Less amounts classified as regulatory liabilities Non-current deferred income taxes 565 519 Non-current Deferred Income Tax Liabilities $ 2,976 $ 2,798 Deferred tax assets $ 2,565 $ 2,346 Deferred tax liabilities 6,106 5,663 Net Accumulated Deferred Income Tax Liabilities $ 3,541 $ 3,317
Schedule of Reconciliation of Unrecognized Income Tax Benefits	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2016, 2015 and 2014 consisted of: Years ended December 31, 2016 2015 2014 (Millions) Beginning Balance $ 36 $ 38 $ 41 Increases for tax positions related to prior years 8 1 20 Decreases for tax positions related to prior years (4 ) — — Reduction for tax position related to settlements with taxing authorities — (3 ) (23 ) Ending Balance $ 40 $ 36 $ 38

Post-retirement and Similar O54

Post-retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2016
Schedule of Amounts Recognized in Balance Sheet	Amounts recognized as of December 31, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2016 2015 (Millions) Current liabilities $ — $ — $ (5 ) $ (5 ) Non-current liabilities (776 ) (845 ) (330 ) (358 ) Total $ (776 ) $ (845 ) $ (335 ) $ (363 )
Summary of Amounts Recognized in OCI	Amounts recognized in OCI for ARHI for the years ended December 31, 2016, 2015 and 2014, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 (Millions) Net (gain) loss $ 23 $ 25 $ 22 $ (3 ) $ (1 ) $ 8
Regulatory Assets and Liabilities	Note 6. 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 other 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 NYPSC approved the proposal in connection with a three five ten 16.5 126 fifty Current and non-current regulatory assets as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 22 $ 8 Pension and other post-retirement benefits 7 13 Storm costs 40 8 Temporary supplemental assessment surcharge 4 7 Reliability support services 27 — Revenue decoupling mechanism 15 6 Transmission revenue reconciliation mechanism 12 5 Electric supply reconciliation 13 — Hedges losses 10 37 Contracts for differences 14 18 Hardship programs 16 13 Deferred property tax 10 — Plant decommissioning 6 — Deferred purchased gas 14 12 Deferred transmission expense 13 12 Environmental remediation costs 14 37 Other 48 43 Total Current Regulatory Assets 285 219 Non-current Pension and other post-retirement benefits cost deferrals 134 151 Pension and other post-retirement benefits 1,320 1,509 Storm costs 187 251 Deferred meter replacement costs 32 34 Unamortized losses on reacquired debt 20 23 Environmental remediation costs 287 271 Unfunded future income taxes 542 549 Asset retirement obligations 18 24 Deferred property tax 33 45 Federal tax depreciation normalization adjustment 161 158 Merger capital expense target customer credit 11 15 Debt premium 151 141 Plant decommissioning 14 7 Contracts for differences 61 50 Hardship programs 18 29 Other 102 57 Total Non-current Regulatory Assets $ 3,091 $ 3,314 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG, 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 for 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. CMP’s total deferral, including carrying costs, was $2 million and $12 million as of December 31, 2016 and 2015, respectively. 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 December 31, 2016. “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. “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. “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) represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred 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 “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. “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. “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. “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. “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 December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Current Reliability support services (Cayuga) $ 3 $ 16 Non by-passable charges 22 7 Energy efficiency portfolio standard 45 33 Gas supply charge and deferred natural gas cost 6 6 Transmission revenue reconciliation mechanism 5 16 Pension and other post-retirement benefits 3 3 Pension and other post-retirement benefits cost deferrals 14 — Carrying costs on deferred income tax bonus depreciation 15 — Carrying costs on deferred income tax - Mixed Services 263(a) 5 — Yankee DOE refund 24 5 Merger-related rate credits 3 20 Revenue decoupling mechanism 9 14 Other 38 27 Total Current Regulatory Liabilities 192 147 Non-current Accrued removal obligations 1,117 1,084 Asset sale gain account 9 8 Carrying costs on deferred income tax bonus depreciation 95 116 Economic development 35 36 Merger capital expense target customer credit account 15 17 Pension and other post-retirement benefits 76 90 Positive benefit adjustment 42 51 New York state tax rate change 9 17 Post term amortization 3 25 Theoretical reserve flow thru impact 24 31 Deferred property tax 19 15 Net plant reconciliation 10 10 Variable rate debt 28 32 Carrying costs on deferred income tax - Mixed Services 263(a) 25 31 Rate refund – FERC ROE proceeding 22 21 Transmission congestion contracts 18 — Merger-related rate credits 21 24 Accumulated deferred investment tax credits 15 10 Asset retirement obligation 13 13 Earning sharing provisions 12 — Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge — 21 Low income programs 46 42 Unfunded future income taxes — 27 Non-firm margin sharing credits 7 8 Deferred income taxes regulatory 565 519 Other 73 93 Total Non-current Regulatory Liabilities $ 2,318 $ 2,360 “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 “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 “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 “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 “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 “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 “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five “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 “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. See Merger Settlement Agreement in Note 4 for further details. 20 “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.
Amounts Expected to be Amortized for Net Periodic Benefit Cost	Amounts expected to be amortized from regulatory assets or liabilities into net periodic benefit cost for the year ending December 31, 2017 consists of: Year Ended December 31, 2017 Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 126 $ 5 Estimated prior service cost (benefit) 2 (9 ) Amounts expected to be amortized from OCI into net periodic benefit cost for the year ending December 31, 2017 consists of: Year Ended December 31, 2017 Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 1 $ — Estimated prior service cost (benefit) — —
Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations	Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 Health care cost trend rate assumed for next year - Networks 7.00%/9.00% 7.50%/7.00% Health care cost trend rate assumed for next year - ARHI 6.75%/8.50% 7.00%/9.00% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.50% 4.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.50% 4.50% Year that the rate reaches the ultimate trend rate - Networks 2026 / 2028 2027 Year that the rate reaches the ultimate trend rate - ARHI 2026 / 2028 2026
One Percent Change in Assumed Health Care Cost Trend Rates	The effects of a one-percent change in the assumed health care cost trend rates would have the following effects: 1% Increase 1% Decrease (Millions) Effect on total of service and interest cost $ 1 $ (1 ) Effect on postretirement benefit obligation $ 14 $ (12 )
Fair Values of Pension Benefits Plan Assets, by Asset Category	The fair values of pension benefits plan assets, by asset category, as of December 31, 2016 consisted of: As of December 31, 2016 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 49 $ — $ 49 $ — U.S. government securities 172 172 — — Common stocks 120 120 — — Registered investment companies 122 122 — — Corporate bonds 358 — 358 — Preferred stocks 4 — 4 — Common collective trusts 1,192 — 371 821 Partnerships/joint venture interests 5 — — 5 Real estate investments 61 — — 61 Other, principally annuity, fixed income 589 — 315 274 Total $ 2,672 $ 414 $ 1,097 $ 1,161 The fair values of pension benefits plan assets, by asset category, as of December 31, 2015 consisted of: As of December 31, 2015 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 57 $ 3 $ 54 $ — U.S. government securities 171 171 — — Common stocks 314 314 — — Registered investment companies 114 114 — — Corporate bonds 324 — 324 — Preferred stocks 5 — 5 — Common collective trusts 859 — 369 490 Partnership/joint venture interests 84 — — 84 Real estate investments 89 — — 89 Other, principally annuity, fixed income 647 — 329 318 Total $ 2,664 $ 602 $ 1,081 $ 981
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliations of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2016, 2015 and 2014 consisted of: (Millions) 2016 2015 2014 Fair value as of January 1, $ (19 ) $ 57 $ 53 Gains for the year recognized in operating revenues 67 33 11 Losses for the year recognized in operating revenues — (8 ) (1 ) Total gains or losses for the period recognized in operating revenues 67 25 10 Gains recognized in OCI 1 2 — Losses recognized in OCI — (3 ) (3 ) Total gains or losses recognized in OCI 1 (1 ) (3 ) Net change recognized in regulatory assets and liabilities (8 ) — — Purchases 3 (73 ) 14 Settlements (9 ) (14 ) (26 ) Transfers out of Level 3 (a) (4 ) (13 ) 9 Fair value as of December 31, $ 31 $ (19 ) $ 57 Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date $ 67 $ 25 $ 10 (a) Transfers out of Level 3 were the result of increased observability of market data. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input December 31, 2016 Risk of non-performance 0.68% - 0.81% Discount rate 1.47% - 2.45% Forward pricing ($ per MW) $3.15 - $9.55
Fair Value of Other Postretirement Benefits Plan Assets, by Asset Category	The fair value of other postretirement benefits plan assets, by asset category, as of December 31, 2016 consisted of: As of December 31, 2016 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 6 $ 4 $ 2 $ — Mutual funds, fixed 41 39 2 — Government and corporate bonds 2 — 2 — Mutual funds, equity 72 43 29 — Common stocks 23 23 — — Mutual funds, other 16 9 7 — Total $ 160 $ 118 $ 42 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2015 consisted of: As of December 31, 2015 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 4 $ 4 $ — $ — Mutual funds, fixed 36 36 — — Government and corporate bonds 2 — 2 — Mutual funds, equity 46 46 — — Common stocks 24 24 — — Mutual funds, other 50 43 7 — Total $ 162 $ 153 $ 9 $ —
Level 3 [Member]
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliation of changes in fair value of plan assets based on Level 3 inputs for the years ended December 31, 2016 and 2015, consisted of: (Millions) Common Collective Trusts Partnership Joint Venture Interests Real Estate Investments Other Investments Total As of December 31, 2014 $ 449 $ 79 $ 75 $ 342 $ 945 Actual return on plan assets: Relating to assets sold during the year (3 ) (19 ) — 1 (21 ) Relating to assets still held at the reporting date (5 ) 19 10 (21 ) 3 Purchases, sales and settlements 49 5 4 (4 ) 54 As of December 31, 2015 $ 490 $ 84 $ 89 $ 318 $ 981 Actual return on plan assets: Relating to assets sold during the year 6 (19 ) — 1 (12 ) Relating to assets still held at the reporting date 51 — 2 (8 ) 45 Purchases, sales and settlements 274 (60 ) (30 ) (37 ) 147 As of December 31, 2016 $ 821 $ 5 $ 61 $ 274 $ 1,161
Networks and ARHI [Member]
Obligations and Funded Status	Obligations and funded status of Networks and ARHI as of December 31, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2016 2015 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 3,509 $ 2,620 $ 525 $ 435 Acquisition of UIL — 1,019 — 122 Service cost 44 36 5 5 Interest cost 142 99 21 16 Plan participants’ contributions — — 7 4 Plan amendments — — — (1 ) Actuarial gain (43 ) (105 ) (24 ) (31 ) Special termination benefits — 2 — — Benefits paid (204 ) (162 ) (39 ) (25 ) Benefit Obligation as of December 31, 3,448 3,509 495 525 Change in plan assets Fair value of plan assets as of January 1, 2,664 2,143 162 129 Acquisition of UIL — 687 — 39 Actual return on plan assets 169 (31 ) 11 (4 ) Employer contributions 43 27 30 21 Plan participants’ contributions — — 7 4 Benefits paid (204 ) (162 ) (39 ) (25 ) Withdrawals from VEBA — — (11 ) (2 ) Fair Value of Plan Assets as of December 31, 2,672 2,664 160 162 Funded Status as of December 31, $ (776 ) $ (845 ) $ (335 ) $ (363 )
Aggregate Projected and Accumulated Benefit Obligations and Fair Value of Plan Assets for Underfunded Plans	The aggregate projected and accumulated benefit obligations and the fair value of plan assets for underfunded plans of Networks and ARHI as of December 31, 2016 and 2015 consisted of: Projected Benefit Obligation Exceeds Fair Value of Plan Assets Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets As of December 31, 2016 2015 2016 2015 (Millions) Projected benefit obligation $ 3,448 $ 3,509 $ 3,448 $ 3,509 Accumulated benefit obligation 3,214 3,261 3,214 3,261 Fair value of plan assets 2,672 2,664 2,672 2,664
Weighted Average Assumptions Used to Determine Benefit Obligations and Net periodic Benefit Cost	The weighted-average assumptions used to determine benefit obligations for Networks and ARHI as of December 31, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2016 2015 Discount rate - Networks 4.12% / 4.24% 4.10% / 4.24% 4.12% / 4.24% 4.10% / 4.24% Discount rate - ARHI 3.81% 3.90% 3.81% 3.90% Rate of compensation increase - Networks 3.50% - 4.20% 4.00% — — The weighted-average assumptions used to determine net periodic benefit cost for Networks and ARHI for the years ended December 31, 2016, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 Discount rate - Networks 4.12% / 4.24% 3.80% / 4.24% 4.90 % 4.12% / 4.24% 3.80% / 4.24% 4.90 % Discount rate - ARHI 3.90% 3.90% 5.00 % 3.90% 3.90% 5.00 % Expected long-term return on plan assets - Networks 7.40% / 7.75% 7.50% 7.50 % 7.16% — — Expected long-term return on plan assets - ARHI 5.50% 5.50% 6.90 % 5.50% 5.75% 6.50 % Expected long-term return on plan assets - nontaxable trust - Networks — — — 7.00% 7.50% 7.50 % Expected long-term return on plan assets - taxable trust - Networks — — — 4.50% 5.00% 5.00 % Rate of compensation increase - Networks 3.50% - 4.20% 4.10% 4.20 % — — —
Networks and ARHI [Member] | Improvement and Modernization Act of 2003 [Member]
Expected Future Benefits Payments	Expected benefit payments and Medicare Prescription Drug, Improvement and Modernization Act of 2003 subsidy receipts reflecting expected future service for Networks and ARHI as of December 31, 2016 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2017 $ 211 $ 34 $ — 2018 212 34 — 2019 216 34 — 2020 219 35 — 2021 224 35 — 2022 - 2026 1,125 169 3
Iberdrola Renewables Holding, Inc. (IRHI) [Member]
Regulatory Assets and Liabilities	Amounts recognized as regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2016, 2015 and 2014 for Networks consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2016 2015 2014 2016 2015 2014 (Millions) Net loss $ 860 $ 994 $ 1,045 $ 44 $ 76 $ 96 Prior service cost (credit) 7 9 12 (40 ) (49 ) (57 )
Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations	Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities as of December 31, 2016, 2015 and 2014 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2014 2016 2015 2014 Net Periodic Benefit Cost: Service cost $ 44 $ 36 $ 30 $ 5 $ 4 $ 4 Interest cost 140 97 107 20 15 17 Expected return on plan assets (199 ) (156 ) (161 ) (8 ) (7 ) (7 ) Amortization of prior service cost (benefit) 2 3 4 (9 ) (9 ) (11 ) Amortization of net loss 123 130 94 8 7 — Special termination benefit charge — 2 — — — — Settlement charge — 2 — — — — Net Periodic Benefit Cost 110 114 74 16 10 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Settlements $ — $ (2 ) $ — $ — $ — $ — Net loss (gain) (11 ) 69 434 (24 ) (12 ) 72 Amortization of net loss (123 ) (130 ) (94 ) (8 ) (7 ) — Current year prior service cost — — — — (1 ) — Amortization of prior service (cost) benefit (2 ) (3 ) (4 ) 9 9 11 Total Other Changes (136 ) (66 ) 336 (23 ) (11 ) 83 Total Recognized $ (26 ) $ 48 $ 410 $ (7 ) $ (1 ) $ 86
Iberdrola Renewables Holding, Inc [Member]
Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations	Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI as of December 31, 2016, 2015 and 2014 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2016 2015 2014 2016 2015 2014 Net Periodic Benefit Cost: Service cost $ — $ — $ — $ — $ 1 $ 1 Interest cost 2 2 2 1 1 1 Expected return on plan assets (2 ) (2 ) (3 ) — — — Amortization of prior service cost - — — — — 1 Amortization of net loss 1 1 — — — 1 Settlement charge 1 — — — — — Net Periodic Benefit Cost (income) 2 1 (1 ) 1 2 4 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) — 4 6 (2 ) (8 ) (5 ) Amortization of net loss (1 ) (1 ) — — — (1 ) Amortization of prior service (cost) — — — — — (1 ) Total Other Changes (1 ) 3 6 (2 ) (8 ) (7 ) Total Recognized $ 1 $ 4 $ 5 $ (1 ) $ (6 ) $ (3 )

