Avangrid (AGR) 10-K 1 Apr 16 2015 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($)	12 Months Ended
	Dec. 31, 2015	Mar. 28, 2016	Jun. 30, 2015
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2015
Document Fiscal Year Focus	2,015
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	No
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		308,962,088
Entity Public Float			$ 0

Combined and Consolidated State

Combined and Consolidated Statements of Operations - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Operating Revenues	$ 4,367	$ 4,594	$ 4,313
Operating Expenses
Purchased power, natural gas and fuel used	972	1,181	1,088
Operations and maintenance	1,808	1,560	1,541
Impairment of non-current assets	12	25	620
Depreciation and amortization	695	629	594
Taxes other than income taxes	367	314	291
Total Operating Expenses	3,854	3,709	4,134
Operating Income	513	885	179
Other Income and (Expense)
Other income and (expense)	55	52	54
Earnings (losses) from equity method investments		12	(3)
Interest expense, net of capitalization	(267)	(243)	(245)
Income (Loss) Before Income Tax	301	706	(15)
Income tax expense	34	282	35
Net Income (Loss)	267	424	(50)
Less: Net income attributable to noncontrolling interests			1
Net Income (Loss) Attributable to AVANGRID, Inc.	$ 267	$ 424	$ (51)
Earnings (Loss) Per Common Share, Basic:	$ 1.05	$ 1.68	$ (0.20)
Earnings (Loss) Per Common Share, Diluted:	$ 1.05	$ 1.68	$ (0.20)
Weighted-average Number of Common Shares Outstanding:
Basic	254,588,212	252,235,232	252,235,232
Diluted	254,605,111	252,235,232	252,235,232
Avangrid, Inc [Member]
Operating Expenses
Taxes other than income taxes	$ 5	$ 2	$ (15)
Total Operating Expenses	43	4	2
Operating expense	38	2	17
Operating Income	(43)	(4)	(2)
Other Income and (Expense)
Other income and (expense)	10	(1)	6
Earnings (losses) from equity method investments	44	515	(37)
Interest expense, net of capitalization	(14)	(34)	(22)
Income (Loss) Before Income Tax	(3)	476	(55)
Income tax expense	(270)	52	(4)
Net Income (Loss)	267	424	(51)
Net Income (Loss) Attributable to AVANGRID, Inc.	$ 267	$ 424	$ (51)

Combined and Consolidated Stat3

Combined and Consolidated Statements of Comprehensive Income (Loss) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Net Income (Loss)		$ 267	$ 424	$ (50)
Other Comprehensive Income, Amounts arising during the year:
Gain on defined benefit plans, net of income taxes		4	1	1
Amortization of pension cost for nonqualified plans, net of income taxes		3	(3)	(1)
Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes		33	(2)
Reclassification to net income of losses on cash flow hedges, net of income taxes	[1]	7	5	7
Other comprehensive income, net of tax		47	1	7
Comprehensive Income (Loss)		314	425	(43)
Less: Comprehensive income attributable to noncontrolling interests				1
Comprehensive Income (Loss) attributable to AVANGRID, Inc.		314	425	(44)
Net Income (Loss)		267	424	(51)
Other comprehensive income, net of tax		47	1	7
Avangrid, Inc [Member]
Net Income (Loss)		267	424	(51)
Other Comprehensive Income, Amounts arising during the year:
Other comprehensive income, net of tax		47	1	7
Comprehensive Income (Loss)		314	425	(44)
Net Income (Loss)		267	424	(51)
Other comprehensive income, net of tax		$ 47	$ 1	$ 7
[1]	Reclassification is reflected in the operating expenses line item in the combined and consolidated statements of operations.

Combined and Consolidated Stat4

Combined and Consolidated Statements of Comprehensive Income (Loss) (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	$ 20.9	$ (1.4)	$ 0
Reclassification to net income of losses on cash flow hedges, income tax expense	4.9	4.1	4.6
Qualified Pension Plan [Member]
Gain (loss) on defined benefit plans, income tax expense (benefit)	2.2	0.6	0.5
Non-Qualified Pension Plans [Member]
Gain (loss) on defined benefit plans, income tax expense (benefit)	$ 1.7	$ (1.9)	$ 1

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2015		Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 427		$ 482
Accounts receivable and unbilled revenues, net	974		841
Accounts receivable from affiliates	70		50
Notes receivable from affiliates	6
Derivative assets	88		134
Fuel and gas in storage	307		229
Materials and supplies	98		98
Prepayments and other current assets	285		288
Regulatory assets	219		80
Total Current Assets	2,474		2,202
Property, plant and equipment, at cost	25,745	[1]	21,499	[2]
Less: accumulated depreciation	(6,372)	[3]	(5,762)	[4]
Net Property, Plant and Equipment	20,711		17,133
Equity method investments	385		262
Other investments	64		91
Regulatory assets	3,314		2,399
Other Assets
Goodwill	3,115		1,361
Intangible assets	556		569
Derivative assets	89		93
Other	35		52
Total Other Assets	3,795		2,075
Total Assets	30,743		24,162
Current Liabilities
Current portion of debt	206		148
Tax equity financing arrangements	107		124
Notes payable	163
Interest accrued	61		39
Accounts payable	830		684
Accounts payable to affiliates	90		239
Taxes accrued	55		8
Derivative liability	91		103
Other current liabilities	285		262
Regulatory liabilities	147		165
Total Current Liabilities	2,035		1,772
Regulatory liabilities	1,841		1,229
Deferred income taxes regulatory	519		433
Other Non-current Liabilities
Deferred income taxes	2,798		2,269
Deferred income	1,553		1,621
Pension and other postretirement	1,202		785
Tax equity financing arrangements	185		277
Derivative liability	94		38
Asset retirement obligations	184		234
Environmental remediation costs	406		284
Other	330		254
Total Other Non-current Liabilities	6,752		5,762
Non-current Debt	4,530		2,489
Total Non-current Liabilities	13,642		9,913
Total Liabilities	$ 15,677		$ 11,685
Commitments and Contingencies
Stockholders' Equity:
Common stock	$ 3		$ 3
Additional paid-in capital	13,653		11,375
Retained earnings	1,449		1,182
Accumulated other comprehensive loss	(52)		(99)
Total Stockholders' Equity	15,053		12,461
Noncontrolling interests	13		16
Total Equity	15,066		12,477
Total Liabilities and Equity	30,743		24,162
Avangrid, Inc [Member]
Current Assets
Cash and cash equivalents	125		3
Accounts receivable from affiliates	602		3
Notes receivable from affiliates	453		771
Prepayments and other current assets	16		57
Total Current Assets	1,196		834
Other investments	14,093		12,792
Other Assets
Other	4		6
Total Other Assets	152		6
Deferred income taxes	148
Total Assets	15,441		13,632
Current Liabilities
Notes payable	321		652
Interest accrued	1		7
Accounts payable	3		3
Taxes accrued	44		141
Other current liabilities	4		2
Total Current Liabilities	385		805
Accounts payable and accrued liabilities	12
Other Non-current Liabilities
Deferred income taxes			14
Other	3		2
Total Other Non-current Liabilities	3		16
Non-current Debt			350
Total Non-current Liabilities	3		366
Total Liabilities	388		1,171
Stockholders' Equity:
Common stock	3		3
Additional paid-in capital	13,653		11,375
Retained earnings	1,449		1,182
Accumulated other comprehensive loss	(52)		(99)
Total Stockholders' Equity	15,053		12,461
Total Liabilities and Equity	15,441		13,632
Energy Equipment [Member]
Current Assets
Net Property, Plant and Equipment	19,373		15,737
Construction In Progress [Member]
Current Assets
Net Property, Plant and Equipment	$ 1,338		$ 1,396
[1]	Includes capitalized leases of $178 million primarily related to electric generation, distribution, transmission and other.
[2]	Includes capitalized leases of $158 million primarily related to electric generation, distribution, transmission and other.
[3]	Includes accumulated amortization of capitalized leases of $53 million.
[4]	Includes accumulated amortization of capitalized leases of $47 million.