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2016
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) Accumulated OCI for the years ended December 31, 2016, 2015 and 2014 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2013 2014 Change As of December 31, 2014 2015 Change As of December 31, 2015 2016 Change As of December 31, 2016 (Millions) Loss on revaluation of defined benefit plans, net of income tax expense of $0.6 for 2014, $2.2 for 2015 and $4.3 for 2016 $ (26 ) $ 1 $ (25 ) $ 4 $ (21 ) $ 7 $ (14 ) Loss for nonqualified pension plans, net of income tax expense (benefit) of $(1.9) for 2014, $1.7 for 2015 and $0.4 for 2016 (8 ) (3 ) (11 ) 3 (8 ) 1 (7 ) Unrealized (loss) gain on derivatives qualifying as cash flow hedges: Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of ($1.4) for 2014, $20.9 for 2015 and $(15.8) for 2016 — (2 ) (2 ) 33 31 (26 ) 5 Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense (benefit) of $4.1 for 2014, $4.9 for 2015 and $(11.0) for 2016 (a) (66 ) 5 (61 ) 7 (54 ) (16 ) (70 ) Net unrealized (loss) gain on derivatives qualifying as cash flow hedges (66 ) 3 (63 ) 40 (23 ) (42 ) (65 ) Accumulated Other Comprehensive (Loss) Income $ (100 ) $ 1 $ (99 ) $ 47 $ (52 ) $ (34 ) $ (86 ) (a) Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2016, 2015 and 2014, consisted of: Years Ended December 31, 2016 2015 2014 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 630 $ 267 $ 424 Denominator: Weighted average number of shares outstanding - basic 309,512,553 254,588,212 252,235,232 Weighted average number of shares outstanding - diluted 309,817,322 254,605,111 252,235,232 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 2.04 $ 1.05 $ 1.68 Earnings Per Common Share, Diluted $ 2.04 $ 1.05 $ 1.68

Grants, Government Incentives57

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2016
Deferred Revenue Disclosure [Abstract]
Schedule of Changes in Deferred Income	The changes in deferred income as of December 31, 2016 and 2015 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2014 $ 1,606 $ 15 $ 1,621 Additions — — — Recognized in income (77 ) 9 (68 ) As of December 31, 2015 $ 1,529 $ 24 $ 1,553 Additions — — — Recognized in income (68 ) (2 ) (70 ) As of December 31, 2016 $ 1,461 $ 22 $ 1,483

Other Financial Statements It58

Other Financial Statements Items (Tables)	12 Months Ended
	Dec. 31, 2016
Receivables [Abstract]
Schedule of Other Income and (Expense)	Other income and (expense) for the years ended December 31, 2016, 2015 and 2014 consisted of: Years ended December 31, 2016 2015 2014 (Millions) Allowance for funds used during construction $ 26 $ 21 $ 17 Carrying costs on regulatory assets 14 28 29 Other 36 6 6 Total Other income and (expense) $ 76 $ 55 $ 52
Schedule of Accounts Receivable	Accounts receivable as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Trade receivables $ 1,183 $ 1,036 Allowance for bad debts (64 ) (62 ) Total Accounts Receivable $ 1,119 $ 974
Schedule of Change in Allowance For Bad Debts	The change in the allowance for bad debts as of December 31, 2016 and 2015 consisted of: (Millions) As of December 31, 2013 58 Current period provision 39 Write-off as uncollectible (48 ) As of December 31, 2014 $ 49 Current period provision 46 Write-off as uncollectible (33 ) As of December 31, 2015 $ 62 Current period provision 48 Write-off as uncollectible (46 ) As of December 31, 2016 $ 64
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Prepaid other taxes $ 153 $ 130 Broker margin and collateral accounts 32 46 Loans to third parties 3 3 Fixed-term deposits 3 11 Other pledged deposits 8 24 Prepaid expenses 53 53 Other 3 18 Total $ 255 $ 285
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2016 and 2015 consisted of: As of December 31, 2016 2015 (Millions) Advances received $ 107 $ 96 Accrued salaries 84 68 Short-term environmental provisions 34 35 Collateral deposits received 45 59 Pension and other postretirement 5 5 Other 4 22 Total $ 279 $ 285

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2016
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the year ended December 31, 2016 consisted of: For the year ended December 31, 2016 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 5,027 $ 1,000 $ (7 ) $ (2 ) $ 6,018 Revenue - intersegment 3 15 39 (57 ) — Depreciation and amortization 466 313 25 — 804 Operating income (loss) from continuing operations 1,086 149 (41 ) — 1,194 Adjusted EBITDA 1,552 462 (16 ) — 1,998 Earnings (loss) from equity method investments 15 (8 ) — — 7 Capital expenditures 1,140 561 6 — 1,707 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. I Segment information as of and for the year ended December 31, 2015 consisted of: For the year ended December 31, 2015 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,386 $ 1,051 $ (71 ) $ 1 $ 4,367 Revenue - intersegment — 16 52 (68 ) — Impairment of noncurrent assets — 12 — — 12 Depreciation and amortization 328 344 23 — 695 Operating income (loss) from continuing operations 537 100 (85 ) (39 ) 513 Adjusted EBITDA 865 456 (62 ) (39 ) 1,220 Earnings (loss) from equity method investments 1 (5 ) — 4 — Capital expenditures 773 304 5 — 1,082 As of December 31, 2015 Property, plant and equipment 12,363 7,835 513 — 20,711 Equity method investments 110 253 — 22 385 Total assets $ 20,126 $ 10,685 $ 1,265 $ (1,333 ) $ 30,743 (a) Does not represent a segment. I Segment information as of and for the year ended December 31, 2014 consisted of: For the year ended December 31, 2014 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,396 $ 1,180 $ 12 $ 6 $ 4,594 Revenue - intersegment 1 9 72 (82 ) — Impairment of noncurrent assets — 24 — 1 25 Depreciation and amortization 275 332 22 — 629 Operating income (loss) from continuing operations 616 257 16 (4 ) 885 Adjusted EBITDA 891 613 38 (3 ) 1,539 Earnings from equity method investments — 2 — 10 12 Capital expenditures 775 250 5 — 1,030 As of December 31, 2014 Property, plant and equipment 8,389 8,219 525 — 17,133 Equity method investments — 262 — — 262 Total assets $ 12,858 $ 12,328 $ 1,393 $ (2,417 ) $ 24,162 (a) Does not represent a segment. I
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income	Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the years ended December 31, 2016, 2015 and 2014, respectively, is as follows: Years Ended December 31, 2016 2015 2014 (Millions) Consolidated Adjusted EBITDA $ 1,998 $ 1,220 $ 1,539 Less: Impairment of non-current assets — 12 25 Depreciation and amortization 804 695 629 Interest expense, net of capitalization 268 267 243 Income tax expense 379 34 282 Add: Other income 76 55 52 Earnings from equity method investments 7 — 12 Consolidated Net Income $ 630 $ 267 $ 424

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the years ended December 31, 2016, 2015 and 2014, respectively, consisted of: Years Ended December 31, 2016 2015 2014 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Financiación, S.A. $ — $ (2 ) — $ (1 ) — $ (2 ) Iberdrola Renovables Energia, S.L. — (8 ) — (9 ) — (10 ) Iberdrola Canada Energy Services, Ltd — (37 ) — (55 ) — (49 ) Iberdrola, S.A. — (31 ) — (35 ) — (20 ) Other 21 (1 ) 3 (2 ) 12 (10 )
Schedule of Related Party Balances	Related party balances as of December 31, 2016 and 2015, respectively, consisted of: As of December 31, 2016 2015 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd $ — $ (14 ) $ 7 $ (5 ) Gamesa Corporación Tecnológica, S.A. 1 (181 ) 68 (77 ) Iberdrola, S.A. — (30 ) — (3 ) Iberdrola Energy Projects, Inc. — — 1 (3 ) Iberdrola Renovables Energía, S.L. 2 — — — Other 22 (3 ) — (2 )

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2016
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Nonvested PSUs	A summary of the status of the AVANGRID's nonvested PSUs as of December 31 , 2016 December 31, 2016 Number of PSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2015 411,207 $ 39.60 Granted 1,335,416 $ 31.92 Forfeited (36,592 ) $ 32.83 Vested (186,050 ) $ 40.84 Nonvested Balance – December 31, 2016 1,523,981 $ 33.01

Quarterly Financial Data (una62

Quarterly Financial Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2016
Selected Quarterly Financial Information [Abstract]
Schedule of Quarterly Financial Data	Selected quarterly financial data for 2016 and 2015 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 2016 Operating revenues $ 1,670 $ 1,439 $ 1,418 $ 1,491 Operating Income $ 349 $ 322 $ 217 $ 306 Net Income $ 212 $ 102 $ 109 $ 207 Net Income attributable to Avangrid, Inc. $ 212 $ 102 $ 109 $ 207 Earnings Per Common Share, Basic and Diluted: (1) $ 0.69 $ 0.33 $ 0.35 $ 0.67 2015 Operating revenues $ 1,227 $ 939 $ 1,048 $ 1,153 Operating Income $ 196 $ 73 $ 161 $ 83 Net Income $ 106 $ 11 $ 54 $ 96 Net Income attributable to Avangrid, Inc. $ 106 $ 11 $ 54 $ 96 Earnings Per Common Share, Basic and Diluted: (1) $ 0.42 $ 0.04 $ 0.22 $ 0.37

Cash Dividends Paid by Subsid63

Cash Dividends Paid by Subsidiaries (Tables)	12 Months Ended
	Dec. 31, 2016
Avangrid, Inc [Member]
Schedule of Cash Dividends Paid by Subsidiaries	Cash dividends paid by subsidiaries are as follows: Years ended December 31, 2016 2015 2014 (In millions) AVANGRID Networks $ 220 $ 59 $ 200 AVANGRID Renewables 200 750 — Other AVANGRID subsidiaries — 302 — $ 420 $ 1,111 $ 200

Background and Nature Of Oper64

Background and Nature Of Operations - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Nature Of Business [Line Items]
Owned Subsidiaries	81.50%
Effective date of business acquisition of UIL Holdings	Feb. 25, 2015
Shares issued in connection with acquisition	309,490,839
Shares issued in connection with the acquisition at par value | $ / shares	$ 10.50
Membership interest	50.00%
Iberdrola, S.A. [Member]
Nature Of Business [Line Items]
Shares issued in connection with acquisition	252,234,989
UIL Holdings [Member]
Nature Of Business [Line Items]
Shares issued in connection with acquisition	57,255,850
Shares issued in connection with the acquisition at par value | $ / shares	$ 0.01
Percentage of ownership	18.50%
Issuance of share in connection of acquisition	In connection with the acquisition, we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including those held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per each share of the common stock of UIL issued and outstanding at the acquisition date.
NEW YORK
Nature Of Business [Line Items]
Incorporation date of organization	Jan. 1, 1997

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Service Life [Member]
Change In Accounting Estimate [Line Items]
Decrease in depreciation and amortization expense	$ 52
Decrease in asset retirement obligation accretion expense	3
Increase in earnings from equity method investments	4
Estimated increase in net income	$ 36
Increase in earnings per share, basic	$ 0.12
Increase in earnings per share, diluted	$ 0.12
Estimated increase in income before income tax	$ 59
Wind Power Stations [Member]
Change In Accounting Estimate [Line Items]
Depreciation rate		4.00%	4.00%
Estimated useful life	40 years
Wind Power Stations [Member] | Wind Farm Assets [Member]
Change In Accounting Estimate [Line Items]
Estimated useful life	31 years
Wind Power Stations [Member] | Scenario, Previously Reported [Member]
Change In Accounting Estimate [Line Items]
Estimated useful life		25 years

Summary of Significant Accoun66

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accounting Polices [Line Items]
Percentage of tax returns included in taxable income	80.00%
Increase (decrease) in restricted cash and cash equivalents		$ 2,000,000	$ 0
Percentage of employees covered by collective bargaining agreement	48.00%
Percentage of expiry	6.00%
Minimum [Member]
Accounting Polices [Line Items]
Finite lived intangible assets useful economic life	4 years
Maximum [Member]
Accounting Polices [Line Items]
Finite lived intangible assets useful economic life	40 years

Summary of Significant Accoun67

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives (Detail)	12 Months Ended
	Dec. 31, 2016
Wind Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	40 years
Plant [Member] | Combined Cycle Plants [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	35 years
Minimum [Member] | Plant [Member] | Hydroelectric Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	35 years
Minimum [Member] | Plant [Member] | Wind Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	25 years
Minimum [Member] | Plant [Member] | Gas Storage [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	25 years
Minimum [Member] | Plant [Member] | Transport Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	40 years
Minimum [Member] | Plant [Member] | Distribution Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	30 years
Minimum [Member] | Equipment [Member] | Conventional Meters And Measuring Devices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	15 years
Minimum [Member] | Other [Member] | Buildings [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	50 years
Minimum [Member] | Other [Member] | Operations Offices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	4 years
Minimum [Member] | Other [Member] | Computer Software[Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	3 years
Maximum [Member] | Plant [Member] | Hydroelectric Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	90 years
Maximum [Member] | Plant [Member] | Wind Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	40 years
Maximum [Member] | Plant [Member] | Gas Storage [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	40 years
Maximum [Member] | Plant [Member] | Transport Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	56 years
Maximum [Member] | Plant [Member] | Distribution Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	54 years
Maximum [Member] | Equipment [Member] | Conventional Meters And Measuring Devices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	27 years
Maximum [Member] | Other [Member] | Buildings [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	75 years
Maximum [Member] | Other [Member] | Operations Offices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	50 years
Maximum [Member] | Other [Member] | Computer Software[Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	5 years