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - $ / shares	Dec. 31, 2015	Dec. 31, 2014	Nov. 30, 2011
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.01	$ 0.01
Common stock, authorized	500,000,000	500,000,000
Common stock, issued	309,491,082	252,235,232	243
Common stock, outstanding	308,864,609	252,235,232

Combined and Consolidated Stat7

Combined and Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Flow from Operating Activities
Net income (loss)	$ 267	$ 424	$ (50)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Depreciation and amortization	695	629	594
Impairment of non-current assets	12	25	620
Accretion expenses	14	14	14
Regulatory assets/liabilities amortization	101	(38)	(2)
Regulatory assets/liabilities carrying cost	41	35	21
Pension cost	115	74	96
(Earnings) losses from equity method investments		(12)	3
Unrealized losses (gains) on marked to market derivative contracts	10	(116)	4
Deferred taxes	87	261	58
Changes in current operating assets and liabilities, net of effects of acquisition
Decrease (increase) in accounts receivable and unbilled revenues	160	(1)	56
Decrease (increase) in inventories	4	58	(1)
Decrease in other assets	(42)	(101)	(126)
(Decrease) increase in accounts payable	(10)	27	(208)
(Decrease) increase in other liabilities	(188)	(110)	123
Increase (decrease) in taxes accrued	21	(13)	2
Increase (decrease) in regulatory assets/liabilities	74	175	(27)
Net Cash provided by Operating Activities	1,361	1,331	1,177
Cash Flow from Investing Activities
Capital expenditures	(1,082)	(1,030)	(944)
Proceeds from disposal of property, plant and equipment			2
Contributions in aid of construction	38	43	24
Government grants	17	4	31
Acquisition of business, net of $48 million cash acquired	(547)
Proceeds from sale of businesses, net of cash	3	31
(Payments to) receipts from affiliates	(6)	10
Other investments and equity method investments	59	54	19
Net Cash used in Investing Activities	(1,518)	(888)	(868)
Cash Flow from Financing Activities
Capital contributions from Parent			153
Non-current note issuance	350		225
Repayments of non-current debt	(141)	(27)	(273)
Proceeds (repayments) of other short-term debt, net	10	(14)	(165)
Proceeds from sales leaseback			110
Repayments of capital leases	(12)	(21)	(21)
Payments on tax equity financing arrangements	(102)	(119)	(173)
Contribution from noncontrolling interests		4
Dividends to noncontrolling interests	(3)	(3)
Net Cash Provided by (used in) Financing Activities	102	(180)	(144)
Net (Decrease) Increase in Cash and Cash Equivalents	(55)	263	165
Cash and Cash Equivalents, Beginning of Year	482	219	54
Cash and Cash Equivalents, End of Year	427	482	219
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	132	133	147
Cash paid (refund) for income taxes	7	21	(30)
Avangrid, Inc [Member]
Cash Flow from Operating Activities
Net income (loss)	267	424	(51)
Adjustments to reconcile net income (loss) to net cash provided by operating activities
Regulatory assets/liabilities amortization		1
(Earnings) losses from equity method investments	(44)	(515)	37
Changes in current operating assets and liabilities, net of effects of acquisition
(Decrease) increase in accounts payable	12		1
Accounts receivable from subsidiaries	(399)	(2)
Accounts payable to subsidiaries	1	2	(6)
Interest accrued to subsidiaries	(5)	(1)	(12)
Taxes accrued	(96)	28	(46)
Other current assets and liabilities	35	7	(1)
Deferred income taxes	(151)	24	61
Net Cash provided by Operating Activities	(380)	(32)	(17)
Cash Flow from Investing Activities
Other investments and equity method investments		11	5
Net Cash used in Investing Activities	833	(267)	(133)
Notes receivable from subsidiaries	317	(478)	(95)
Acquisition of subsidiary	(595)
Investments in subsidiaries			(165)
Return of capital from investments in subsidiaries	1,111	200	122
Cash Flow from Financing Activities
Net Cash Provided by (used in) Financing Activities	(331)	302	143
Proceeds (repayments) of short-term notes payable from subsidiaries, net	(331)	302	150
Non-current debt with subsidiaries			(7)
Net (Decrease) Increase in Cash and Cash Equivalents	122	3	(7)
Cash and Cash Equivalents, Beginning of Year	3		$ 7
Cash and Cash Equivalents, End of Year	$ 125	$ 3

Combined and Consolidated Stat8

Combined and 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

Combined and Consolidated Stat9

Combined and Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Common stock		Additional paid-in capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Stockholders' Equity	Non controlling Interests
Balance at Dec. 31, 2012		$ 11,348	$ 3		$ 10,629	$ 809	$ (107)	$ 11,334	$ 14
Balance, shares at Dec. 31, 2012	[1]		252,235,232
Net Income (Loss)		(50)				(51)		(51)	1
Other comprehensive income, net of tax		7					7	7
Comprehensive income (loss)		(43)
Capital contribution from non-controlling		746			746			746
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 (Loss)		424				424		424
Other comprehensive income, net of tax		1					1	1
Comprehensive income (loss)		425
Capital contribution from non-controlling		4							4
Balance at Dec. 31, 2014		$ 12,477	$ 3		11,375	1,182	(99)	12,461	16
Balance, shares at Dec. 31, 2014		252,235,232	252,235,232	[1]
Dividends to noncontrolling interests		$ (3)							(3)
Net Income (Loss)		267				267		267
Other comprehensive income, net of tax		47					47	47
Comprehensive income (loss)		314
Issuance of common stock		2,278			2,278			2,278
Issuance of common stock, shares	[1]		57,255,850
Treasury stock, shares	[1]		(626,473)
Balance at Dec. 31, 2015		$ 15,066	$ 3		$ 13,653	$ 1,449	$ (52)	$ 15,053	13
Balance, shares at Dec. 31, 2015		308,864,609	308,864,609	[1]
Dividends to noncontrolling interests		$ (3)							$ (3)
[1]	Par value of share amounts is $.01

Combined and Consolidated Sta10

Combined and Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Statement Of Stockholders Equity [Abstract]
Common Stock, Par or Value Per Share	$ 0.01	$ 0.01
Other Comprehensive Income, Net of Taxes	$ 29.7	$ 1.4	$ 6.1