Acquisition of UIL - Additional

Acquisition of UIL - Additional Information (Detail) - USD ($)	Dec. 16, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Aug. 04, 2016
Business Acquisition [Line Items]
Shares issued in connection with acquisition		309,490,839
Common stock, par value		$ 0.01	$ 0.01
Payments to acquire business, cash paid	$ 595,000,000
Business acquisition, share price		$ 10.50
Revenue			$ 5,958,000,000	$ 6,226,000,000
Business acquisition, Net income (loss)			468,000,000	$ 539,000,000
Goodwill		$ 3,124,000,000	3,115,000,000
Costs related to investigation and remediation		388,000,000	397,000,000
Fair value of contingent liability		46,000,000
Regulatory liabilities		19,800,000
Merger Related Rate Credits [Member]
Business Acquisition [Line Items]
Regulatory liabilities		44,000,000
DEEP [Member]
Business Acquisition [Line Items]
Business combination contribution to stimulate investment		$ 2,000,000
Contribution term to stimulate investment		3 years
Connecticut [Member]
Business Acquisition [Line Items]
Contribution for disaster relief entities		$ 1,000,000
Minimum year of charitable contribution at historical contribution levels		4 years
Connecticut [Member] | Minimum [Member]
Business Acquisition [Line Items]
Business combination expected merger related costs		$ 500,000
Charitable contribution at historical contribution levels		500,000
Connecticut [Member] | Maximum [Member]
Business Acquisition [Line Items]
Charitable contribution at historical contribution levels		800,000
Massachusetts [Member] | Minimum [Member]
Business Acquisition [Line Items]
Business combination expected merger related costs		500,000
AVANGRID [Member]
Business Acquisition [Line Items]
Payments to acquire business, cash paid			595,000,000
Southern Connecticut Gas Company (SCG) [Member]
Business Acquisition [Line Items]
Business combination additional rate credits		$ 750,000
Business combination rate credit allocation period		10 years
Savings to SCG customers		$ 1,600,000
UI [Member]
Business Acquisition [Line Items]
Regulatory liabilities		0	1,000,000
UI [Member] | Connecticut [Member]
Business Acquisition [Line Items]
Benefits to customers		5,000,000
Investment in storm resiliency programs		50,000,000
United Illuminating Company (UI)
Business Acquisition [Line Items]
Costs related to investigation and remediation		28,300,000	20,500,000		$ 30,000,000
Estimated environmental liability		1,700,000	9,500,000
Difference in pretax reflected as reversal of expense		7,800,000
United Illuminating Company (UI) | Maximum [Member]
Business Acquisition [Line Items]
Cost of investigation and remediation		30,000,000
The Berkshire Gas Company [Member] | Massachusetts [Member]
Business Acquisition [Line Items]
Customers receivable rate credits		4,000,000
Contribution to alternative heating programs		1,000,000
Connecticut Natural Gas Corporation (CNG) [Member]
Business Acquisition [Line Items]
Business combination additional rate credits		$ 1,250,000
Business combination rate credit allocation period		10 years
UIL Holdings [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	57,255,850
Payments to acquire business, cash paid	$ 595,000,000
Business combination, date of acquisition		Dec. 16, 2015
Number of Consecutive Trading Days	10 days
Business acquisition, share price	$ 50.10	$ 10.50
Business combination, transaction costs			37,500,000
Revenue			36,000,000
Business acquisition, Net income (loss)			$ (36,000,000)
Goodwill		$ 1,765,000,000
UIL Holdings [Member] | Restatement Adjustment
Business Acquisition [Line Items]
Goodwill		11,000,000
UIL Holdings [Member] | AVANGRID [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	309,490,839
Common stock, par value	$ 0.01
Percentage of ownership	18.50%
Business acquisition, share price	$ 10.50
UIL Holdings [Member] | AVANGRID [Member] | Iberdrola, S.A. [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	252,234,989
UIL Holdings [Member] | AVANGRID [Member] | UIL shareowners [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	57,255,850
Connecticut [Member]
Business Acquisition [Line Items]
Business combination amount allocated for rate credits to customers		$ 20,000,000

Acquisition of UIL - Summary of

Acquisition of UIL - Summary of Fair Value of Purchase Consideration (Detail) - USD ($) $ / shares in Units, $ in Millions		Dec. 16, 2015	Dec. 31, 2016		Dec. 31, 2015	[1]	Dec. 15, 2015	Dec. 31, 2014	[1]	Dec. 31, 2013	[1]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Common shares			308,993,149	[1]	308,864,609		252,235,232	252,235,232		252,235,232
Business acquisition, share price			$ 10.50
Shares issued in connection with acquisition			309,490,839
Total consideration		$ 2,873
Performance Shares [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Vesting shares			186,050
UIL Holdings [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Common shares	[2]	56,629,377
Business acquisition, share price		$ 50.10	$ 10.50
Subtotal value of common shares		$ 2,837
Other shares	[3]	12,999
Shares issued in connection with acquisition		57,255,850
UIL Holdings [Member] | Restricted Stock Units [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Vesting shares	[4]	476,198
Equity exchange factor		1.2806%
UIL Holdings [Member] | Restricted Stock Units and Other [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Total shares after applying an equity exchange factor	[3]	626,473
Price per share used	[5]	$ 39.60
Subtotal value of shares		$ 25
UIL Holdings [Member] | Performance Shares [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Vesting shares	[6]	211,904
Equity exchange factor		1.2806%
Total shares after applying an equity exchange factor		271,368
Price per share used	[5]	$ 39.60
Subtotal value of shares		$ 11
Total consideration		$ 2,873
[1]	Par value of share amounts is $.01
[2]	Based on UIL’s common shares outstanding on December 16, 2015.
[3]	Based on UIL’s restricted shares that vested upon the change in control.
[4]	Based on UIL’s shares of vested restricted stock.
[5]	Based on the closing share price of UIL common stock on December 16, 2015, less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under the UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.
[6]	Based on UIL’s vested performance shares award.

Acquisition of UIL - Summary 70

Acquisition of UIL - Summary of Fair Value of Purchase Consideration (Detail) (Parenthetical)	Dec. 16, 2015$ / shares
UIL Holdings [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Cash paid per common share	$ 10.50

Acquisition of UIL - Summary 71

Acquisition of UIL - Summary of Components of Estimated Consideration Transferred (Detail) $ in Millions	Dec. 16, 2015USD ($)
Business Combination Consideration Transferred [Abstract]
Payments to acquire business, cash paid	$ 595
Equity	2,278
Total consideration	$ 2,873

Acquisition of UIL - Summary 72

Acquisition of UIL - Summary of Components of Estimated Consideration Transferred (Parenthetical) (Detail) - $ / shares		Dec. 31, 2016	[1]	Dec. 31, 2015	[1]	Dec. 16, 2015	Dec. 15, 2015	Dec. 31, 2014	[1]	Dec. 31, 2013	[1]
Business Combination Consideration Transferred [Line Items]
Common shares outstanding		308,993,149		308,864,609			252,235,232	252,235,232		252,235,232
UIL Holdings [Member]
Business Combination Consideration Transferred [Line Items]
Cash paid per common share						$ 10.50
Common shares outstanding	[2]					56,629,377
[1]	Par value of share amounts is $.01
[2]	Based on UIL’s common shares outstanding on December 16, 2015.

Acquisition of UIL - Schedule o

Acquisition of UIL - Schedule of Unaudited Pro Forma Results (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition Pro Forma Information [Abstract]
Revenue	$ 5,958	$ 6,226
Net income	$ 468	$ 539

Acquisition of UIL - Summary 74

Acquisition of UIL - Summary of Allocation of Purchase Price (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 16, 2015
Business Acquisition [Line Items]
Goodwill – consideration transferred in excess of fair value assigned	$ 3,124	$ 3,115
UIL Holdings [Member]
Business Acquisition [Line Items]
Current assets, including cash of $48 million	493
Other investments	136
Property, plant and equipment	3,547
Regulatory assets	1,002
Other assets	52
Current liabilities	(493)
Regulatory liabilities	(493)
Non-current debt	(1,905)
Other liabilities	(1,231)
Total net assets acquired at fair value	1,108
Goodwill – consideration transferred in excess of fair value assigned	1,765
Total consideration	2,873
UIL Holdings [Member] | Scenario, Previously Reported [Member]
Business Acquisition [Line Items]
Current assets, including cash of $48 million			$ 500
Other investments			114
Property, plant and equipment			3,552
Regulatory assets			966
Other assets			52
Current liabilities			(493)
Regulatory liabilities			(493)
Non-current debt			(1,878)
Other liabilities			(1,201)
Total net assets acquired at fair value			1,119
Goodwill – consideration transferred in excess of fair value assigned			1,754
Total consideration			$ 2,873
UIL Holdings [Member] | Restatement Adjustment
Business Acquisition [Line Items]
Current assets, including cash of $48 million	(7)
Other investments	22
Property, plant and equipment	(5)
Regulatory assets	36
Non-current debt	(27)
Other liabilities	(30)
Total net assets acquired at fair value	(11)
Goodwill – consideration transferred in excess of fair value assigned	$ 11

Acquisition of UIL - Summary 75

Acquisition of UIL - Summary of Allocation of Purchase Price (Parenthetical) (Detail) $ in Millions	Dec. 16, 2015USD ($)
Business Combinations [Abstract]
Purchase price allocation, cash	$ 48

Industry Regulation - Additiona

Industry Regulation - Additional Information (Detail)

Mar. 31, 2017USD ($)

May 03, 2016

Nov. 05, 2015

Oct. 21, 2015USD ($)

Apr. 02, 2015

Jul. 03, 2014

Jan. 22, 2014

Oct. 23, 2013USD ($)MWh

Sep. 01, 2012USD ($)

Dec. 31, 2016USD ($)Plant

Dec. 31, 2014

Jan. 31, 2014ContractMW

Aug. 31, 2010USD ($)

Dec. 31, 2017USD ($)

Dec. 31, 2016USD ($)CompanyInstallmentPlant

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Sep. 30, 2012USD ($)

Mar. 31, 2010USD ($)MW

Industry Regulation [Line Items]

Number of networks supply companies | Company

4

Purchase obligation per year

$ 2,587,000,000

$ 2,587,000,000

Depreciation and amortization

$ 804,000,000

$ 695,000,000

$ 629,000,000

Approved return on equity

9.18%

10.50%

Customer receiving percentage

50.00%

Percentage of earnings sharing lower of actual equity

50.00%

50.00%

Purchase power, description

UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts

Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2017

80.00%

Percentage of standard service customers with wholesale power supply agreements in place for the first half of 2018

20.00%

Public utilities regulatory authority distribution rate

9.15%

Increase (decrease) in distribution rates

9.10%

Modified agreement monthly payment amount

$ 15,400,000

Minimum deferred cost required for offset per month

$ 2,300,000

$ 2,300,000

Number of installments for payment of capital recovery balance | Installment

8

Ownership interest

50.00%

50.00%

Requested return on equity base percentage

9.55%

9.20%

Basis point added to return on equity

0.25%

Common equity ratio maximum dividend restriction threshold to set rates

3.00%

Number of average months used to set rate

13 months

Restricted net assets

$ 4,291,000,000

$ 4,291,000,000

Number of megawatts of grid connected renewable energy allowed to be developed by UI (in MW) | MWh

10

Current authorized distribution ROE for CL&P

9.17%

Cost of renewable connections program

$ 47,000,000

Number of megawatts energy to be produced by existing biomass facilities | MW

5.7

Number of long term contracts to purchase RECs from existing biomass facilities | Contract

3

Ratio of equity investment in peaking generation for joint venture

50.00%

Number of peaking generation plants | Plant

2

2

New York Transco [Member]

Industry Regulation [Line Items]

Customer receiving percentage

53.00%

Return on equity

9.50%

Ownership interest

20.00%

20.00%

Requested return on equity base percentage

10.60%

Requested return on equity basis points incentive

1.50%

Applicants requested

0.50%

Basis point added to return on equity

0.50%

Scenario, Forecast [Member]

Industry Regulation [Line Items]

Capital recovery payments period

75 days

Estimated capital recovery balance

$ 20,100,000

Minimum [Member]

Industry Regulation [Line Items]

Requested return on equity base percentage

14.55%

Maximum [Member]

Industry Regulation [Line Items]

Approved return on equity

11.74%

CMP Distribution [Member]

Industry Regulation [Line Items]

Distribution rate review process

On May 1, 2013, CMP submitted its required distribution rate request with the Maine Public Utilities Commission (MPUC). On July 3, 2014, after a fourteen month review process, CMP filed a rate stipulation agreement on the majority of the financial matters with the MPUC. The stipulation agreement was approved by the MPUC on August 25, 2014. The stipulation agreement also noted that certain rate design matters would be litigated, which the MPUC ruled on October 14, 2014.

Distribution rate review process period

14 months

Annual distribution tariff increase percentage

10.70%

Annual distribution tariff increase

$ 24,300,000

Distribution tariff rate increased based on ROE

9.45%

Distribution tariff rate increased based on equity capital

50.00%

Recovery mechanism when storm cost exceed

$ 3,500,000

$ 3,500,000

Sharing basis of storm cost

fifty-fifty

Business combination, date of acquisition

Mar. 31, 2010

Period of purchase commitment

20 years

Number of megawatts energy to be purchased from evergreen Rollins wind | MW

60

Purchase obligation per year

$ 7,000,000

Recovery Of Deferred Cost

$ 123,000,000

CMP Distribution [Member] | Minimum [Member]

Industry Regulation [Line Items]

Exposure limit of storm cost

$ 3,000,000

NYSEG [Member]

Industry Regulation [Line Items]

Depreciation and amortization

$ 15,200,000

Excess depreciation reserve

$ 303,900,000

Depreciation amortization period

20 years

RG&E [Member]

Industry Regulation [Line Items]

Depreciation and amortization

$ 5,300,000

Excess depreciation reserve

$ 105,000,000

Depreciation amortization period

20 years

NYSEG Gas [Member]

Industry Regulation [Line Items]

Approved return on equity

9.00%

Equity Ratio

48.00%

48.00%

Customer receiving percentage

50.00%

Return on equity

9.50%

RG&E Electric [Member]

Industry Regulation [Line Items]

Approved return on equity

9.00%

Equity Ratio

48.00%

48.00%

Customer receiving percentage

75.00%

Return on equity

10.00%

Percentage of revenue entitled

70.00%

70.00%

Maximum amount of investment under credit agreement

$ 110,000,000

$ 110,000,000

RG&E Electric [Member] | Deferred Storm Cost Amortization 1 Year [Member]

Industry Regulation [Line Items]

Amortization Of Deferred Storm Cost

2,500,000

RG&E Electric [Member] | Maximum [Member]

Industry Regulation [Line Items]

Reliability support service agreement final payment

$ 2,300,000

$ 2,300,000

RG&E Gas [Member]

Industry Regulation [Line Items]

Approved return on equity

9.00%

Equity Ratio

48.00%

48.00%

Customer receiving percentage

90.00%

Return on equity

10.50%

NYSEG Electric [Member]

Industry Regulation [Line Items]

Recovery Of Deferred Cost

$ 262,000,000

NYSEG Electric [Member] | Deferred Storm Cost Amortization 10 Year's [Member]

Industry Regulation [Line Items]

Amortization Of Deferred Storm Cost

123,000,000

NYSEG Electric [Member] | Deferred Storm Cost Amortization 5 Year's [Member]

Industry Regulation [Line Items]

Amortization Of Deferred Storm Cost

139,000,000

NYSEG Electric [Member] | Deferred Storm Cost Amortization 1 Year [Member]

Industry Regulation [Line Items]

Amortization Of Deferred Storm Cost

$ 21,400,000

United Illuminating Company (UI)

Industry Regulation [Line Items]

Period of purchase commitment

21 years

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

Maximum amount of commitment to purchase Renewable Energy Credits (RECs) from new facilities behind distribution customer meters

$ 200,000,000

$ 200,000,000

Solicitation period obligations will phase-in

6 years

Maximum annual commitment level obligation after year six

$ 13,600,000

$ 13,600,000

Connecticut Natural Gas Corporation (CNG) [Member]

Industry Regulation [Line Items]

Public utilities nature of allowance for earnings on equity, description

CNG and customers share on a 50/50 basis all earnings above the allowed ROE in a calendar year.

RG&E & GNPP [Member]

Industry Regulation [Line Items]

Modified agreement monthly payment amount

$ 15,400,000

Ginna Nuclear Power Plant LLC [Member]

Industry Regulation [Line Items]

Percentage of revenue entitled

30.00%

30.00%

One time payment

$ 11,500,000

New Haven Harbor Station Site [Member]

Industry Regulation [Line Items]

Number of Megawatts of project planned | MWh

2.8

Bridgeport [Member]

Industry Regulation [Line Items]

Number of Megawatts of project planned | MWh

5

Woodbridge [Member]

Industry Regulation [Line Items]

Number of Megawatts of project planned | MWh

2.2

GenConn Devon [Member] | Scenario, Forecast [Member] | Electric Transmission and Distribution [Member]

Industry Regulation [Line Items]

Revenue requirements for equity investment in peaking generation

$ 28,800,000

GenConn Middletown [Member] | Scenario, Forecast [Member] | Electric Transmission and Distribution [Member]

Industry Regulation [Line Items]

Revenue requirements for equity investment in peaking generation

$ 35,700,000

Industry Regulation - Electric

Industry Regulation - Electric and Gas Delivery Rate Increase (Detail) - USD ($) $ in Millions	12 Months Ended
	May 01, 2018	May 01, 2017	May 01, 2016
NYSEG Electric [Member]
Industry Regulation [Line Items]
Rate Increase			$ 29.6
Delivery Rate Increase			4.10%
NYSEG Electric [Member] | Scenario, Forecast [Member]
Industry Regulation [Line Items]
Rate Increase	$ 30.3	$ 29.9
Delivery Rate Increase	4.10%	4.10%
NYSEG Gas [Member]
Industry Regulation [Line Items]
Rate Increase			$ 13.1
Delivery Rate Increase			7.30%
NYSEG Gas [Member] | Scenario, Forecast [Member]
Industry Regulation [Line Items]
Rate Increase	$ 14.8	$ 13.9
Delivery Rate Increase	7.30%	7.30%
RG&E Electric [Member]
Industry Regulation [Line Items]
Rate Increase			$ 3
Delivery Rate Increase			0.70%
RG&E Electric [Member] | Scenario, Forecast [Member]
Industry Regulation [Line Items]
Rate Increase	$ 25.9	$ 21.6
Delivery Rate Increase	5.70%	5.00%
RG&E Gas [Member]
Industry Regulation [Line Items]
Rate Increase			$ 8.8
Delivery Rate Increase			5.20%
RG&E Gas [Member] | Scenario, Forecast [Member]
Industry Regulation [Line Items]
Rate Increase	$ 9.5	$ 7.7
Delivery Rate Increase	5.20%	4.40%

Regulatory Assets and Liabili78

Regulatory Assets and Liabilities - Additional Information (Detail) $ in Millions	3 Months Ended	12 Months Ended
	Jun. 30, 2016USD ($)	Dec. 31, 2016USD ($)Station	Dec. 31, 2015USD ($)
Regulatory Assets And Liabilities [Line Items]
Unrecorded Regulatory Assets		$ 2,357
Unfunded future income tax expense	$ 126	$ 126
Unfunded future Income tax expense collection period		50 years
Deferred costs		$ 2.3
Number of nuclear generating stations | Station		2
UIL Holdings [Member]
Regulatory Assets And Liabilities [Line Items]
Business combination merger related rate credits		$ 20
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
NYSEG [Member]
Regulatory Assets And Liabilities [Line Items]
Annual amortization of regulatory items		$ 16.5
Regulatory items amortization period		3 years
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
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
Regulatory assets		$ 2	$ 12
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	$ 68
UI [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory assets		0
Deferred costs		$ 1

Regulatory Assets and Liabili79

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Asset [Line Items]
Regulatory Assets, current	$ 285	$ 219
Regulatory Assets, noncurrent	3,091	3,314
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	22	8
Regulatory Assets, noncurrent	134	151
Pension And Other Post-Retirement Benefits [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	7	13
Regulatory Assets, noncurrent	1,320	1,509
Storm Costs
Regulatory Asset [Line Items]
Regulatory Assets, current	40	8
Regulatory Assets, noncurrent	187	251
Temporary Supplemental Assessment Surcharge [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	4	7
Support Services [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	27
Revenue Decoupling Mechanism [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	15	6
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	12	5
Electric Supply Reconciliation [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	13
Hedges Loss [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	10	37
Contracts For Differences [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	14	18
Regulatory Assets, noncurrent	61	50
Hardship Programs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	16	13
Regulatory Assets, noncurrent	18	29
Deferred Property Tax [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	10
Regulatory Assets, noncurrent	33	45
Plant Decommissioning [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	6
Regulatory Assets, noncurrent	14	7
Deferred Purchased Gas [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	14	12
Deferred Transmission Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	13	12
Environmental Restoration Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	14	37
Regulatory Assets, noncurrent	287	271
Other [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	48	43
Regulatory Assets, noncurrent	102	57
Deferred Meter Replacement Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	32	34
Unamortized Loss On Reacquired Debt [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	20	23
Future Income Tax [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	542	549
Asset Retirement Obligation Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	18	24
Federal Tax Depreciation Normalization Adjustment [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	161	158
Merger Capital Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	11	15
Debt Premium [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	$ 151	$ 141

Regulatory Assets and Liabili80

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 192	$ 147
Regulatory liabilities including deferred income taxes, noncurrent	1,753	1,841
Deferred income taxes regulatory	565	519
Regulatory liabilities including deferred income taxes, noncurrent	2,318	2,360
Support Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	16
Non By Passable Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	22	7
Energy Efficiency Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	45	33
Gas Supply Charge And Deferred Natural Gas Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	6	6
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	5	16
Pension And Other Post-Retirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	3
Regulatory liabilities including deferred income taxes, noncurrent	76	90
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	14
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	15
Regulatory liabilities including deferred income taxes, noncurrent	95	116
Yankee DOE Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	24	5
Merger Related Rate Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	3	20
Regulatory liabilities including deferred income taxes, noncurrent	21	24
Carrying Costs On Deferred Income Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	5
Regulatory liabilities including deferred income taxes, noncurrent	25	31
Revenue Decoupling Mechanism [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	9	14
Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	38	27
Regulatory liabilities including deferred income taxes, noncurrent	73	93
Accrued Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	1,117	1,084
Asset Sale Gain Account [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	9	8
Economic Development [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	35	36
Merger Capital Expense [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	15	17
Positive Benefit Adjustment [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	42	51
New York State Tax Rate Change [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	9	17
Post Term Amortization [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	3	25
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	24	31
Deferred Property Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	19	15
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	32
Rate Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	22	21
Accumulated Deferred Investment Tax Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	15	10
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	13	13
Transmission Congestion Contracts [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	18
Middletown/Norwalk Local Transmission Network Service Collections [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	19	19
Excess Generation Service Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent		21
Low Income Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	46	42
Unfunded Future Income Taxes [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent		27
Earning sharing provisions [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	12
Non-Firm Margin Sharing Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	$ 7	$ 8

Goodwill and Intangible asset81

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Detail) - USD ($) $ in Millions		Dec. 31, 2016	Dec. 31, 2015
Goodwill [Line Items]
Goodwill		$ 3,124	$ 3,115
Network [Member]
Goodwill [Line Items]
Goodwill		2,744	2,733
Renewables [Member]
Goodwill [Line Items]
Goodwill		$ 380	380
Other [Member]
Goodwill [Line Items]
Goodwill	[1]		$ 2
[1]	Does not represent a reportable segment. It includes Corporate.

Goodwill and Intangible asset82

Goodwill and Intangible assets - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016USD ($)Segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)	Dec. 31, 2002USD ($)	Dec. 31, 2000USD ($)
Goodwill [Line Items]
Number of reporting units | Segment	3
Impairment of goodwill	$ 0	$ 0
Amortization expense	$ 25,000,000	54,000,000	$ 66,000,000
Gas Storage Rights [Member]
Goodwill [Line Items]
Finite lived intangible assets useful economic life	40 years
Impairment of intangible assets	$ 4,100,000	6,500,000
UIL Holdings [Member]
Goodwill [Line Items]
Goodwill	1,765,000,000
Other [Member]
Goodwill [Line Items]
Goodwill, gross	0	2,000,000
Goodwill reversed related to sale of business unit	2,000,000
Network [Member]
Goodwill [Line Items]
Goodwill, gross	2,744,000,000	2,733,000,000
Goodwill, period increase (decrease)	11,000,000	1,754,000,000
Renewables And Gas Segments
Goodwill [Line Items]
Goodwill, gross	3,340,000,000	3,340,000,000
Goodwill, accumulated impairment loss	$ 2,960,000,000	$ 2,960,000,000
Maine Reporting Unit [Member]
Goodwill [Line Items]
Goodwill					$ 325,000,000
New York Reporting Unit [Member]
Goodwill [Line Items]
Goodwill				$ 654,000,000

Goodwill and Intangible asset83

Goodwill and Intangible assets - Summary of Intangible Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 923	$ 923
Accumulated Amortization	(385)	(367)
Net Carrying Amount	538	556
Gas Storage Rights [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	319	324
Accumulated Amortization	(120)	(116)
Net Carrying Amount	199	208
Wind Development [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	587	584
Accumulated Amortization	(254)	(243)
Net Carrying Amount	333	341
Other [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	17	15
Accumulated Amortization	(11)	(8)
Net Carrying Amount	$ 6	$ 7

Goodwill and Intangible asset84

Goodwill and Intangible assets - Schedule of Amortization Expense (Detail) $ in Millions	Dec. 31, 2016USD ($)
Goodwill And Intangible Assets Disclosure [Abstract]
2,017	$ 16
2,018	16
2,019	18
2,020	17
2,021	$ 21

Property, Plant and Equipment85

Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	$ 27,063	[1]	$ 25,745	[2]
Less: accumulated depreciation	(6,986)	[3]	(6,372)	[4]
Total Net Property, Plant and Equipment in Service	20,077		19,373
Construction work in progress	1,471		1,338
Total Property, Plant and Equipment ($1,144 and $1,206 related to VIEs, respectively)	21,548		20,711		$ 17,133
Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	16,023	[1]	14,996	[2]
Less: accumulated depreciation	(3,970)	[3]	(3,727)	[4]
Total Net Property, Plant and Equipment in Service	12,053		11,269
Construction work in progress	979		1,094
Total Property, Plant and Equipment ($1,144 and $1,206 related to VIEs, respectively)	13,032		12,363
Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	11,040	[1]	10,749	[2]
Less: accumulated depreciation	(3,016)	[3]	(2,645)	[4]
Total Net Property, Plant and Equipment in Service	8,024		8,104
Construction work in progress	492		244
Total Property, Plant and Equipment ($1,144 and $1,206 related to VIEs, respectively)	8,516		8,348
Electric Generation, Distribution and Transmission Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	20,727		21,564
Electric Generation, Distribution and Transmission Equipment [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	10,343		11,506
Electric Generation, Distribution and Transmission Equipment [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	10,384		10,058
Natural Gas, Transportation and Distribution Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	5,416		3,324
Natural Gas, Transportation and Distribution Equipment [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	4,803		2,673
Natural Gas, Transportation and Distribution Equipment [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	613		651
Other Common Operating Property [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	920		857
Other Common Operating Property [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	877		817
Other Common Operating Property [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	$ 43		$ 40
[1]	Includes capitalized leases of $208 million primarily related to electric generation, distribution, transmission and other.
[2]	Includes capitalized leases of $178 million primarily related to electric generation, distribution, transmission and other.
[3]	Includes accumulated amortization of capitalized leases of $60 million.
[4]	Includes accumulated amortization of capitalized leases of $53 million.

Property, Plant and Equipment -

Property, Plant and Equipment - (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Capital lease obligations	$ 104	$ 87
Accumulated Capitalized Interest Costs	60	53
Electric Generation, Distribution and Transmission Equipment [Member]
Property Plant And Equipment [Line Items]
Capital lease obligations	$ 208	$ 178

Property, Plant and Equipment87

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Abstract]
Interest costs capitalized	$ 20	$ 13	$ 12
Tangible asset impairment charges	0	12	24
Depreciation	$ 779	$ 641	$ 563

Asset Retirement Obligations -

Asset Retirement Obligations - Reconciliation of ARO (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$ 184	$ 234
Liabilities settled during the year	(7)	(16)
Liabilities incurred during the year	3
Accretion expense	10	14
Revisions in estimated cash flows	(29)	(48)
Ending Balance	$ 161	$ 184

Asset Retirement Obligations 89

Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted Cash	$ 2	$ 1.8
Estimated annual reduction in expense upon revision	$ 3

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Capital lease obligations	$ 104	$ 87
Unamortized debt issuance costs and discount	(31)	(25)
Long-Term Debt	4,859	4,736
Less: debt due within one year, included in current liabilities	349	206
Total Non-current Debt	$ 4,510	4,530
First Mortgage Bonds - Fixed [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start	2,018
Debt Instrument, Maturity Date, End	2,045
Long-Term Debt	$ 1,752	$ 1,815
First Mortgage Bonds - Fixed [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	3.07%	3.07%
First Mortgage Bonds - Fixed [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	10.60%	10.60%
Unsecured Pollution Control Notes - Fixed [Member]
Debt Instrument [Line Items]
Debt instrument maturity year	2,020
Long-Term Debt	$ 200	$ 200
Unsecured Pollution Control Notes - Fixed [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	2.00%	2.00%
Unsecured Pollution Control Notes - Fixed [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	2.375%	2.375%
Unsecured Pollution Control Notes – Variable [Member]
Debt Instrument [Line Items]
Debt instrument maturity year	2,032
Long-Term Debt	$ 62	$ 219
Debt instrument, interest rate	1.32%
Unsecured Pollution Control Notes – Variable [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		0.195%
Unsecured Pollution Control Notes – Variable [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate		1.181%
Other Various Non-current Debt - Fixed [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start	2,017
Debt Instrument, Maturity Date, End	2,045
Long-Term Debt	$ 2,772	$ 2,440
Other Various Non-current Debt - Fixed [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	2.89%	2.89%
Other Various Non-current Debt - Fixed [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	10.48%	10.48%
Obligations Under Capital Leases [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start	2,017
Debt Instrument, Maturity Date, End	2,023
Obligations Under Capital Leases [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	4.00%	4.00%
Obligations Under Capital Leases [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	4.44%	4.44%

Debt - Schedule of Long-term 91

Debt - Schedule of Long-term Debt (Parenthetical) (Detail) $ in Millions	Dec. 31, 2016USD ($)
First Mortgage Bonds - Fixed [Member]
Debt Instrument [Line Items]
Bond pledged as collateral	$ 5,886