Background and Nature of Operat

Background and Nature of Operations	12 Months Ended
	Dec. 31, 2015
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 through its principal subsidiaries AVANGRID Networks, Inc. (Networks), UIL Holdings Corporation (UIL) and AVANGRID Renewables Holding, Inc. (ARHI) in the regulated energy distribution, renewable energy generation (Renewables) and gas businesses (Gas), collectively (Renewables and Gas). AVANGRID is an 81.5% owned subsidiary of Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was organized in 1997 as Energy East Corporation under the laws of New York as the holding company for the principal operating utility companies. 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 and Maine. 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 & Electric Corporation (RGE) and Maine Natural Gas Company (MNG). 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 The United Illuminating Company (UI) and the natural gas transportation, distribution and sales operations of The Southern Connecticut Gas Company (SCG), Connecticut Natural Gas Corporation (CNG) and The Berkshire Gas Company. 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, 2015
Basis of Presentation	Note 2. Basis of Presentation The accompanying combined and consolidated financial statements have been prepared in accordance with U.S GAAP and are presented on a combined basis prior to the Reorganization, and on a consolidated basis subsequent to the Reorganization. For the periods prior to the Reorganization the combined financial statements include AVANGRID, ARHI and Networks (combined entities) all of which were under common control of Iberdrola, and for the periods subsequent to the Reorganization, the consolidated financial statements include AVANGRID and its consolidated subsidiaries Networks and ARHI until December 16, 2015, and Networks, UIL and ARHI (consolidated entities) afterwards. The combined financial statements have been prepared on a combined basis to allow for comparability with the consolidated financial statements for the periods subsequent to the Reorganization. All intercompany transactions and accounts have been eliminated in all periods presented. All share and per share information included in the combined and consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend. As a result of the common control transfers occurring as part of the Reorganization, management recorded the net assets of ARHI in these combined and consolidated financial statements at the historical accounting basis of Iberdrola. The historical accounting basis of Iberdrola includes purchase accounting adjustments related to Iberdrola’s acquisition of ARHI in 2007. At the time of the Reorganization, the holding of Networks was not considered to be a substantive operating entity as it did not hold any direct operations prior to it and the Networks businesses had always been a part of AVANGRID. As a result the net assets of Networks in these combined and consolidated financial statements are recorded at the historical accounting basis of AVANGRID, which do not include purchase accounting adjustments related to Iberdrola’s acquisition of Energy East in 2008. Immaterial corrections to prior periods During the year ended December 31, 2015, we identified immaterial corrections to prior periods related to property, plant and equipment and depreciation expense in our Renewables reportable segment. The corrections resulted in an overstatement of depreciation expense and an understatement of income tax expense in the combined and consolidated statements of operations for the years ended December 31, 2013 and 2012. The recorded balances of accumulated depreciation were likewise overstated with deferred income tax liabilities being understated in the consolidated balance sheets as of December 31, 2014, 2013 and 2012. We evaluated the effects of these corrections on prior periods’ combined and consolidated financial statements, individually and in the aggregate, in accordance with the guidance in Accounting Standards Codification (ASC) Topic 250, Accounting Changes and Error Corrections, ASC Topic 250-10-S99-1, Assessing Materiality, and ASC Topic 250-10-S99-2, Considering the Effects of Prior Year Misstatements when Quantifying Misstatements in Current Year Financial Statements, and concluded that no prior period is materially misstated. However, in accordance with the aforementioned ASC Topics, we have determined to revise our combined and consolidated financial statements for the prior periods presented herein. As a result of the correction, the cumulative effect of the change on retained earnings as of December 31, 2013 and 2012 was an increase of $21 million and $7 million, respectively. Total assets, deferred income taxes, total other non-current liabilities, total non-current liabilities and total liabilities as reported in the table below are shown after reclassifications discussed in Note 3 of these combined and consolidated financial statements. Net loss per common share as reported in the table below is shown after retroactive application of stock split discussed in Note 17 of these combined and consolidated financial statements. The revision had no net impact on our net cash provided by operating activities for the year ended December 31, 2013. A summary of the effect of the correction on the consolidated balance sheet as of December 31, 2014 is as follows: As of December 31, 2014 As Reported Correction As Revised (Millions) Accumulated depreciation $ (5,796 ) $ 34 $ (5,762 ) Net Property, Plant and Equipment in Service 15,703 34 15,737 Total Property, Plant and Equipment 17,099 34 17,133 Total assets 24,128 34 24,162 Deferred income taxes 2,256 13 2,269 Total Other Non-current Liabilities 5,749 13 5,762 Total Non-current Liabilities 9,900 13 9,913 Total liabilities 11,672 13 11,685 Retained earnings 1,161 21 1,182 Total Stockholders' Equity 12,440 21 12,461 Total Equity 12,456 21 12,477 Total Liabilities and Equity $ 24,128 $ 34 $ 24,162 A summary of the effect of the correction on the combined and consolidated statement of operations for the year ended December 31, 2013 is as follows: Year Ended December 31, 2013 As Reported Correction As Revised (Millions, except per share data) Depreciation and amortization $ 617 $ (23 ) $ 594 Total Operating Expenses 4,157 $ (23 ) 4,134 Operating income 156 23 179 Loss Before Income Tax (38 ) 23 (15 ) Income tax expense 26 9 35 Net Loss (64 ) 14 (50 ) Net Loss Per Common Share, Basic and Diluted: $ (0.26 ) $ (0.06 ) $ (0.20 )
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 combined and consolidated financial statements and notes thereto of AVANGRID, Inc. and subsidiaries (Group). AVANGRID, Inc. indirectly or directly owns all of the ownership interests of its significant subsidiaries. AVANGRID, Inc. relies on dividends or loans from its subsidiaries to fund dividends to its primary shareholder. AVANGRID, Inc.’s significant accounting policies are consistent with those of the Group. For the purposes of these condensed financial statements, the Company’s wholly owned and majority owned subsidiaries are recorded based upon its proportionate share of the subsidiaries net assets. Immaterial corrections to prior periods During the year ended December 31, 2015, a correction necessary to certain subsidiary’s depreciation and amortization expenses that originated in prior periods was identified. AVANGRID assessed the materiality and determined that the cumulative impact of the amount was not material to the results of operation, financial position or cash flows in the previously issued financial statements and therefore, amendments of previously filed condensed financial information of AVANGRID are not required. However, management has determined to revise the prior periods included within these financial statements to reflect these updated amounts. Accordingly, the correction of these prior period amounts has been reflected in the periods in which they originated and the statement of operations for the year ended December 31, 2013 and the balance sheet as of December 31, 2014 have been revised. The correction resulted in a $14 million increase in equity earnings and net income and a $21 million increase in retained earnings and investments in subsidiaries, respectively, in the statement of operations for the year ended December 31, 2013 and balance sheet as of December 31, 2014. The revision had no net impact on the net cash provided by operating activities for the year ended December 31, 2013.

Summary of Significant Accounti

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates	12 Months Ended
	Dec. 31, 2015
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 combined and consolidated financial statements: (a) Principles of consolidation and combination 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 combined and consolidated statements of operations 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. (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 combined and consolidated statements of operations 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 combined and consolidated statements of operations 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 30-35 Hydroelectric power stations 40-90 Plant Wind power stations 25 Gas storage 17-119 Transport facilities 33-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 17-41 Computer software 3-10 Other Buildings 9-75 Operations offices 5-32 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 combined and 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 recognized at fair value 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 amounts related to AROs are included as other non-current assets in 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 company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as 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 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. (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. (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 sheet within “Materials and supplies.” Inventory items are combined for the cash flow statement 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 combined and consolidated statements of operations 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 to 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, and to depreciate the capitalized cost over the useful life of the related asset. 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 2048. (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, RGE 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. O (v) Income tax For the 2015 tax year, AVANGRID will file a consolidated federal income tax return, which will include the UIL taxable income or loss for the period from December 17, 2015 to December 31, 2015. UIL will file 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 most recently 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. In addition, a consolidated federal income tax return, that included the taxable income or loss of ARHI and all of its subsidiaries for the entire 2013 tax year and the taxable income or loss of AVANGRID (without UIL) and all of its subsidiaries for the tax period of November 21, 2013 through December 31, 2013, was filed. For the period of January 1, 2013 through November 20, 2013, AVANGRID (excluding ARHI and UIL) filed a consolidated federal income tax return that included the taxable income or loss of all its subsidiaries, which are 80% or more owned. 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, 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. 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 combined and 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 combined and consolidated statements of operations. 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 combined and consolidated statements of operations. 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. We account for stock-based payment transactions based on the estimated fair value of awards, net of estimated forfeitures at the date of issuance. 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 for certain share-based awards until the employee becomes retirement eligible, if earlier. The total stock-based compensation expense, which is included in operations and maintenance of the combined and consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 was $6.0 million, $4.8 million and $7.6 million, respectively. The total liability relating to stock-based compensation, which is included in other non-current liabilities, was $17.5 million and $16.8 million as of December 31, 2015 and 2014. The Company’s historical stock-based expense and liabilities are based on shares of its parent, Iberdrola S.A, and not on shares of the Company. The Company has total unrecognized costs for stock-based compensation of approximately $1.0 million as of December 31, 2015. As of December 31, 2015 the Company maintained unvested performance shares that may be settled through the issuance of additional Company shares in future periods upon the achievement of certain conditions. Reclassifications Certain amounts have been reclassified in the consolidated balance sheet and combined and consolidated statements of operations to conform to the 2015 presentation. Amounts pertaining to sales and use tax of $8 million and $11 million for the years ended December 31, 2014 and 2013, respectively, have been reclassified from “Taxes other than income taxes” to “Operations and maintenance” in the combined and consolidated statements of operations. Additionally, current and non-current liabilities amounting to $12 million and $23 million, pertaining to the Rate refund – FERC ROE proceeding have been reclassified from “Other current liability” and “Other non-current liability” to current and non-current regulatory liabilities in the consolidated balance sheet as of December 31, 2014. New Accounting Standards and Interpretations (a) Simplifying the presentation of debt issuance costs The Financial Accounting Standards Board (FASB) issued an amendment in April 2015 that is intended to simplify the presentation of debt issuance costs. Instead of presenting debt issuance costs as a deferred charge (that is, as an asset), the amendments require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation for debt discounts. The amendment is effective for public entities for financial statements issued for fiscal years beginning after December 15, 2015, and for interim periods within those fiscal years. As permitted, we have early