Debt - Additional Information (

Debt - Additional Information (Detail)	Apr. 05, 2016USD ($)	Nov. 30, 2016USD ($)	Dec. 31, 2016USD ($)CreditFacility	Dec. 27, 2016USD ($)	Dec. 19, 2016USD ($)	May 13, 2016USD ($)	Dec. 31, 2015USD ($)	Oct. 07, 2010USD ($)
Debt Instrument [Line Items]
Repayment of debt		$ 100,000,000
Debt instrument maturity date		Dec. 15, 2016
Debt instrument repurchase amount				$ 64,000,000	$ 96,000,000
Estimated fair value of debt			$ 5,204,000,000				$ 4,985,000,000
Notes payable			161,000,000				163,000,000
Line of credit borrowings							160,000,000
Other notes payable			1,000,000				3,000,000
Commercial paper			150,000,000
Notes payable to affiliates			10,000,000
Credit facility remaining borrowing capacity			1,350,000,000
Joint Utility Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 600,000,000
Credit facility, termination date			2018-07
UIL Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 400,000,000			$ 1,000,000,000
Credit facility, termination date			2016-11
AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 1,500,000,000
Maturity date for credit facility			Apr. 5, 2021
Number of credit facilities terminated | CreditFacility			3
AVANGRID Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Credit facility initial fees range	0.10%
AVANGRID Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Credit facility initial fees range	0.175%
AVANGRID Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 300,000,000
Credit facility, termination date			2019-05
Level 3 [Member]
Debt Instrument [Line Items]
Estimated fair value of debt			$ 61,000,000				$ 204,000,000
AVANGRID [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 1,000,000,000
NYSEG, RGE, CMP and UI [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	250,000,000
CNG and SCG [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	150,000,000
The Berkshire Gas Company [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity	$ 25,000,000
3.25% Interest Notes [Member]
Debt Instrument [Line Items]
Debt instrument principal amount		$ 500,000,000
Debt instrument maturity year		2,026
Interest rate on outstanding loans		3.25%
4.625% Interest Notes [Member] | AVANGRID [Member]
Debt Instrument [Line Items]
Debt instrument principal amount								$ 450,000,000
Debt instrument maturity year			2,020
Interest rate on outstanding loans								4.625%

Debt - Schedule of Maturities a

Debt - Schedule of Maturities and Repayments of Long-term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Total	$ 4,510	$ 4,530
Non-current debt, including sinking fund obligations and capital lease payments, due over the next five [Member]
Debt Instrument [Line Items]
2,017	349
2,018	180
2,019	358
2,020	723
2,021	308
Total	$ 1,918

Fair Value of Financial Instr94

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 172	$ 177
Derivative financial instruments, liabilities	(153)	(185)
Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(281)	(351)
Derivative financial instruments, liabilities	296	267
Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	40	39
Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	75	68
Derivative financial instruments, liabilities	(15)	(14)
Derivative Financial Instrument Power [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(42)	(71)
Derivative financial instruments, liabilities	39	55
Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	77	80
Derivative financial instruments, liabilities	(43)	(72)
Derivative Financial Instrument Gas [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(239)	(280)
Derivative financial instruments, liabilities	257	212
Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	20	29
Derivative financial instruments, liabilities	(95)	(96)
Derivative Financial Instrument Other [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities		(3)
Fair Value, Inputs, Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	191	277
Derivative financial instruments, liabilities	(237)	(236)
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	39
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	11	10
Derivative financial instruments, liabilities	(24)	(43)
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	180	267
Derivative financial instruments, liabilities	(213)	(193)
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	80	106
Derivative financial instruments, liabilities	(61)	(52)
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	48	81
Derivative financial instruments, liabilities	(27)	(12)
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	32	25
Derivative financial instruments, liabilities	(34)	(40)
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	182	145
Derivative financial instruments, liabilities	(151)	(164)
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	58	48
Derivative financial instruments, liabilities	(3)	(14)
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	104	68
Derivative financial instruments, liabilities	(53)	(51)
Level 3 [Member] | Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	20	29
Derivative financial instruments, liabilities	$ (95)	(96)
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		$ (3)

Fair Value of Financial Instr95

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Debt Instrument Fair Value Carrying Value [Abstract]
Fair value as of January 1,		$ (19)	$ 57	$ 53
Gains for the year recognized in operating revenues		67	33	11
Losses for the year recognized in operating revenues			(8)	(1)
Total gains or losses for the period recognized in operating revenues		67	25	10
Gains recognized in OCI		1	2
Losses recognized in OCI			(3)	(3)
Total gains or losses recognized in OCI		1	(1)	(3)
Net change recognized in regulatory assets and liabilities		(8)
Purchases		3	(73)	14
Settlements		(9)	(14)	(26)
Transfers out of Level 3	[1]	(4)	(13)	9
Fair value as of December 31,		31	(19)	57
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date		$ 67	$ 25	$ 10
[1]	Transfers out of Level 3 were the result of increased observability of market data.

Fair Value of Financial Instr96

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	12 Months Ended
	Dec. 31, 2016$ / 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 ($/MMBtu)
SP15 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	SP15 ($/MWh)
Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Mid C ($/MWh)
Cinergy [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Cinergy ($/MWh)
Weighted Average [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	4.27
Weighted Average [Member] | SP15 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	44.23
Weighted Average [Member] | Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	35.44
Weighted Average [Member] | Cinergy [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	36.40
Maximum [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	7.37
Maximum [Member] | SP15 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	80.28
Maximum [Member] | Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	83.93
Maximum [Member] | Cinergy [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	77.49
Minimum [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	1.64
Minimum [Member] | SP15 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	14.25
Minimum [Member] | Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	3.60
Minimum [Member] | Cinergy [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	18.53

Fair Value of Financial Instr97

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2016
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

Fair Value of Financial Instr98

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Detail) - Contracts For Differences [Member] - Level 3 [Member]	12 Months Ended
	Dec. 31, 2016$ / MWh
Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.68%
Discount rate	1.47%
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	0.81%
Discount rate	2.45%
Forward pricing ($ per MW)	9.55

Derivative Instruments and He99

Derivative Instruments and Hedging - Additional Information (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets			$ 81,000,000	$ (74,000,000)	$ (175,000,000)
Derivative financial instruments, assets			172,000,000	177,000,000
Gross Amounts of Recognized Liabilities			153,000,000	185,000,000
Regulatory liabilities			19,800,000
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]		(16,000,000)	7,000,000	5,000,000
UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets			19,000,000	29,000,000
Regulatory Assets			75,000,000	68,000,000
Gross Amounts of Recognized Liabilities			95,000,000	96,000,000
Regulatory liabilities			$ 0	1,000,000
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	1,000,000
Gross Amounts of Recognized Liabilities			70,000,000	61,000,000
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	[2]			(3,000,000)	(4,000,000)
Network [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges			8,000,000	8,600,000	8,900,000
Ineffective portion of Cash flow hedge			0	0	0
Unrealized gain(loss) from hedging activities reported on OCI			$ (400,000)
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		$ 400,000
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			$ 76,700,000	84,900,000	93,500,000
Network [Member] | Electricity Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets			(12,300,000)	(34,300,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income			(66,700,000)	(46,900,000)	(21,300,000)
Network [Member] | Natural Gas Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets			3,500,000	(3,100,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income			$ (1,900,000)	(6,300,000)	$ (2,200,000)
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			$ (6,800,000)	4,800,000
Unrealized gain(loss) from hedging activities reported on OCI			$ 13,600,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months			12 months
Gain Recognized in OCI Derivatives Effective Portion			$ 400,000	2,300,000
Counter Party [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities			12,000,000
Cash Collateral Pledged			20,000,000	$ 11,000,000
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			$ 12,800,000
[1]	Reclassification is reflected in the operating expenses line item in the consolidated statements of income.
[2]	Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the consolidated statements of income.

Derivative Instruments and H100

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2016
Regulatory Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory Assets (Liabilities) - Derivative assets (liabilities)	$ 1	$ 7
Regulatory Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory Assets (Liabilities) - Derivative assets (liabilities)		$ 1

Derivative Instruments and H101

Derivative Instruments and Hedging - Net Notional Volume (Detail)	Dec. 31, 2016MWhDTHgal	Dec. 31, 2015MWhDTHgal
Network [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	5,600,000	6,700,000
Network [Member] | Natural Gas Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	5,800,000	4,800,000
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	3,800,000
Renewables and Gas Activities [Member] | Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	49,000,000	67,000,000
Renewables and Gas Activities [Member] | Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	45,000,000	80,000,000
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	3,000,000	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	6,000,000
Renewables and Gas Activities [Member] | Foreign Exchange Forward [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount		4,000,000
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	329,000,000	332,000,000
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	7,000,000

Derivative Instruments and H102

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Network [Member] | UIL Holdings [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	$ 12	$ 11
Total derivatives as presented in the balance sheet	12	11
Network [Member] | UIL Holdings [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	19	11
Derivative liabilities	(7)
Derivative Fair Value, Net	12	11
Network [Member] | UIL Holdings [Member] | Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities		(3)
Derivative assets		3
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	11	18
Total derivatives as presented in the balance sheet	11	18
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	16	18
Derivative liabilities	(5)
Derivative Fair Value, Net	11	18
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities		(6)
Derivative assets		6
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(33)	(67)
Cash collateral receivable	10	37
Total derivatives as presented in the balance sheet	(23)	(30)
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	7
Derivative liabilities	(40)	(28)
Derivative Fair Value, Net	(33)	(28)
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities		(42)
Derivative Fair Value, Net		(39)
Derivative assets		3
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(74)	(69)
Cash collateral receivable	2
Total derivatives as presented in the balance sheet	(72)	(69)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	5
Derivative liabilities	(79)	(68)
Derivative Fair Value, Net	(74)	(68)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities		(7)
Derivative Fair Value, Net		(1)
Derivative assets		6
Renewables and Gas Activities [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	104	157
Total derivatives as presented in the balance sheet	87	77
Cash collateral receivable (payable)	(17)	(80)
Renewables and Gas Activities [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(118)	(85)
Derivative Fair Value, Net	80	101
Derivative assets	198	186
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	24	56
Derivative assets	25	56
Renewables and Gas Activities [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	108	112
Total derivatives as presented in the balance sheet	62	71
Cash collateral receivable (payable)	(46)	(41)
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(4)	(14)
Derivative Fair Value, Net	104	99
Derivative assets	108	113
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	4	13
Derivative assets	4	13
Renewables and Gas Activities [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(93)	(61)
Total derivatives as presented in the balance sheet	(52)	(61)
Cash collateral receivable (payable)	41
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(132)	(169)
Derivative Fair Value, Net	(54)	(52)
Derivative assets	78	117
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(39)	(9)
Derivative Fair Value, Net	(39)	(9)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(30)	(25)
Total derivatives as presented in the balance sheet	(6)	(25)
Cash collateral receivable (payable)	24
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(16)	(29)
Derivative Fair Value, Net	(9)	(25)
Derivative assets	7	$ 4
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(21)
Derivative Fair Value, Net	$ (21)

Derivative Instruments and H103

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI Derivatives Effective Portion	[1]	$ (42)	$ 57
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[2]		(3)	$ (4)
Loss Reclassified from Accumulated OCI Income Effective Portion	[2]	10	12	10
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) Reclassified from Accumulated OCI Income Effective Portion	[1]	(43)	(2)
Interest Rate Contract [Member] | Network [Member] | Interest expense [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI Income Effective Portion	[2]	8	9	9
Commodity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI Derivatives Effective Portion	[1]	(42)	57
Commodity Contract [Member] | Network [Member] | Operating expenses [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[2]		(3)	(4)
Loss Reclassified from Accumulated OCI Income Effective Portion	[2]	2	3	$ 1
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Revenue [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) Reclassified from Accumulated OCI Income Effective Portion	[1]	$ (43)	$ (2)
[1]	Changes in OCI are reported on a pre-tax basis.
[2]	Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the consolidated statements of income.

Derivative Instruments and H104

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 91	$ 62
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	56	32
Long [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(2)	(13)
Long [Member] | Foreign Exchange Forward [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net		(1)
Long [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	30	10
Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	3	1
Short [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	6	35
Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ (2)	$ (2)

Derivative Instruments and H105

Derivative Instruments and Hedging - Effect of Trading and Non-Trading Derivatives (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (22)	$ (25)	$ 123
Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	3	6	(9)
Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(7)	(5)	9
Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	4		(2)
Trading Derivatives [Member] | Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(22)	(26)	125
Non-Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	13	29	36
Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	9	(8)	(8)
Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(20)	(5)	15
Non-Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(10)	24	30
Non-Trading Derivatives [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 34	$ 18	$ (1)

Commitments and Contingent L106

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

Oct. 14, 2016USD ($)

May 03, 2016USD ($)

Apr. 29, 2016

Mar. 25, 2016USD ($)

Mar. 22, 2016

Oct. 21, 2015USD ($)

Dec. 31, 2014USD ($)

Jul. 31, 2014

Jan. 22, 2014

Dec. 26, 2012

Nov. 30, 2013USD ($)

Dec. 31, 2012USD ($)

Dec. 31, 2016USD ($)UnitMW

Dec. 31, 2015USD ($)

Dec. 31, 2014USD ($)

Dec. 31, 2012USD ($)

May 31, 2016USD ($)

Loss Contingencies [Line Items]

New rate plan

10 years

Delivery revenue percentage

34.60%

Requested return on equity base percentage

9.55%

9.20%

Requested equity ratio

50.00%

One-time gross plant investment

$ 15

Cash Reserve

$ 6

Approved return on equity

9.18%

10.50%

Disclosure of Rate Matters

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

Regulatory liabilities

$ 1,753

$ 1,841

Spent fuel litigation damages awarded, value

$ 76.8

$ 235.4

$ 160

Spent fuel litigation damages settlement received

$ 41.6

Litigation appeal expiration date

Jul. 18, 2016

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

Operating lease expenses

70.6

47.7

$ 48.7

Contingent rent payment for electricity generation facility

$ 22.2

22.2

20.4

Sale of ownership interest percent

10.00%

Proceeds from sale of ownership Interest

$ 19.6

Modified agreement monthly payment amount

$ 15.4

Purchase power, description

UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts

Standby letters of credit

$ 2,600

Property, Plant and Equipment [Member]

Loss Contingencies [Line Items]

Future purchase commitment

$ 493

Power purchase commitments [Member]

Loss Contingencies [Line Items]

Purchase power, description

U.S. Power purchase commitments include the following: (i) a 55MW Biomass Power Purchase Agreement (PPA) for 12 years (five years remaining) with a guaranteed output of 34.4MW flat and a schedule of fixed price rates depending on season and time of day, (ii) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers and (iii) a three year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (two years remaining)

Power purchase commitment | MW

55

Period of purchase commitment

12 months

Power purchase commitment, remaining period

5 months

Power purchase commitments [Member] | Guaranteed output / Guaranteed annual production [Member]

Loss Contingencies [Line Items]

Power purchase commitment | MW

34

Power purchase commitments [Member] | Hydro Capacity and Energy [Member]

Loss Contingencies [Line Items]

Period of purchase commitment

3 months

Power purchase commitment, remaining period

2 months

Power sales commitments [Member]

Loss Contingencies [Line Items]

Purchase power, description

Power sales commitments include: (i) a 55MW Biomass off-take agreement for 12 years (five years remaining) with guaranteed annual production of 34.4MW flat with a schedule of fixed price rates depending on season and time of day, (ii) fixed price, fixed volume power sales off the Klamath Cogen facility in addition to tolling arrangements that have fixed capacity charges and (iii) fixed price, fixed volume renewable energy credit sales off merchant wind facilities.