Acquisition of UIL

Acquisition of UIL	12 Months Ended
	Dec. 31, 2015
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 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 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) after applying 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 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 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 combined and consolidated statements of operations. The following unaudited pro forma 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, (millions) 2015 2014 Revenue $ 5,958 $ 6,226 Net income $ 468 $ 539 The revenue and net (loss) of UIL since the acquisition date included in the combined and consolidated statements of operations for the year ended December 31, 2015 were $36 million and $(36) million, respectively (see Merger Settlement Agreement below for further details). The fair value of assets acquired and liabilities assumed from our acquisition of UIL was based on a preliminary valuation and our estimates and assumptions are subject to change within the measurement period. 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. The primary areas of the purchase price that are not yet finalized include, but are not limited to contracts, equity method investments, provisions, contingent liabilities related to certain environmental sites, income taxes and goodwill. We will finalize these amounts no later than December 16, 2016. Under U.S. GAAP, the measurement period shall not exceed one year from the acquisition date. Measurement period adjustments that we determine to be material will be recognized in future periods in our consolidated financial statements. The following is a summary of the preliminary allocation of the purchase price as of the acquisition date: (millions) Current assets, including cash of $48 million $ 500 Other investments 114 Property, plant and equipment, net 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 estimated consideration $ 2,873 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. As part of the preliminary allocation of the purchase price we have determined a fair value of contingent liabilities of approximately $44.0 million relating to certain environmental sites. 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. In connection with the acquisition proceeding, UI signed a proposed partial consent order, or consent order that, when approved by the Commissioner of DEEP, and pursuant to the terms and conditions in the consent order, would require 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, upon its issuance and subject to its terms and conditions, UI would be 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). 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 Berkshire 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. · Berkshire will contribute $1 million to alternative heating programs. · Berkshire 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, 2015
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. The FERC currently provides a base ROE of 10.57% and additional ROE incentive adders applicable to assets based upon vintage, voltage and other factors. 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 Federal Power Act (FPA), the FERC finds 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. The FERC also found that the current Regional Network Service (RNS) and Local Network Service (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 RGE 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 RGE effective from August 26, 2010 through December 31, 2013. The rate plans contain continuation provisions beyond 2013 if NYSEG and RGE do not request new rates to go into effect and the current base rates will stay in place. The revenue requirements were based on a ten-percent allowed ROE applied to an equity ratio of forty-eight-percent. 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 RGE 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 RGE 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, RGE 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 RGE will 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 RGE filed electric and gas rate cases with the NYPSC. The companies requested rate increases for NYSEG electric, NYSEG gas and RGE gas. RGE electric proposed a rate decrease. On February 19, 2016, NYSEG, RGE 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 RGE commencing May 1, 2016. The Proposal balances 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 attributes including: acceleration of the companies’ natural gas leak prone main replacement programs and enhanced 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 % RGE Electric 3.0 0.70 % 21.6 5.00 % 25.9 5.70 % RGE 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, RGE Electric and RGE 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 earnings levels, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% of ROE, respectively, in the first year. Earnings thresholds would increase in subsequent years. The Proposal reflects the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million will be amortized over ten years and the remaining $139 million will be 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 RGE 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 RGE’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 and the customer average interruption duration index. 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 RGE’s bill reduction and arrears forgiveness Low Income Programs at the 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 rollout of Distribution Automation and Advanced Metering Infrastructure (AMI) to customers on circuits in the Ithaca region. The Companies will also pursue Non-Wires Alternative projects as described in the Proposal. 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 a 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 RGE continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis. The Administrative Law Judges assigned to the New York rate case will issue a procedural schedule establishing the remaining procedure for review and decision on the Proposal. We expect hearings on the Proposal to be held in April 2016 and a NYPSC decision to be made in May 2016. 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 2016, 80% of its standard service load for the second half of 2016 and for 30% of its standard service load for the first half of 2017. 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 August 2013, PURA approved new distribution rate schedules for UI for two years which became effective at that time and which, among other things, increased the UI distribution and CTA allowed ROE from 8.75% to 9.15%, 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 establishment of the requested storm reserve. In accordance with the approval by PURA of the acquisition, UI agreed not to initiate a rate case for new rates effective before at least January 1, 2017. 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. Berkshire’s rates are established by the DPU. Berkshire’s 10-year rate plan, which was approved by the DPU and included an approved ROE of 10.5%, expired on January 31, 2012. Berkshire 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, Berkshire 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 proposes 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 RGE are participating in the initiative with other New York utilities and are providing their unique perspective. NYPSC staff is currently conducting public statement hearings regarding REV across New York state. The NYPSC has issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform (DSP) provider, and requires the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016. The DSIP will also include information regarding the potential deployment of Automated Metering Infrastructure (AMI). 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 Fund, Demand Response Tariffs, and Community Choice Aggregation. 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. We expect an Order by the end of the second quarter of 2016. 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. On July 11, 2014, GNPP filed a petition requesting that the NYPSC initiate a proceeding to examine a proposal for the continued operation of the Ginna Facility. Ginna asserted that “in the two preceding calendar years, 2012 and 2013, it had sustained cumulative losses at the Facility of nearly $100 million (including the allocation of CENG corporate overhead)” and that “CENG has not been compensated for any operational risk or an appropriate return on its investment over this period.” Based on the results of the 2014 Reliability Study, GNPP requested that: 1) the NYPSC determine that the continued operation of the Ginna Facility is required to preserve system reliability; and 2) the NYPSC issue an Order directing RGE to negotiate and file a Reliability Support Services Agreement (RSSA) 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 an RSSA.” As such, the NYPSC ordered RGE and GNPP to negotiate an RSSA. On February 13, 2015, RGE submitted to the NYPSC an executed RSSA between RGE and GNPP. RGE requested that the NYPSC accept the RSSA and approve cost recovery by RGE from its customers of all amounts payable to GNPP under the RSSA utilizing the cost recovery surcharge mechanism. On October 21, 2015, RGE, 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. RGE shall make monthly payments to Ginna in the amount of $15.4 million. RGE 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 RGE to implement a rate surcharge effective January 1, 2016 to recover amounts paid to Ginna pursuant to the RSSA. RGE's payment obligation to Ginna shall not begin until the rate surcharge is in effect and FERC has issued an order authorizing the FERC Settlement agreement in the Settlement Docket. RGE 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 RGE to Ginna then the RSSA surcharge may continue past March 31, 2017 to recover up to $2.3 million per month until the final payment has been recovered by RGE from ratepayers. In the month following the expiration of the term on March 31, 2017, Ginna shall prepare and issue an invoice to RGE for, and RGE shall pay to Ginna, a one-time payment in the amount of $11.5 million, which will be recovered from ratepayers. 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 Affiliates of National Grid, Central Hudson, NYSEG, and RGE, together with an affiliate of Consolidated Edison and Orange and Rockland Utilities, are part of a new organization, New York Transco. New York Transco is focused on developing electric transmission to meet future electricity needs of all New Yorkers and will develop New York transmission projects upon receipt of all necessary regulatory approvals. New York Transco members (Applicants) are requesting regulatory approval for a group of transmission projects expected to cost $1.7 billion, funded through debt and equity. NYSEG and RGE allocated twenty-percent equity contribution amounts to approximately $183 million over the period 2015 through 2018. Additional projects may be developed in the future. Equity investments will be expressly contingent on receiving necessary regulatory approvals and acceptable economic returns. The investment will be made through a Networks affiliate, Networks New York Transco, LLC, formed on November 3, 2014. New York Transco filed with FERC in early December 2014. The filing requests a formula base ROE of 10.6%, plus one-hundred fifty basis points ROE incentives. The filing also requests recognition of construction work in process, abandoned plant, regulatory asset for pre-commercial costs, and sixty-percent equity for five years. Various parties, including the NYPSC, have protested the filing with FERC. On April 2, 2015, the FERC issued an order granting, inter alia, Applicants’ request for a 50 basis point adder for NY 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 the Applicants’ 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, Applicants, 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. Minimum Equity Requirements for Regulated Subsidiaries Our regulated utility subsidiaries (NYSEG, RGE, CMP and Maine Natural Gas) of Maine and New York are each subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. 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. Movement of capital from our wholly owned unregulated subsidiaries is unrestricted. 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 dividend 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. 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 9.15%) plus 25 basis points and (B) the current authorized distribution ROE for 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. New England East-West Solution Pursuant to an agreement with The Connecticut Light and Power Company, or CL&P (the Agreement), UI has the right to invest in, and own transmission assets associated with, the Connecticut portion of CL&P’s New England East West Solution (NEEWS) projects to improve regional energy reliability. NEEWS originally consisted of four inter-related transmission projects being developed by subsidiaries of Northeast Utilities (doing business as Eversource Energy), the parent company of CL&P, in collaboration with National Grid USA. Three of the original projects have portions located in Connecticut: (1) the Greater Springfield Reliability Project (GSRP), which was fully energized in November 2013, (2) the Interstate Reliability Project (IRP), which was placed in service in the fourth quarter 2015 and (3) the Central Connecticut Reliability Project, the need for which is now planned to be addressed by CL&P’s Greater Hartford Central Connecticut solutions, in which UI does not anticipate making any investments. Under the Agreement, as of December 31, 2015, UI had made aggregate deposits of approximately $45 million since its inception, with assets valued at approximately $44.6 million having been transferred to UI. UI does not anticipate making any additional investments in NEEWS under the agreement. 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, 2015 through December 31, 2015 of $29.5 million and $36.5 million for GenConn Devon and GenConn Middletown, respectively. In addition, PURA has ruled that GenConn project costs incurred that were in excess of the proposed costs originally submitted in 2008 were p