Power purchase commitment | MW

55

Period of purchase commitment

12 months

Power purchase commitment, remaining period

5 months

Power sales commitments [Member] | Guaranteed output / Guaranteed annual production [Member]

Loss Contingencies [Line Items]

Power purchase commitment | MW

34.4

Support Services [Member]

Loss Contingencies [Line Items]

Operating lease expenses

$ 114.9

79.9

Support Services [Member] | Coal Fired Generating Station

Loss Contingencies [Line Items]

Operating lease expenses

$ 37.8

$ 25.5

$ 19.8

Number of Coal-Fired Generating Unit | Unit

2

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

Period of purchase commitment

20 years

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

RG&E Electric [Member]

Loss Contingencies [Line Items]

Requested equity ratio

75.00%

Approved return on equity

9.00%

Percentage of revenue entitled

70.00%

70.00%

Ginna Nuclear Power Plant LLC [Member]

Loss Contingencies [Line Items]

Percentage of revenue entitled

30.00%

30.00%

Complaint I [Member]

Loss Contingencies [Line Items]

Regulatory liabilities

$ 21.6

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 the Complaint I.

Regulatory liabilities

$ 21.6

Complaint III [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.84%

Regulatory liabilities

$ 4.4

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 in mid-2017.

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

8.61%

Before Amendment [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.14%

Minimum [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

14.55%

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

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

Maximum [Member] | Complaint II [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Maximum [Member] | Complaint III [Member]

Loss Contingencies [Line Items]

Approved return on equity

12.19%

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

Loss Contingencies [Line Items]

Approved return on equity

11.24%

Commitments and Contingent L107

Commitments and Contingent Liabilities - Schedule of Future Minimum Lease Payment (Detail) $ in Millions	Dec. 31, 2016USD ($)
Commitments And Contingencies Disclosure [Abstract]
Operating lease, 2017	$ 106
Operating lease, 2018	28
Operating leases, 2019	28
Operating leases, 2020	26
Operating leases, 2021	28
Operating leases, 2022 and thereafter	487
Total operating lease	703
Capital lease, 2017	30
Capital lease, 2018	6
Capital leases, 2019	7
Capital leases, 2020	7
Capital leases, 2021	4
Capital leases, 2022 and thereafter	50
Total capital lease	104
Operating and capital leases, 2017	136
Operating and capital leases, 2018	34
Operating and capital leases, 2019	35
Operating and capital leases, 2020	33
Operating and capital leases, 2021	32
Operating and capital leases, 2022 and thereafter	537
Total operating and capital leases	$ 807

Commitments and Contingent L108

Commitments and Contingent Liabilities - Schedule of Forward Purchases and Sales Commitments Under Power, Gas, and Other Arrangements (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2017	$ 487
Forward purchase commitments, 2018	376
Forward purchase commitments, 2019	287
Forward purchase commitments, 2020	238
Forward purchase commitments, 2021	191
Forward purchase commitments, thereafter	1,008
Total forward purchase commitments	2,587
Forward sales commitments, 2017	159
Forward sales commitments, 2018	84
Forward sales commitments, 2019	59
Forward sales commitments, 2020	47
Forward sales commitments, 2021	33
Forward sales commitments, thereafter	26
Total forward sales commitments	408
Derivative Financial Instrument Gas [Member]
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2017	284
Forward purchase commitments, 2018	245
Forward purchase commitments, 2019	205
Forward purchase commitments, 2020	161
Forward purchase commitments, 2021	127
Forward purchase commitments, thereafter	520
Total forward purchase commitments	1,542
Forward sales commitments, 2017	23
Forward sales commitments, 2018	4
Forward sales commitments, 2019	5
Forward sales commitments, 2020	5
Total forward sales commitments	37
Power [Member]
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2017	168
Forward purchase commitments, 2018	108
Forward purchase commitments, 2019	68
Forward purchase commitments, 2020	65
Forward purchase commitments, 2021	52
Forward purchase commitments, thereafter	379
Total forward purchase commitments	840
Forward sales commitments, 2017	132
Forward sales commitments, 2018	76
Forward sales commitments, 2019	53
Forward sales commitments, 2020	42
Forward sales commitments, 2021	33
Forward sales commitments, thereafter	26
Total forward sales commitments	362
Other Forward Purchases And Sales Commitments
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2017	35
Forward purchase commitments, 2018	23
Forward purchase commitments, 2019	14
Forward purchase commitments, 2020	12
Forward purchase commitments, 2021	12
Forward purchase commitments, thereafter	109
Total forward purchase commitments	205
Forward sales commitments, 2017	4
Forward sales commitments, 2018	4
Forward sales commitments, 2019	1
Total forward sales commitments	$ 9

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 ($)	Dec. 31, 2016USD ($)siteLocation	Aug. 04, 2016USD ($)	Dec. 31, 2015USD ($)	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						$ 388		$ 397
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 Idemnity 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]
Estimated environmental liability						$ 1.7		9.5
Costs related to investigation and remediation						28.3	$ 30	20.5
Difference in pretax reflected as reversal of expense						$ 7.8
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		$ 99
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

Income Taxes - Schedule of Curr

Income Taxes - Schedule of Current and Deferred Taxes Charged to (Benefit) Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Current
Federal	$ (6)	$ (20)	$ (10)
State	8	(33)	31
Current taxes charged to (benefit) expense	2	(53)	21
Deferred
Federal	414	136	218
State	2	(6)	82
Deferred taxes charged to expense	416	130	300
Production tax credits	(38)	(42)	(37)
Investment tax credits	(1)	(1)	(2)
Total Income Tax Expense	$ 379	$ 34	$ 282

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 353	$ 105	$ 247
Depreciation and amortization not normalized	61	15	15
Investment tax credit amortization	(1)	(1)	(2)
Tax return related adjustments	(2)	6	2
Production tax credits	(38)	(42)	(37)
Tax equity financing arrangements	(25)	(36)	(11)
Change in tax reserves			3
Changes in New York tax law			41
State tax expense (benefit), net of federal benefit	7	(25)	32
Non-deductible acquisition costs		9
Other, net	24	3	(8)
Total Income Tax Expense	$ 379	$ 34	$ 282

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Non-current Deferred Income Tax Liabilities (Assets)
Property related	$ 5,195	$ 4,763
Unfunded future income taxes	216	211
Federal and state tax credits	(417)	(367)
Accumulated deferred investment tax credits	14	15
Federal and state NOL’s	(1,397)	(1,367)
Joint ventures/partnerships	651	655
Nontaxable grant revenue	(581)	(595)
Other	(171)	(17)
Non-current Deferred Income Tax Liabilities	3,510	3,298
Add: Valuation allowance	31	19
Total Non-current Deferred Income Tax Liabilities	3,541	3,317
Less amounts classified as regulatory liabilities non-current deferred income taxes	565	519
Deferred income taxes	2,976	2,798
Deferred tax assets	2,565	2,346
Deferred tax liabilities	$ 6,106	$ 5,663

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2012
Income Taxes [Line Items]
Valuation allowance, net of federal benefit	$ 10			$ 9
Increase in valuation allowance	12
Tax credit carry forward	3
Accruals for interest and penalties on tax reserves	2	$ 2	$ 3
Unrecognized tax benefits that would impact effective tax rate	8
Net decrease to unrecognized tax benefits	9
State
Income Taxes [Line Items]
Valuation allowance, net of federal benefit	15	$ 10
Tax credit carry forward	32
Net operating loss carry forwards	241
Recognized valuation allowance	$ 31
Expiration year for net operating losses	2,021
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	$ 3,600
Expiration year for net operating losses	2,028
Expiration year for tax credits	2,023
Federal | Renewable Energy and Investment
Income Taxes [Line Items]
Tax credit carry forward	$ 394
Federal | R&D
Income Taxes [Line Items]
Tax credit carry forward	394
Federal | Other
Income Taxes [Line Items]
Tax credit carry forward	$ 394

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Income Tax Disclosure [Abstract]
Beginning Balance	$ 36	$ 38	$ 41
Increases for tax positions related to prior years	8	1	20
Decreases for tax positions related to prior years	(4)
Reduction for tax position related to settlements with taxing authorities		(3)	(23)
Ending Balance	$ 40	$ 36	$ 38

Post-Retirement and Similar 115

Post-Retirement and Similar Obligations - Obligations and Funded Status (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Change in plan assets
Fair value of plan assets, Beginning balance	$ 2,664
Fair Value of Plan Assets, Ending balance	2,672	$ 2,664
Other Postretirement Benefit Plan [Member]
Change in plan assets
Fair value of plan assets, Beginning balance	162
Fair Value of Plan Assets, Ending balance	160	162
Networks and ARHI [Member] | Pension Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance	3,509	2,620
Acquisition of UIL		1,019
Service cost	44	36
Interest cost	142	99
Actuarial gain	(43)	(105)
Special termination benefits		2
Benefits paid	(204)	(162)
Benefit Obligation, Ending balance	3,448	3,509
Change in plan assets
Fair value of plan assets, Beginning balance	2,664	2,143
Acquisition of UIL		687
Actual return on plan assets	169	(31)
Employer contributions	43	27
Benefits paid	(204)	(162)
Fair Value of Plan Assets, Ending balance	2,672	2,664
Funded Status as of December 31,	(776)	(845)
Networks and ARHI [Member] | Other Postretirement Benefit Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance	525	435
Acquisition of UIL		122
Service cost	5	5
Interest cost	21	16
Plan participants’ contributions	7	4
Plan amendments		(1)
Actuarial gain	(24)	(31)
Benefits paid	(39)	(25)
Benefit Obligation, Ending balance	495	525
Change in plan assets
Fair value of plan assets, Beginning balance	162	129
Acquisition of UIL		39
Actual return on plan assets	11	(4)
Employer contributions	30	21
Plan participants’ contributions	7	4
Benefits paid	(39)	(25)
Withdrawals from VEBA	(11)	(2)
Fair Value of Plan Assets, Ending balance	160	162
Funded Status as of December 31,	$ (335)	$ (363)

Post-Retirement and Similar 116

Post-Retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-current liabilities	$ (776)	$ (845)
Total	(776)	(845)
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(330)	(358)
Total	$ (335)	$ (363)

Post-Retirement and Similar 117

Post-Retirement and Similar Obligations - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2017
Defined Benefit Plan Disclosure [Line Items]
Other	$ 342,000,000	$ 330,000,000
Benefits plan, target asset allocation	37.00%
Equity Securities [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	35.00%
Equity Securities [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	54.00%
Equity Alternative Securities [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	3.00%
Equity Alternative Securities [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	20.00%
Liability Hedging Assets [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	43.00%
Liability Hedging Assets [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
Other Postretirement Benefit Plan [Member] | Large Cap Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation minimum range	27.00%
Benefits plan, target asset allocation maximum range	66.00%
Other Postretirement Benefit Plan [Member] | Small Cap Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Other Postretirement Benefit Plan [Member] | International Developed Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	8.00%
Other Postretirement Benefit Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	6.00%
Other Postretirement Benefit Plan [Member] | Core Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation minimum range	24.00%
Benefits plan, target asset allocation maximum range	31.00%
Other Postretirement Benefit Plan [Member] | Global High Yield Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	4.00%
Other Postretirement Benefit Plan [Member] | International Developed Market Debt [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	3.00%
Other Postretirement Benefit Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	6.00%
Other Postretirement Benefit Plan [Member] | Tangible Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	6.00%
Other Postretirement Benefit Plan [Member] | Other Multi-asset Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation minimum range	3.00%
Benefits plan, target asset allocation maximum range	11.00%
Scenario, Forecast [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan assets				$ 0
Scenario, Forecast [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan assets				$ 0
Iberdrola Renewables Holding, Inc. (IRHI) [Member]
Defined Benefit Plan Disclosure [Line Items]
Retired employees currently receiving benefits			$ 118,500,000
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution for pension benefit plans during 2017	$ 33,000,000
Asset return seeking percentage category		7.50%	7.50%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	7.40%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	7.75%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	7.16%
Networks and ARHI [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 3,214,000,000	$ 3,261,000,000
Networks and ARHI [Member] | Non-Qualified Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Other	57,000,000	59,000,000
Networks and ARHI [Member] | Defined Contribution Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Annual contributions made	$ 34,000,000	$ 17,000,000	$ 20,000,000
ARHI | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	5.50%	5.50%	6.90%
ARHI | Pension Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	33.00%
ARHI | Pension Plan [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	50.00%
ARHI | Pension Plan [Member] | Other Investment Types [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	17.00%
ARHI | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	5.50%	5.75%	6.50%
ARHI | Other Postretirement Benefit Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	48.00%
ARHI | Other Postretirement Benefit Plan [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	49.00%
ARHI | Other Postretirement Benefit Plan [Member] | Other Investment Types [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	3.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation minimum range	46.00%
Benefits plan, target asset allocation maximum range	66.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation minimum range	30.00%
Benefits plan, target asset allocation maximum range	31.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Other Investment Types [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation minimum range	3.00%
Benefits plan, target asset allocation maximum range	23.00%

Post-Retirement and Similar 118

Post-Retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Detail) - ARHI - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net (gain) loss	$ 23	$ 25	$ 22
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net (gain) loss	$ (3)	$ (1)	$ 8

Post-Retirement and Similar 119

Post-Retirement and Similar Obligations - Summary of Recognized as Regulatory Assets or Regulatory Liabilities (Detail) - Iberdrola Renewables Holding, Inc. (IRHI) [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss	$ 860	$ 994	$ 1,045
Prior service cost (credit)	7	9	12
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss	44	76	96
Prior service cost (credit)	$ (40)	$ (49)	$ (57)

Post-Retirement and Similar 120

Post-Retirement and Similar Obligations - Schedule of Aggregate Projected and Accumulated Benefit Obligations of Fair Value of Plan Assets for Underfunded Plans (Detail) - Networks and ARHI [Member] - Pension Plan [Member] - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Projected benefit obligation	$ 3,448	$ 3,509
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Accumulated benefit obligation	3,214	3,261
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Fair value of plan assets	2,672	2,664
Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets, Projected benefit obligation	3,448	3,509
Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets, Accumulated benefit obligation	3,214	3,261
Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets, Fair value of plan assets	$ 2,672	$ 2,664