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2015
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 rate base or are accruing a carrying cost until they will be included in rate base. The primary items that are not included in 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, asset retirement obligations, hedge losses and contracts for differences. The total amount of these items is $2,825 million. 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. Most of the items related to NYSEG for which the amortization period has been characterized as to be determined in a future proceeding have been addressed in the Proposal. If the Proposal is approved, most of these items would be amortized over a five year period, except the portion of storm costs to be recovered over ten years and plant related tax items which will be amortized over the life of associated plant. Annual amortization expense for NYSEG would be approximately $16.5 million per rate year. The RGE items that would begin being amortized are plant related tax items. A majority of the other items related to RGE, which net to a regulatory liability, will not be amortized until future proceedings or will be used to recover costs of the Ginna RSSA agreement. Current and non-current regulatory assets as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Current Pension and other postretirement benefits cost deferrals $ 8 $ — Pension and other postretirement benefits 13 — Storm costs 8 14 Temporary supplemental assessment surcharge 7 12 Hedges losses 37 34 Contracts for differences 18 — Hardship programs 13 — Deferred purchased gas 12 — Deferred transmission expense 12 — Environmental remediation costs 37 — Other 54 20 Total Current Regulatory Assets 219 80 Non-current Pension and other postretirement benefits cost deferrals 151 125 Pension and other postretirement benefits 1,509 1,101 Storm costs 251 259 Deferred meter replacement costs 34 36 Unamortized losses on reacquired debt 23 25 Environmental remediation costs 271 247 Unfunded future income taxes 549 366 Asset retirement obligation 24 32 Deferred property tax 45 30 Federal tax depreciation normalization adjustment 158 128 Merger capital expense target customer credit 15 10 Debt premium 141 — Contracts for differences 50 — Hardship programs 29 14 Other 64 26 Total Non-current Regulatory Assets $ 3,314 $ 2,399 “Pension and other postretirement benefits” represent the actuarial losses on the pension and other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG, and RGE 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. Since the approval of the 2010 rate plan in New York, NYSEG has experienced unusually high levels of restoration costs resulting from various storms including Hurricane Sandy, Hurricane Irene, and Tropical Storm Lee. NYSEG’s deferred storm costs, reflecting the over (under) spending of actual costs compared with amounts currently allowed in rates, was $(9) million and $5 million for the years ended December 31, 2015 and 2014, respectively. NYSEG’s total deferral, including carrying costs, was $247 million and $241 million as of December 31, 2015 and 2014, respectively. The amortization will be determined in a future NYPSC proceeding. CMP’s deferred service restoration costs, primarily as a result of an ice storm in late December 2014, reflecting over (under) spending of actual costs compared with amounts allowed in rates, was $(6) million and $15 million for the years ended December 31, 2015 and 2014, respectively. CMP’s total deferral, including carrying costs, was $12 million and $32 million as of December 31, 2015 and 2014, respectively. Recovery of CMP’s deferred storm costs in the amount of $28 million began with the effective date of its last rate case and occurs over a twenty-four month period. Recovery of incremental deferrals will be determined in a future proceeding. “Deferred meter replacement costs” represent the deferral of the value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized at the related existing depreciation amounts. “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. 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. “Asset retirement obligation” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred property taxes” represent the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amortization period is awaiting a future NYPSC rate proceeding. “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 will be determined in future NYPSC and 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. “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, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Current Reliability support services (Cayuga) $ 16 $ 18 Plant decommissioning — 13 Non by-passable charges 7 19 Energy efficiency portfolio standard 33 34 Gas supply charge and deferred natural gas cost 6 6 Transmission revenue reconciliation mechanism 16 23 Yankee DOE Phase I 5 23 Merger related rate credits 20 — Revenue decoupling mechanism 14 8 Other 30 21 Total Current Regulatory Liabilities 147 165 Non-current Accrued removal obligations 1,084 721 Asset sale gain account 8 19 Carrying costs on deferred income tax bonus depreciation 116 81 Economic development 36 33 Merger capital expense target customer credit account 17 17 Pension and other postretirement benefits 90 50 Positive benefit adjustment 51 51 New York state tax rate change 17 16 Post term amortization 25 20 Theoretical reserve flow thru impact 31 24 Deferred property tax 15 51 Net plant reconciliation 10 10 Variable rate debt 32 25 Carrying costs on deferred income tax - Mixed Services 263(a) 31 20 Rate refund – FERC ROE proceeding 21 23 Merger related rate credits 24 — Accumulated deferred investment tax credits 10 — Asset retirement obligation 13 — Middletown/Norwalk local transmission network service collections 19 — Excess generation service charge 21 — Low income programs 42 10 Unfunded future income taxes 27 — Non-firm margin sharing credits 8 — Deferred income taxes regulatory 519 433 Other 93 58 Total Non-current Regulatory Liabilities $ 2,360 $ 1,662 “Reliability support services (Cayuga)” represent 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 fixed 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 awaiting a future NYPSC rate proceeding. “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 awaiting a future NYPSC rate proceeding. “Economic development” represents the economic development program which enables NYSEG and RGE 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 RGE varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is awaiting a future NYPSC rate proceeding. “Merger capital expense target customer credit” account was created as a result of NYSEG and RGE not meeting certain capital expenditure requirements established in the order approving the purchase of Energy East by Iberdrola. The amortization period is awaiting a future NYPSC rate proceeding. “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. It also represents 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 acquisitions of Energy East. This is being used to moderate increases in rates. The amortization period is awaiting a future NYPSC rate proceeding. “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 awaiting a future NYPSC rate proceeding. “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is awaiting a future NYPSC rate proceeding. “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 awaiting a future NYPSC rate proceeding. “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. “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. 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, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 7. Goodwill and Intangible assets Goodwill by reportable segment as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Networks $ 2,733 $ 979 Renewables 380 380 Gas — — Other (a) 2 2 Total $ 3,115 $ 1,361 (a) Does not represent a reportable segment. It mainly includes Corporate and company eliminations. As of December 31, 2015 and 2014, the gross amounts of goodwill were $2,733 million for Networks reportable segment, $3,340 million for Renewables and Gas reportable segments and $2 million for Corporation (which does not represent a segment), 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 $1,754 million due to acquisition of UIL (See Note 4 – Acquisition of UIL – for further details). Goodwill Impairment Assessment For impairment testing purposes our reporting units are the same as operating segments, except for Networks, which contained two reporting units, Maine and New York as of December 31, 2014 and three reporting units, Maine, New York and UIL as of December 31, 2015. 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 RGE 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 $1,754 million. 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. In 2015 the impairment testing of goodwill for Networks includes Maine and New York reporting units. 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. None of these factors had changed significantly since 2014. Renewables Based on the results of our step 1 impairment test for the Renewables reporting unit conducted in 2015, its estimated fair value exceeds carrying value by approximately 1.55%. 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. 2014 We had no impairment of goodwill in 2014 as a result of our impairment testing. Networks Based on the results of our step 1 impairment test conducted in 2014, the estimated fair value of each of the Networks reporting units was substantially in excess of their respective carrying value. Renewables Based on the results of our step 1 impairment test for the Renewables reporting unit conducted in 2014, its estimated fair value exceeds carrying value by approximately 1%. 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. 2013 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 2013 considering the substantial excess of fair value over the carrying value that was demonstrated in the 2011 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. None of these factors had changed significantly since 2011. Renewables Based on the results of our step 1 impairment test for the Renewables reporting unit conducted in 2013, the estimated fair value exceeded the carrying value by approximately 11%. Gas Based on the results of our step 1 impairment test the Gas reporting unit fair value analysis resulted in an implied fair value of goodwill of $0 for this reporting unit, and consequently, a non-cash impairment charge in the amount of $163 million was recorded for the year ended December 31, 2013. The inputs used to determine the fair value of the Gas reporting unit were based on forecasted cash flows, which are classified as Level 3 in the fair value hierarchy. The main reason for the impairment was the projected long-term low margins for natural gas given the impact of shale gas in the North American energy market. We elected to suspend the gas storage facility construction projects of this reporting unit until this scenario substantially changes. 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, 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 As of December 31, 2014 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 325 $ (117 ) $ 208 Wind development 574 (220 ) 354 Other 56 (49 ) 7 Total Intangible Assets $ 955 $ (386 ) $ 569 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, 2015, 2014 and 2013 amounted to $54 million, $66 million and $72 million, respectively. We do not believe our future cash flows will impact the recoverability of our intangible assets. We expect amortization expense for the five years subsequent to December 31, 2015, to be as follows: Year ending December 31, (Millions) 2016 $ 27 2017 25 2018 24 2019 26 2020 25 As a result of writing off of fully amortized intangibles assets relating to Gas Storage rights, $6.5 million was removed from both cost and accumulated amortization during 2015. Wind development costs written off totaled $42 million in 2013. These charges were included in Impairment of non-current assets in the combined and consolidated statements of operations.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2015
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	Note 8. Property, Plant and Equipment 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. Property, plant and equipment as of December 31, 2014 consisted of: As of December 31, 2014 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 8,625 $ 9,798 $ 18,423 Natural gas transportation, distribution and other 1,723 648 2,371 Other common operating property 654 51 705 Total Property, Plant and Equipment in Service (a) 11,002 10,497 21,499 Total accumulated depreciation (b) (3,491 ) (2,271 ) (5,762 ) Total Net Property, Plant and Equipment in Service 7,511 8,226 15,737 Construction work in progress 878 518 1,396 Total Property, Plant and Equipment $ 8,389 $ 8,744 $ 17,133 ( a ) Includes capitalized leases of $158 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $47 million. Capitalized interest costs were $13 million, $12 million, and $9 million for the years ended December 31, 2015, 2014 and 2013, respectively. In view of the projected long-term low margins for natural gas as a result of the impact of shale gas in the North American energy market, in 2013 we abandoned the gas storage facility construction projects assigned to the gas reporting unit. Consequently, we impaired or wrote off certain gas storage projects and other facilities under construction for an amount of $382 million, included in “Impairment of non-current assets” in the combined and consolidated statements of operations for the year ended December 31, 2013. We also impaired or wrote off amounts of $12 million, $24 million, and $33 million for the years ended December 31, 2015, 2014 and 2013 respectively, resulting from reassessment of the economic feasibility of its various Renewables development projects in construction. Depreciation expense for the years ended December 31, 2015, 2014 and 2013 amounted to $641 million, $563 million and $522 million, respectively.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 consisted of: (Millions) As of December 31, 2013 $ 209 Liabilities settled during the year (1 ) Liabilities incurred during the year 6 Accretion expense 14 Revisions in estimated cash flows 6 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 Several of the wind generation facilities have restricted cash for purposes of settling AROs. Restricted cash related to AROs was $1.8 million and $1.7 million as of December 31, 2015 and 2014, 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 combined and consolidated statements of operations. 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. In 2015 we revised our model used to estimate the future undiscounted costs for removal of our wind and solar facilities, based upon a study performed by an independent engineering firm that specializes in such matters. This revision resulted in a lower estimate of future removal costs, which we estimate will result in a $5 million annual reduction in expense going forward.

Debt

Debt	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Debt	Note 10. Debt Long- term debt as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2016-2045 $ 1,815 3.07%-10.60% $ 1,405 3.07%-8.00% Unsecured pollution control notes - fixed 2020 200 2.00%-2.375% 132 2.125%-2.25% Unsecured pollution control notes – variable 2032-2034 219 0.195%-1.181% 159 0.03%-0.461% Other various non-current debt - fixed 2016-2045 2,440 2.89%-10.48% 889 3.24%-10.48% Total Debt $ 4,674 $ 2,585 Obligations under capital leases 2020-2023 87 4%-4.44% 81 4%-4.44% Unamortized debt (costs) premium, net (25 ) (29 ) Less: debt due within one year, included in current liabilities 206 148 Total Non-current Debt $ 4,530 $ 2,489 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s properties of approximately $5,682 million. In January 2015, CMP issued $150 million of first mortgage bonds in three tranches: $65 million maturing in 2025 bearing a coupon of 3.15%, $20 million maturing in 2030 bearing a coupon of 3.37%, and $65 million maturing in 2045 bearing a coupon of 4.07%. In April 2015, NYSEG issued $200 million of fixed rate pollution control notes in four separate series. The notes have mandatory redemption dates in 2020. $99 million of the notes bear an interest rate of 2.375% and $101 million bear an interest rate of 2.00%. Non-current debt, including sinking fund obligations and capital lease payments, due over the next five years consists of: (Millions) 2016 2017 2018 2019 2020 Total $ 206 $ 302 $ 162 $ 354 $ 721 $ 1,745 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, 2015 and 2014. Fair Value of Debt The estimated fair value of debt amounted to $4,985 million and $2,962 million as of December 31, 2015 and 2014, 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 $204 million and $145 million, respectively, as of December 31, 2015 and 2014, 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 (a) AVANGRID Revolving credit facility In May 2012, we entered into a $300 million revolving credit facility for the purpose of providing for our liquidity needs and those of our unregulated subsidiaries. The facility has a termination date in May 2019. We pay an annual facility fee of $0.7 million. As of December 31, 2015 and December 31, 2014 the facility was undrawn. The revolving credit facility contains a covenant that requires us to maintain a ratio of consolidated indebtedness to consolidated total capitalization that does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated total capitalization, the facility excludes from consolidated net worth the balance of accumulated other comprehensive income (AOCI) as it appears on the consolidated balance sheets. (b) Iberdrola Financiación, S.A. credit facility In August 2011, we entered into a revolving credit facility with Iberdrola Financiación, S.A., a subsidiary of Iberdrola, under which we could borrow up to $600 million. The facility was terminated by AVANGRID on October 28, 2015. The facility was never utilized. (c) Joint utility revolving credit facility In July 2011, NYSEG, RGE and CMP jointly entered into a bank provided revolving credit facility (Joint Utility Facility) that allows maximum aggregate borrowings of up to $600 million and expires in July 2018. Each subsidiary is currently subject to a $200 million credit limit. Each borrower pays a facility fee ranging from fifteen to twenty basis points annually depending on the rating of its unsecured debt. CMP and NYSEG have established commercial paper programs backstopped by the Joint Utility Facility. These companies use commercial paper as an alternative to revolving credit facilities as a source of short-term credit. In the Joint Utility Facility each joint borrower covenants not to permit, without the lender’s consent, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 at any time. For purposes of calculating the maximum ratio of consolidated indebtedness to total capitalization, the facility excludes from consolidated net worth the balance of AOCI as it appears on the consolidated balance sheets. As of December 31, 2015 and December 31, 2014 there were no outstanding loans, no outstanding commercial paper and $14 million of outstanding letters of credit at both dates. (d) UIL credit facility In November 2011 UIL, UI, CNG, SCG, and Berkshire became parties to a revolving credit agreement that will expire on November 30, 2016 (the UIL Credit Facility). The aggregate borrowing limit under the UIL Credit Facility is $400 million, all of which is available to UIL, $250 million of which is available to UI, $150 million of which is available to each of CNG and SCG, and $25 million of which is available to Berkshire, all subject to the aggregate limit of $400 million. UIL pays a facility fee of twenty basis points annually. The UIL Credit Facility contains a covenant that requires each borrower to maintain a ratio of consolidated indebtedness to consolidated total capitalization that does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated total capitalization, the facility excludes from consolidated net worth unrealized gains and losses reflected in other comprehensive income in respect of qualified and non-qualified defined benefit pension plans, as well as other post-retirement benefit plans of such borrower. As of December 31, 2015 there were $163 million in outstanding loans bearing interest rate of 1.57%, and there was $4 million in outstanding letters of credit.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2015
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 noncurrent 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 RGE 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). RGE hedges all its electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value RGE’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 RGE 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, RGE 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 financial instruments measured at fair value as of December 31, 2015 and 2014 consisted of: 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 (CfDs) — — 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 (CfDs) — — (96 ) — (96 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (236 ) $ (52 ) $ (164 ) $ 267 $ (185 ) As of December 31, 2014 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 33 $ — $ — $ — $ 33 Derivative assets Derivative financial instruments - power 11 83 48 (53 ) 89 Derivative financial instruments - gas 18 638 61 (579 ) 138 Total 29 721 109 (632 ) $ 227 Derivative liabilities Derivative financial instruments - power (40 ) (42 ) (7 ) 53 (36 ) Derivative financial instruments - gas (25 ) (614 ) (42 ) 579 (102 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (65 ) $ (656 ) $ (52 ) $ 632 $ (141 ) The reconciliations of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2015, 2014 and 2013 consisted of: (Millions) 2015 2014 2013 Fair value as of January 1, $ 57 $ 53 $ 5 Gains for the year recognized in operating revenues 33 11 21 Losses for the year recognized in operating revenues (8 ) (1 ) (3 ) Total gains or losses for the period recognized in operating revenues 25 10 18 Gains recognized in OCI 2 — — Losses recognized in OCI (3 ) (3 ) — Total gains or losses recognized in OCI (1 ) (3 ) — Purchases (73 ) 14 47 Settlements (14 ) (26 ) (15 ) Transfers out of Level 3 (a) (13 ) 9 (2 ) Fair value as of December 31, $ (19 ) $ 57 $ 53 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 $ 25 $ 10 $ 18 (a) Transfers out of Level 3 were the result of increased observability of market data. For assets and liabilities that are recognized in the combined and 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. They represent the variability in prices for those transactions that fall into the illiquid period (beyond 2 years), using past and current views of prices for those future periods. Variability 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) $ 4.56 $ 7.37 $ 1.76 with delivery exceeding two on a corroborated by SP15 ($/MWh) $ 46.82 $ 80.28 $ 19.75 period > two years discounted market data for Mid C ($/MWh) $ 37.93 $ 83.93 $ 6.75 years basis identical or Cinergy ($/MWh) $ 37.73 $ 77.49 $ 19.98 similar products Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2017. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are traded at liquid hubs in the West and Midwest and are used to hedge merchant wind production in those regions. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuations inputs and concluded that no material change to the financial statements is expected given the following: (i) any changes in the fair value of the gas swaps hedging inventory would be expected to be largely offset by changes in the value of the inventory; (ii) any changes in the fair value of the gas swaps hedging merchant generation would be expected to be significantly offset by changes in the value of future power generation. Future commodity prices are the significant unobservable inputs to fair value. Any significant increases in prices would result in a lower fair value of derivatives. Conversely, significant reductions in prices would result in a higher fair value of derivatives. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models themselves. Authorized trading points and associated forward price curves are maintained and documented by the Middle Office. Models used in valuation of the various products are developed and documented by the Structuring and Market Analysis group. Transaction models are valued in part on the basis of forward price, correlation, and volatility curves. Descriptions of these curves and their derivations are maintained and documented by the Structuring and Market Analysis group. Forward price curves used in valuing the models are applied to the full duration of transactional models to a maximum of approximately thirty years. 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 the December 31, 2015 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: Unobservable Input Range at December 31, 2015 Risk of non-performance 0.06% - 0.88% Discount rate 1.31% - 2.27% Forward pricing ($ per MW) $3.15 - $11.19