Post-Retirement and Similar 121

Post-Retirement and Similar Obligations - Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations Recognized (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Net Periodic Benefit Cost:
Service cost	$ 44	$ 36	$ 30
Interest cost	140	97	107
Expected return on plan assets	(199)	(156)	(161)
Amortization of prior service cost (benefit)	2	3	4
Amortization of net loss	123	130	94
Special termination benefit charge		2
Settlement charge		2
Net Periodic Benefit Cost	110	114	74
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlements		(2)
Net loss (gain)	(11)	69	434
Amortization of net loss	(123)	(130)	(94)
Amortization of prior service (cost) benefit	(2)	(3)	(4)
Total Other Changes	(136)	(66)	336
Total Recognized	(26)	48	410
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Net Periodic Benefit Cost:
Service cost	5	4	4
Interest cost	20	15	17
Expected return on plan assets	(8)	(7)	(7)
Amortization of prior service cost (benefit)	(9)	(9)	(11)
Amortization of net loss	8	7
Net Periodic Benefit Cost	16	10	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	(24)	(12)	72
Amortization of net loss	(8)	(7)
Current year prior service cost		(1)
Amortization of prior service (cost) benefit	9	9	11
Total Other Changes	(23)	(11)	83
Total Recognized	(7)	(1)	86
ARHI | Pension Plan [Member]
Net Periodic Benefit Cost:
Interest cost	2	2	2
Expected return on plan assets	(2)	(2)	(3)
Amortization of net loss	1	1
Settlement charge	1
Net Periodic Benefit Cost	2	1	(1)
Other Changes in plan assets and benefit obligations recognized in OCI:
Net loss (gain)		4	6
Amortization of net loss	(1)	(1)
Total Other Changes	(1)	3	6
Total Recognized	1	4	5
ARHI | Other Postretirement Benefit Plan [Member]
Net Periodic Benefit Cost:
Service cost		1	1
Interest cost	1	1	1
Amortization of prior service cost (benefit)			1
Amortization of net loss			1
Net Periodic Benefit Cost	1	2	4
Other Changes in plan assets and benefit obligations recognized in OCI:
Net loss (gain)	(2)	(8)	(5)
Amortization of net loss			(1)
Amortization of prior service (cost)			(1)
Total Other Changes	(2)	(8)	(7)
Total Recognized	$ (1)	$ (6)	$ (3)

Post-Retirement and Similar 122

Post-Retirement and Similar Obligations - Schedule of Amounts Expected to be Amortized from Regulatory Assets or Liabilities and OCI into Net Periodic Benefit Cost (Detail) - Scenario, Forecast [Member] $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Pension Plan [Member] | OCI [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss	$ 1
Regulatory Assets or Liabilities [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss	126
Estimated prior service cost (benefit)	2
Regulatory Assets or Liabilities [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss	5
Estimated prior service cost (benefit)	$ (9)

Post-Retirement and Similar 123

Post-Retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase		4.00%
Discount rate			4.90%
Expected long-term return on plan assets		7.50%	7.50%
Rate of compensation increase - Networks		4.10%	4.20%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.12%	4.10%
Rate of compensation increase	3.50%
Discount rate	4.12%	3.80%
Expected long-term return on plan assets	7.40%
Rate of compensation increase - Networks	3.50%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.24%	4.24%
Rate of compensation increase	4.20%
Discount rate	4.24%	4.24%
Expected long-term return on plan assets	7.75%
Rate of compensation increase - Networks	4.20%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate			4.90%
Expected long-term return on plan assets	7.16%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Nontaxable Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	7.00%	7.50%	7.50%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Taxable Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	4.50%	5.00%	5.00%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.12%	4.10%
Discount rate	4.12%	3.80%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.24%	4.24%
Discount rate	4.24%	4.24%
ARHI | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.81%	3.90%
Discount rate	3.90%	3.90%	5.00%
Expected long-term return on plan assets	5.50%	5.50%	6.90%
ARHI | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.81%	3.90%
Discount rate	3.90%	3.90%	5.00%
Expected long-term return on plan assets	5.50%	5.75%	6.50%

Post-Retirement and Similar 124

Post-Retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Detail)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Iberdrola Renewables Holding, Inc. (IRHI) [Member]
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
Year that the rate reaches the ultimate trend rate		2,027
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.00%	7.00%
Year that the rate reaches the ultimate trend rate	2,026
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	9.00%	7.50%
Year that the rate reaches the ultimate trend rate	2,028
ARHI
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
Year that the rate reaches the ultimate trend rate		2,026
ARHI | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	6.75%	7.00%
Year that the rate reaches the ultimate trend rate	2,026
ARHI | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	8.50%	9.00%
Year that the rate reaches the ultimate trend rate	2,028

Post-Retirement and Similar 125

Post-Retirement and Similar Obligations - Schedule of Effects of One-Percent Change In Assumed Health Care Cost Trend Rates (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on total of service and interest cost, 1% Increase	$ 1
Effect on postretirement benefit obligation, 1% Increase	14
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on total of service and interest cost, 1% Decrease	(1)
Effect on postretirement benefit obligation, 1% Decrease	$ (12)

Post-Retirement and Similar 126

Post-Retirement and Similar Obligations - Estimated Future Benefit Payments (Detail) - Improvement and Modernization Act of 2003 [Member] - Networks and ARHI [Member] $ in Millions	Dec. 31, 2016USD ($)
Medicare Act Subsidy Receipts [Member]
Defined Benefit Plan Disclosure [Line Items]
2022 - 2026	$ 3
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2,017	211
2,018	212
2,019	216
2,020	219
2,021	224
2022 - 2026	1,125
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2,017	34
2,018	34
2,019	34
2,020	35
2,021	35
2022 - 2026	$ 169

Post-Retirement and Similar 127

Post-Retirement and Similar Obligations - Fair Value of Benefits Plan Assets by Asset Category (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 1,161	$ 981	$ 945
Level 3 [Member] | Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	61	89	75
Level 3 [Member] | Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	821	490	449
Level 3 [Member] | Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	5	84	79
Level 3 [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	274	318	$ 342
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	2,672	2,664
Pension Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	358	324
Pension Plan [Member] | Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	61	89
Pension Plan [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	120	314
Pension Plan [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	4	5
Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	49	57
Pension Plan [Member] | U.S. Government Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	172	171
Pension Plan [Member] | Registered Investment Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	122	114
Pension Plan [Member] | Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1,192	859
Pension Plan [Member] | Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	5	84
Pension Plan [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	589	647
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	414	602
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	120	314
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category		3
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | U.S. Government Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	172	171
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Registered Investment Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	122	114
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1,097	1,081
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	358	324
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	4	5
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	49	54
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	371	369
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	315	329
Pension Plan [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1,161	981
Pension Plan [Member] | Level 3 [Member] | Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	61	89
Pension Plan [Member] | Level 3 [Member] | Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	821	490
Pension Plan [Member] | Level 3 [Member] | Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	5	84
Pension Plan [Member] | Level 3 [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	274	318
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	160	162
Other Postretirement Benefit Plan [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	23	24
Other Postretirement Benefit Plan [Member] | Money Market Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	6	4
Other Postretirement Benefit Plan [Member] | Mutual Funds Fixed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	41	36
Other Postretirement Benefit Plan [Member] | Government and Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	2	2
Other Postretirement Benefit Plan [Member] | Mutual Funds Equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	72	46
Other Postretirement Benefit Plan [Member] | Mutual Funds, Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	16	50
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	118	153
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	23	24
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Money Market Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	4	4
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Funds Fixed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	39	36
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Funds Equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	43	46
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Mutual Funds, Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	9	43
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	42	9
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Money Market Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	2
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Funds Fixed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	2
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Government and Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	2	2
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Funds Equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	29
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Funds, Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 7	$ 7

Post-Retirement and Similar 128

Post-Retirement and Similar Obligations - Changes in Fair Value of Plan Assets Based on Level 3 Inputs (Detail) - Level 3 [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	$ 981	$ 945
Actual return on plan assets:
Relating to assets sold during the year	(12)	(21)
Relating to assets still held at the reporting date	45	3
Purchases, sales and settlements	147	54
Fair Value of Plan Assets, Ending balance	1,161	981
Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	89	75
Actual return on plan assets:
Relating to assets still held at the reporting date	2	10
Purchases, sales and settlements	(30)	4
Fair Value of Plan Assets, Ending balance	61	89
Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	490	449
Actual return on plan assets:
Relating to assets sold during the year	6	(3)
Relating to assets still held at the reporting date	51	(5)
Purchases, sales and settlements	274	49
Fair Value of Plan Assets, Ending balance	821	490
Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	84	79
Actual return on plan assets:
Relating to assets sold during the year	(19)	(19)
Relating to assets still held at the reporting date		19
Purchases, sales and settlements	(60)	5
Fair Value of Plan Assets, Ending balance	5	84
Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	318	342
Actual return on plan assets:
Relating to assets sold during the year	1	1
Relating to assets still held at the reporting date	(8)	(21)
Purchases, sales and settlements	(37)	(4)
Fair Value of Plan Assets, Ending balance	$ 274	$ 318

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions		Dec. 15, 2015	Dec. 31, 2016		Dec. 31, 2015		Dec. 31, 2014	[1]	Dec. 31, 2013	[1]	Nov. 30, 2011
Class Of Stock [Line Items]
Common stock, authorized			500,000,000		500,000,000
Common stock, issued			309,600,439		309,491,082						243
Common stock, outstanding		252,235,232	308,993,149	[1]	308,864,609	[1]	252,235,232		252,235,232
Common stock, par value			$ 0.01		$ 0.01
Common stock			$ 3		$ 3
Additional paid-in capital			$ 13,653		$ 13,653
Treasury stock, shares			491,459		626,473
Convertible preferred stock, shares outstanding			0		0
Issuance of common stock, shares	[1]		109,357		57,255,850
Release of common stock held in trust	[1]		135,014
Repurchase of common stock, shares	[1]		115,831
Repurchase of common stock			$ 5
Common stock issued from stock split		252,234,989
Iberdrola Renewables Holding, Inc [Member]
Class Of Stock [Line Items]
Percentage of equity owned by parent			81.50%		81.50%
[1]	Par value of share amounts is $.01

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)		$ (26)	$ 33	$ (2)
Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense(benefit)		(65)	(23)	(63)	$ (66)
Accumulated Other Comprehensive (Loss) Income		(86)	(52)	(99)	(100)
Gain on defined benefit plans, net of income taxes		7	4	1
Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense(benefit)	[1]	(16)	7	5
Net unrealized (loss) gain on derivatives qualifying as cash flow hedges		(42)	40	3
Other comprehensive income, net of tax		(34)	47	1
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense(benefit)	[1]	(70)	(54)	(61)	(66)
Designated as Hedging Instrument [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)		5	31	(2)
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Loss on defined benefit plans, net of income tax expense (benefit)		(14)	(21)	(25)	(26)
Gain on defined benefit plans, net of income taxes		7	4	1
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Loss on defined benefit plans, net of income tax expense (benefit)		(7)	(8)	(11)	$ (8)
Gain on defined benefit plans, net of income taxes		$ 1	$ 3	$ (3)
[1]	Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Equity - Accumulated Other C131

Equity - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized (loss) gain during period on derivatives qualified as cash flow hedges, income tax expense (benefit)	$ (15.8)	$ 20.9	$ (1.4)
Reclassification to net income of losses on cash flow hedges, income tax expense	11	4.9	4.1
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense (benefit)	4.3	2.2	0.6
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense (benefit)	$ 0.4	$ 1.7	$ (1.9)

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								12 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Numerator:
Net income attributable to AVANGRID	$ 207	$ 109	$ 102	$ 212	$ 96	$ 54	$ 11	$ 106	$ 630	$ 267	$ 424
Denominator:
Weighted average number of shares outstanding - basic									309,512,553	254,588,212	252,235,232
Weighted average number of shares outstanding - diluted									309,817,322	254,605,111	252,235,232
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic									$ 2.04	$ 1.05	$ 1.68
Earnings Per Common Share, Diluted									$ 2.04	$ 1.05	$ 1.68

Tax Equity Financing Arrange133

Tax Equity Financing Arrangements - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Oct. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Tax Equity Financing Arrangements [Line Items]
Accrued interest average rate		5.40%	8.50%
Assets of variable interest entities (VIEs)		$ 1,343,000,000	$ 1,401,000,000
Liabilities of variable interest entities (VIEs)		244,000,000	338,000,000
Equity method investments of variable interest entities (VIEs)		387,000,000	385,000,000	$ 262,000,000
Upfront cash payments		0
Gain on other income and (expense)	$ 5,000,000
Variable Interest Entity, Primary Beneficiary [Member]
Tax Equity Financing Arrangements [Line Items]
Equity method investments of variable interest entities (VIEs)		$ 161,000,000	$ 169,000,000
Aeolus I [Member]
Tax Equity Financing Arrangements [Line Items]
Percentage of equity owned by subsidiaries				10.00%

Grants, Government Incentive134

Grants, Government Incentives and Deferred Income - Schedule of Changes in Deferred Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Deferred Revenue Arrangement [Line Items]
Beginning Balance	$ 1,553	$ 1,621
Recognized in income	(70)	(68)
Ending Balance	1,483	1,553
Government Grants [Member]
Deferred Revenue Arrangement [Line Items]
Beginning Balance	1,529	1,606
Recognized in income	(68)	(77)
Ending Balance	1,461	1,529
Other Deferred Income [Member]
Deferred Revenue Arrangement [Line Items]
Beginning Balance	24	15
Recognized in income	(2)	9
Ending Balance	$ 22	$ 24

Grants, Government Incentive135

Grants, Government Incentives and Deferred Income - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Government Grants [Member]
Deferred Revenue Arrangement [Line Items]
Depreciable assets and contributions credited to property plant and equipment	$ 459	$ 390

Equity Method Investments - Add

Equity Method Investments - Additional Information (Detail) $ in Millions	Dec. 31, 2014USD ($)	Mar. 31, 2016USD ($)	Dec. 31, 2016USD ($)PlantJointVenture	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Schedule Of Investments [Line Items]
Equity method investments	$ 262		$ 387	$ 385	$ 262
Number of peaking generation plants | Plant			2
Equity method investment, distributions received			$ 20	12	$ 19
Proceeds from sale of ownership Interest	$ 19.6
Network [Member] | New York Transco [Member]
Schedule Of Investments [Line Items]
Equity method investments			$ 22
Business combination, equity interest percentage			20.00%
Shell Wind Energy Inc [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage			50.00%
Equity method investments			$ 45	41
Horizon Wind Energy LLC [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage			50.00%
Number of joint ventures | JointVenture			2
Flat Rock Wind Power LLC [Member]
Schedule Of Investments [Line Items]
Equity method investments			$ 128	143
Flat Rock Wind Power II LLC [Member]
Schedule Of Investments [Line Items]
Equity method investments			$ 64	69
NRG Energy Inc [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage			50.00%
Equity method investments			$ 128	110
Number of peaking generation plants | Plant			2
Iroquois [Member]
Schedule Of Investments [Line Items]
Equity method investments				$ 22
Proceeds from sale of ownership Interest		$ 53.8	$ 53.8
Net income on disposition of business		$ 19	$ 19

Other Financial Statements I137

Other Financial Statements Items - Schedule of Other Income and (Expense) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Other Nonoperating Income Expense [Abstract]
Allowance for funds used during construction	$ 26	$ 21	$ 17
Carrying costs on regulatory assets	14	28	29
Other	36	6	6
Total Other income and (expense)	$ 76	$ 55	$ 52

Other Financial Statements I138

Other Financial Statements Items - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015
Accounts Notes And Loans Receivable [Line Items]
Gain on sale of investment	$ 33
Other	241	$ 35
Restricted Cash [Member]
Accounts Notes And Loans Receivable [Line Items]
Other	5	7
Deferred Payment Arrangements [Member]
Accounts Notes And Loans Receivable [Line Items]
Accounts receivable	54	$ 62
Safe Harbor Turbine Payments [Member]
Accounts Notes And Loans Receivable [Line Items]
Other	$ 186

Other Financial Statements I139

Other Financial Statements Items - Schedule of Accounts Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Receivables [Abstract]
Trade receivables	$ 1,183	$ 1,036
Allowance for bad debts	(64)	(62)	$ (49)	$ (58)
Total Accounts Receivable	$ 1,119	$ 974