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 2015
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. (a) Networks activities NYSEG and RGE have a non by-passable wires charge adjustment that allows them to pass through any changes in 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 loss recognized in regulatory assets for electricity derivatives was $34.3 million and $28.8 million as of December 31, 2015 and 2014, respectively. The loss reclassified from regulatory assets into income, which is included in electricity purchased, was $46.9 million, $21.3 million, and $2.2 million for the years ended December 31, 2015, 2014 and 2013, respectively. NYSEG and RGE 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 RGE 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 loss recognized in regulatory assets for natural gas hedges was $3.1 million as of December 31, 2015. The loss recognized in regulatory assets for natural gas hedges was $4.7 million as of December 31, 2014. The loss reclassified from regulatory assets into income, which is included in natural gas purchased, was $6.3 million, $2.2 million, and $1.8 million for the years ended December 31, 2015, 2014 and 2013, respectively. Contracts for Differences (CfDs) Pursuant to Connecticut’s 2005 Energy Independence Act, the Connecticut Public Utilities Regulatory Authority (PURA) solicited bids to create new or incremental capacity resources in order to reduce federally mandated congestion charges, and selected four new capacity resources. To facilitate the transactions between the selected capacity resources and Connecticut electric customers, and provide the commitment necessary for owners of these resources to obtain necessary financing, PURA required that UI and The Connecticut Light and Power Company (CL&P) execute long-term contracts with the selected resources. In August 2007, PURA approved four CfDs, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. UI executed two of the contracts and CL&P executed the other two contracts. 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, 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 period from December 17, 2015 to December 31, 2015 were as follows: (Millions) Period from December 17, 2015 to December 31, 2015 Regulatory Assets - Derivative liabilities $ (1 ) Regulatory Liabilities - Derivative assets $ — The net notional volumes of the outstanding derivative instruments associated with Networks activities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Wholesale electricity purchase contracts (MWh) 6.7 6.6 Natural gas purchase contracts (Dth) 4.8 3.8 Fleet fuel purchase contracts (Gallons) 3.8 2.8 The location and amounts of derivatives designated as hedging instruments associated with Networks activities as of December 31, 2015 and 2014 consisted of: Asset Derivatives Liability Derivatives (Millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value As of December 31, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ — Non-current Other assets — Other liabilities — Natural gas derivatives: Current Current assets — Current liabilities — Non-current Other assets — Other liabilities — Fleet fuel contracts Current Current assets — Current liabilities (2 ) Non-current Other assets — Other liabilities (1 ) Total $ — $ (3 ) As of December 31, 2014 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ (20 ) Non-current Other assets — Other liabilities (9 ) Natural gas derivatives: Current Current assets — Current liabilities (4 ) Non-current Other assets — Other liabilities (1 ) Fleet fuel contracts Current assets — Current liabilities (3 ) Total $ — $ (37 ) The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2015, 2014 and 2013 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) 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 ) 2013 Interest rate contracts $ — Interest expense $ (11 ) Commodity contracts — Operating expenses (1 ) Total $ — $ (12 ) (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 combined and consolidated statements of operations. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $84.9 million, $93.5 million, and $102.5 million for the years ended December 31, 2015, 2014 and 2013, respectively. We recorded $8.6 million, $8.9 million, and $11.2 million in net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2015, 2014 and 2013, respectively. We will amortize approximately $8.1 million of discontinued cash flow hedges in 2016. The unrealized loss of $2.7 million on hedge derivatives is reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2015. We expect that those losses will be reclassified into earnings within the next twenty four months, the maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted energy transactions. The offsetting of derivative assets as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Assets Gross Amounts Not Offset in the Balance Sheet As of December 31, Amounts of Recognized Assets Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ 10 $ (10 ) $ — $ — $ — $ — 2014 Derivatives 11 (11 ) — — — — The offsetting of derivative liabilities as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Liabilities Gross Amounts Not Offset in the Balance Sheet As of December 31, Amounts of Recognized Liabilities Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ (49 ) $ 46 $ (3 ) $ — $ — $ (3 ) 2014 Derivatives (48 ) 11 (37 ) — 37 — (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. The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (MWh/Dth in Millions) Wholesale electricity purchase contracts 3 2 Wholesale electricity sales contracts 6 7 Foreign exchange forward purchase contracts 4 — Natural gas and other fuel purchase contracts 332 275 Financial power contracts 7 8 Basis swaps - purchases 67 160 Basis swaps - sales 80 161 The fair values of derivative contracts associated with Renewables and Gas activities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Wholesale electricity purchase contracts $ (13 ) $ (12 ) Wholesale electricity sales contracts 35 44 Foreign exchange forward purchase contracts (1 ) (3 ) Natural gas and other fuel purchase contracts 10 54 Financial power contracts 32 48 Basis swaps- purchases 1 (4 ) Basis swaps- sales (2 ) (4 ) Total $ 62 $ 123 The offsetting of derivative assets as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Assets Gross Amounts Offset in the Balance Sheet As of December 31, Amounts of Recognized Assets Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ 489 $ (341 ) $ 148 $ (36 ) $ (15 ) $ 97 2014 Derivatives 847 (620 ) 227 (66 ) (73 ) 88 The offsetting of derivative liabilities as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Liabilities Gross Amounts Not Offset in the Balance Sheet As of December 31, Amounts of Recognized Liabilities Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ (307 ) $ 221 $ (86 ) $ 36 $ 4 $ (46 ) 2014 Derivatives (724 ) 620 (104 ) 66 1 (37 ) The effect of trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Wholesale electricity purchase contracts $ 6 $ (9 ) $ 2 Wholesale electricity sales contracts (5 ) 9 (1 ) Financial power contracts — (2 ) (4 ) Financial and natural gas contracts (26 ) 125 (21 ) Total Gain (Loss) $ (25 ) $ 123 $ (24 ) Such gains and losses are included in revenue in the combined and consolidated statements of operations. The effect of non-trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Wholesale electricity purchase contracts $ (8 ) $ (8 ) $ 9 Wholesale electricity sales contracts (5 ) 15 (2 ) Financial power contracts 24 30 (19 ) Natural gas and other fuel purchase contracts 18 (1 ) 16 Total Gain (Loss) $ 29 $ 36 $ 4 Such gains and losses are included in revenue and “Purchased power, natural gas and fuel used” operating expenses in the combined and consolidated statements of operations, 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 location and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of December 31, 2015 consisted of: Asset Derivatives Liability Derivatives (Millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value As of December 31, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ 2 Current liabilities $ — Non-current Other assets 1 Other liabilities — Natural gas derivatives: Current Current assets 50 Current liabilities (9 ) Non-current Other assets 9 Other liabilities — Total $ 62 $ (9 ) Year Ended December 31, 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) 