Other Financial Statements I140

Other Financial Statements Items - Schedule of Change in Allowance For Bad Debts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Receivables [Abstract]
Beginning balance	$ 62	$ 49	$ 58
Current period provision	48	46	39
Write-off as uncollectible	(46)	(33)	(48)
Ending balance	$ 64	$ 62	$ 49

Other Financial Statements I141

Other Financial Statements Items - Schedule of Prepayments and Other Current Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Prepaid other taxes	$ 153	$ 130
Broker margin and collateral accounts	32	46
Loans to third parties	3	3
Fixed-term deposits	3	11
Other pledged deposits	8	24
Prepaid expenses	53	53
Other	3	18
Total	$ 255	$ 285

Other Financial Statements I142

Other Financial Statements Items - Schedule of Other Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Payables And Accruals [Abstract]
Advances received	$ 107	$ 96
Accrued salaries	84	68
Short-term environmental provisions	34	35
Collateral deposits received	45	59
Pension and other postretirement	5	5
Other	4	22
Total	$ 279	$ 285

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)Segment	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	3
Operating Revenues	$ 6,018	$ 4,367	$ 4,594
Regulated Electric Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	3,686	2,779	2,726
Regulated Gas Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	1,306	605	668
Other Networks [Member]
Segment Reporting Information [Line Items]
Operating Revenues	35	2	2
Renewable Energy Generation Of Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues	1,000	1,051	1,180
Gas Storage Services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	7	21	8
Gas Trading Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	$ (14)	$ (92)	$ 4
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								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting Information [Line Items]
Revenue - external										$ 6,018	$ 4,367	$ 4,594
Depreciation and amortization										804	695	629
Operating income (loss) from continuing operations		$ 306	$ 217	$ 322	$ 349	$ 83	$ 161	$ 73	$ 196	1,194	513	885
Adjusted EBITDA										1,998	1,220	1,539
Earnings (loss) from equity method investments										7		12
Capital expenditures										1,707	1,082	1,030
Property, Plant and Equipment, VIEs		21,548				20,711				21,548	20,711	17,133
Equity method investments		387				385				387	385	262
Total assets		31,309				30,743				31,309	30,743	24,162
Impairment of non-current assets											12	25
Operating Segments [Member] | Network [Member]
Segment Reporting Information [Line Items]
Revenue - external										5,027	3,386	3,396
Revenue - intersegment										3		1
Depreciation and amortization										466	328	275
Operating income (loss) from continuing operations										1,086	537	616
Adjusted EBITDA										1,552	865	891
Earnings (loss) from equity method investments										15	1
Capital expenditures										1,140	773	775
Property, Plant and Equipment, VIEs		13,032				12,363				13,032	12,363	8,389
Equity method investments		151				110				151	110
Total assets		20,753				20,126				20,753	20,126	12,858
Operating Segments [Member] | Renewables [Member]
Segment Reporting Information [Line Items]
Revenue - external										1,000	1,051	1,180
Revenue - intersegment										15	16	9
Depreciation and amortization										313	344	332
Operating income (loss) from continuing operations										149	100	257
Adjusted EBITDA										462	456	613
Earnings (loss) from equity method investments										(8)	(5)	2
Capital expenditures										561	304	250
Property, Plant and Equipment, VIEs		8,015				7,835				8,015	7,835	8,219
Equity method investments		236				253				236	253	262
Total assets		9,884				10,685				9,884	10,685	12,328
Impairment of non-current assets											12	24
Operating Segments [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Revenue - external										(7)	(71)	12
Revenue - intersegment										39	52	72
Depreciation and amortization										25	23	22
Operating income (loss) from continuing operations										(41)	(85)	16
Adjusted EBITDA										(16)	(62)	38
Capital expenditures										6	5	5
Property, Plant and Equipment, VIEs		501				513				501	513	525
Total assets		1,124				1,265				1,124	1,265	1,393
Corporate and Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue - external	[1]									(2)	1	6
Revenue - intersegment	[1]									(57)	(68)	(82)
Operating income (loss) from continuing operations	[1]										(39)	(4)
Adjusted EBITDA	[1]										(39)	(3)
Earnings (loss) from equity method investments	[1]										4	10
Equity method investments	[1]					22					22
Total assets	[1]	$ (452)				$ (1,333)				$ (452)	$ (1,333)	(2,417)
Impairment of non-current assets	[1]											$ 1
[1]	Does not represent a segment. It mainly includes Corporate and intercompany eliminations.

Segment information - Reconcili

Segment information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Segment Reporting [Abstract]
Consolidated Adjusted EBITDA	$ 1,998	$ 1,220	$ 1,539
Impairment of non-current assets		12	25
Depreciation and amortization	804	695	629
Interest expense, net of capitalization	268	267	243
Income tax expense	379	34	282
Other income and (expense)	76	55	52
Earnings from equity method investments	7		12
Net Income	$ 630	$ 267	$ 424

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Iberdrola Financiacion, S.A. [Member]
Related Party Transaction [Line Items]
Purchases From	$ (2)	$ (1)	$ (2)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Purchases From	(8)	(9)	(10)
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Purchases From	(37)	(55)	(49)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Purchases From	(31)	(35)	(20)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Sales To	21	3	12
Purchases From	$ (1)	$ (2)	$ (10)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Receivable from related party, write-off	$ 46,000,000	$ 33,000,000	$ 48,000,000
Impairments		12,000,000	25,000,000
Equity method investments	387,000,000	385,000,000	262,000,000
Contributions in aid of construction	69,000,000	38,000,000	$ 43,000,000
Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Portion of amount receivable from related parties	1,000,000	68,000,000
Affiliated Entity [Member] | Impairment of non-current assets [Member]
Related Party Transaction [Line Items]
Receivable from related party, write-off	10,000,000
Impairments	$ 0
Iberdrola, S.A. [Member] | Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%
Related party transaction, amount	$ 269,000,000	$ 70,000,000
Payments to related party	$ 92,000,000
Iberdrola, S.A. [Member] | Siemens AG And Gamesa Corporacion Tecnologica S.A. [Member]
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired	8.10%
Network [Member] | New York Transco [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%
Increase in equity method investments	$ 21,000,000
Equity method investments	22,000,000
Total cash consideration received	67,000,000
Proceed from contributions in assets transfer	43,000,000
Contributions in aid of construction	22,000,000
Proceed from contributions in advanced lease payment	$ 2,000,000
Lease period of land and attachment right	99 years
Portion of amount receivable from related parties	$ 11,000,000

Related Party Transactions -148

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2016	Dec. 31, 2015
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Owed By		$ 7
Owed To	$ (14)	(5)
Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Owed By	1	68
Owed To	(181)	(77)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Owed To	(30)	(3)
Iberdrola Energy Projects, Inc. [Member]
Related Party Transaction [Line Items]
Owed By		1
Owed To		(3)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Owed By	22
Owed To	(3)	$ (2)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Owed By	$ 2

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended		12 Months Ended
	Dec. 31, 2016USD ($)shares	Jul. 31, 2016$ / sharesshares	Dec. 31, 2016USD ($)Installment$ / sharesshares	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares authorized for stock-based compensation plans | shares	2,500,000		2,500,000
Stock-based compensation expense			$ 0.6	$ 6	$ 4.8
Income tax benefit recognized for stock-based compensation arrangements			0.2	2.4	$ 1.9
Stock-based compensation other non-current liabilities	$ 9.5		$ 9.5	$ 17.5
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
Performance Shares Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of PSUs granted | shares			1,335,416
Share-based payment award options grant date fair value, per share | $ / shares			$ 31.92
Unrecognized cost for non-vested PSUs	$ 22		$ 22
Recognition of PSU costs, weighted-average period			5 years
Performance Shares Units [Member] | Officers and Employees [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of PSUs granted | shares	11,804	1,298,683
Number of installment payments of employee related payables | Installment			3
Share-based payment award options grant date fair value, per share | $ / shares		$ 31.80
Share-based payment award options requisite service period			7 years
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

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Nonvested PSUs (Detail) - Performance Shares Units [Member]	12 Months Ended
	Dec. 31, 2016$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of PSUs, Nonvested Balance – December 31, 2015 | shares	411,207
Number of PSUs granted | shares	1,335,416
Number of PSUs, Forfeited | shares	(36,592)
Number of PSUs, Vested | shares	(186,050)
Number of PSUs, Nonvested Balance – December 31, 2016 | shares	1,523,981
Weighted Average Grant Date Fair Value, Nonvested Balance – December 31, 2015 | $ / shares	$ 39.60
Weighted Average Grant Date Fair Value, Granted | $ / shares	31.92
Weighted Average Grant Date Fair Value, Forfeited | $ / shares	32.83
Weighted Average Grant Date Fair Value, Vested | $ / shares	40.84
Weighted Average Grant Date Fair Value, Nonvested Balance – December 31, 2016 | $ / shares	$ 33.01

Schedule of Quarterly Financial

Schedule of Quarterly Financial Data (unaudited) (Detail) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Quarterly Financial Information Disclosure [Abstract]
Operating revenues		$ 1,491	$ 1,418	$ 1,439	$ 1,670	$ 1,153	$ 1,048	$ 939	$ 1,227
Operating Income		306	217	322	349	83	161	73	196	$ 1,194	$ 513	$ 885
Net Income		207	109	102	212	96	54	11	106	630	267	424
Net Income attributable to Avangrid, Inc.		$ 207	$ 109	$ 102	$ 212	$ 96	$ 54	$ 11	$ 106	$ 630	$ 267	$ 424
Earnings Per Common Share, Basic and Diluted:	[1]	$ 0.67	$ 0.35	$ 0.33	$ 0.69	$ 0.37	$ 0.22	$ 0.04	$ 0.42
[1]	Based on weighted average number of 309 million shares outstanding each quarter in 2016 and 252 million shares for each quarter of 2015, except for fourth quarter of 2015, which is based on weighted average of 262 million shares as a result of the acquisition of UIL

Schedule of Quarterly Financ152

Schedule of Quarterly Financial Data (unaudited) (Parenthetical) (Detail) - shares shares in Millions	3 Months Ended
	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015
Selected Quarterly Financial Information [Line Items]
Weighted average shares outstanding	309	309	309	309		252	252	252
UIL Holdings [Member]
Selected Quarterly Financial Information [Line Items]
Weighted average shares outstanding					262

Quarterly Financial Data (un153

Quarterly Financial Data (unaudited) - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2014	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2016
Selected Quarterly Financial Information [Line Items]
Proceeds from sale of ownership Interest	$ 19.6
Unfunded future income tax expense		$ 126						$ 126
Rate credits				$ 44
Tax benefits				(63)
UIL Holdings [Member]
Selected Quarterly Financial Information [Line Items]
Pre-tax merger related expenses				$ 18.5	$ 7	$ 8	$ 4
Iroquois [Member]
Selected Quarterly Financial Information [Line Items]
Proceeds from sale of ownership Interest			$ 53.8					53.8
Net income on disposition of business			$ 19					$ 19

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - $ / shares		Feb. 16, 2017	Jan. 31, 2017	Dec. 31, 2016	Mar. 01, 2017	Dec. 31, 2015	Nov. 30, 2011
Subsequent Event [Line Items]
Release of common stock held in trust	[1]			135,014
Common stock, par value				$ 0.01		$ 0.01
Quarterly dividend payable, per share				$ 1.728
Common stock, issued				309,600,439		309,491,082	243
Subsequent Event [Member]
Subsequent Event [Line Items]
Release of common stock held in trust			5,088
Common stock, par value			$ 0.01		$ 0.01
Dividend declared date		Feb. 16, 2017
Quarterly dividend payable, per share		$ 0.432
Dividend payment date		Apr. 3, 2017
Dividend record date		Mar. 10, 2017
Common stock, issued					70,493
[1]	Par value of share amounts is $.01

Acquisition of UIL and Issua155

Acquisition of UIL and Issuance of Common Stock - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions		Feb. 16, 2017	Dec. 16, 2015	Dec. 31, 2016	Mar. 01, 2017	Jan. 31, 2017	Dec. 31, 2015
Business Acquisition [Line Items]
Effective date of business acquisition of UIL Holdings				Feb. 25, 2015
Shares issued in connection with acquisition				309,490,839
Business acquisition, share price				$ 10.50
Common stock, par value				$ 0.01			$ 0.01
Repurchase of common stock, shares	[1]			115,831
Repurchase of common stock				$ 5
Subsequent Event [Member]
Business Acquisition [Line Items]
Common stock, par value					$ 0.01	$ 0.01
Dividend declared date		Feb. 16, 2017
Dividend payment date		Apr. 3, 2017
Dividend record date		Mar. 10, 2017
UIL Holdings [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition			57,255,850
Business acquisition, share price			$ 50.10	$ 10.50
Avangrid, Inc [Member]
Business Acquisition [Line Items]
Repurchase of common stock, shares				115,831
Repurchase of common stock				$ 5
Avangrid, Inc [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Dividend declared date		Feb. 16, 2017
Quarterly dividend payable, per share		$ 0.432
Dividend payment date		Apr. 3, 2017
Dividend record date		Mar. 10, 2017
Avangrid, Inc [Member] | UIL Holdings [Member]
Business Acquisition [Line Items]
Effective date of business acquisition of UIL Holdings				Feb. 25, 2015
Issuance of share in connection of acquisition				In connection with the acquisition, AVANGRID issued 309,490,839 shares of its common stock, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per each share of the common stock of UIL issued and outstanding at the acquisition date.
Shares issued in connection with acquisition			309,490,839
Business acquisition, share price			$ 10.50
Percentage of ownership			18.50%
Common stock, par value			$ 0.01
Avangrid, Inc [Member] | UIL Holdings [Member] | UIL shareowners [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition			57,255,850
Avangrid, Inc [Member] | UIL Holdings [Member] | Iberdrola, S.A. [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition			252,234,989
Iberdrola Renewables Holding, Inc [Member]
Business Acquisition [Line Items]
Percentage of equity owned by parent				81.50%			81.50%
[1]	Par value of share amounts is $.01

Non-current Debt - Additional I

Non-current Debt - Additional Information (Detail) - UIL, and The Bank of New York Mellon [Member] - USD ($) $ in Millions	Dec. 19, 2016	Dec. 31, 2016
Debt Instrument [Line Items]
Debt instrument principal amount	$ 450
Debt instrument, interest rate	4.625%
Debt instrument maturity year	2,020
Capital contribution to subsidiary by parent		$ 483

Cash Dividends Paid by Subsi157

Cash Dividends Paid by Subsidiaries (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Cash Dividend [Line Items]
Cash dividends paid	$ 420	$ 1,111	$ 200
AVANGRID Networks [Member]
Cash Dividend [Line Items]
Cash dividends paid	220	59	$ 200
AVANGRID Renewables [Member]
Cash Dividend [Line Items]
Cash dividends paid	$ 200	750
Other AVANGRID subsidiaries [Member]
Cash Dividend [Line Items]
Cash dividends paid		$ 302

Cash Dividends Paid by Subsi158

Cash Dividends Paid by Subsidiaries - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2016
Avangrid, Inc [Member]
Cash Dividend [Line Items]
Non cash dividend recorded by parent company		$ 827
Central Maine Power Company [Member]
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 50