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(s) 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 $43.5 million of gains included in accumulated OCI at December 31, 2015 is expected to be reclassified into earnings within the next 12 months. During the year ended December 31, 2015 we recorded a net gain of $4.8 million in earnings as a result of ineffectiveness from cash flow hedges. We recorded $2.3 million in net derivative gain related to discontinued cash flow hedge for the year ended December 31, 2015. (c) Counterparty credit risk management NYSEG and RGE 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, 2015, UI would have had to post an aggregate of approximately $18 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 amount of cash collateral used to offset against net derivative positions was $84 million as of December 31, 2015. Under the master netting arrangements our obligation to return cash collateral was $0.1 million and $0.2 million as of December 31, 2015 and 2014, respectively. Derivate instruments settlements and collateral payments are included in “Other assets” and “Other liabilities” of operating activities in the combined and 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, 2015 is $39.7 million, for which we have posted collateral.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2015
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. MNG requested a 10.0% ROE and 50% equity ratio. The MPUC Staff has recommended a separate revenue requirement for MNG’s Augusta customers and MNG’s non-Augusta customers. Staff also recommended a $19.95 million disallowance of the August Expansion investment based upon the Staff’s conclusion that MNG’s management of the Augusta Expansion Project was imprudent. On November 6, 2015, a stipulation was filed with the MPUC, which was executed by MNG, the Office of Public Advocate and the City of Augusta. The stipulation contained a combined revenue requirement for Augusta and Non-Augusta based on a 9.55% ROE and 50% equity ratio. The stipulation also provided for an initial Augusta investment disallowance of $6 million and an investment phase-in of $10 million. On December 22, 2015, MPUC rejected the proposed Stipulation as not in the public interest. In January 2016, the Administrative Law Judge established a new litigation schedule. The litigation was suspended at the end of January 2016 for settlement discussions. We cannot predict the outcome of the proceeding. 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 a just and reasonable level of 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 initial decision in the first complaint, establishing a methodology and setting the issues for a paper hearing. On October 16, 2014, FERC issued its final decision in the first complaint (Complaint I) setting the base ROE at 10.57%, and a maximum total ROE of 11.74% for the October 2011 – December 2012 period 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 initial 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. We cannot predict the outcome of this appeal. On December 26, 2012, a second, related, complaint (Complaint II) for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On June 19, 2014, FERC accepted the second complaint, established a refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in the first complaint. On July 31, 2014, the Complainants filed a third, related, complaint (Complaint III) for a subsequent rate period requesting the ROE be reduced to 8.84%. On November 24, 2014, FERC accepted the third complaint, established a refund effective date of July 31, 2014, and set for consolidated hearing with Complaint II 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. 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 New England transmission owners 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 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 late 2016 or early 2017. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final Complaint I decision. The CMP and UI total reserve associated with Complaints I, II and III is $23.9 million and $4.2 million, respectively, as of December 31, 2015. If adopted as final, the impact of the initial decision would be an additional reserve for Complaints II and III of $10.2 million, net of tax, which is based upon currently available information for these proceedings. We cannot predict the outcome of Complaint II and III proceedings. Yankee Nuclear Spent Fuel Disposal Claim CMP has an ownership interest in Maine Yankee, Connecticut Yankee, and Yankee Atomic, (the Yankee Companies), three New England single-unit decommissioned nuclear reactor sites, and UI has and ownership in Connecticut Yankee. Every six years, pursuant to the statute of limitations, the Yankee companies need to 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 $40.3 million to Connecticut Yankee Atomic Power Company; affirmed the Court of Federal Claims award of $65 million to Maine Yankee Atomic Power Company; and increased Yankee Atomic Electric Company’s damages award from $21.4 million to $37.8 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 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 based on percentage ownership. We cannot predict the timing or amount of damage awards that may ultimately flow through to shareholders. NYPSC Staff Review of Earnings Sharing Calculations and Other Regulatory Deferrals In December 2012, the NYPSC Staff (Staff) informed NYSEG and RGE 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 RGE reviewed the Staff’s adjustments and work papers and provided a response in 2013. Staff has not yet replied to NYSEG’s and RGE’s response. NYSEG and RGE disagreed with certain staff conclusions and as a result have recorded a $3.4 million reserve in December 2012 in anticipation of settling the Staff issues. In the proposal filed with the NYPSC (see Note 5) the parties agreed that $2.4 million would be added to customer share of Earnings Sharing. Middletown/Norwalk Transmission Project The general contractor and two subcontractors responsible for civil construction work in connection with the installation of UI’s portion of the Middletown/Norwalk Transmission Project’s underground electric cable system filed lawsuits in Connecticut state court on September 22, 2009, March 23, 2009 and January 25, 2010, respectively. The claims, as revised by the general contractor in October 2011, sought payment for change order requests of approximately $33.3 million, a 10% general contractor mark-up on any approved subcontractor change order claims (approximately $2.3 million), interest, costs, and attorneys' fees. In December 2011, UI settled the claims brought by the two subcontractors and their respective lawsuits were dismissed, reducing UI’s estimate of the general contractor’s claims to approximately $7.7 million, exclusive of the contractor’s claims for interest, costs, and attorneys’ fees. UI also pursued an indemnification claim against the general contractor for the payments made in settlement to the two subcontractors. On September 3, 2013, the court found for UI on all claims but one related to certain change orders, and ordered UI to pay the Contractor approximately $1.3 million, which has since been paid. The court also found against UI on the indemnification claims. On October 22, 2013, the general contractor filed an appeal of the Court’s ruling. UI expects to recover any amounts paid to resolve the contractor and subcontractor claims through UI’s transmission revenue requirements. In April 2013, an affiliate of the general contractor for the Middletown/Norwalk Transmission Project, purporting to act as a shareholder on behalf of UIL Holdings, filed a complaint against the UIL Holdings Board of Directors alleging that the directors breached a fiduciary duty by failing to undertake an independent investigation in response to a letter from the affiliate asking for an investigation regarding alleged improper practices by UI in connection with the Middletown/Norwalk Transmission Project. In October 2013, the court granted the defendants’ motion to dismiss the complaint, which dismissal was affirmed by the Connecticut Appellate Court in March 2015. The period to file a petition for review by the Connecticut Supreme Court has passed and the case is now concluded. Leases Operating lease expense relating to operational facilities, office building leases, and vehicle and equipment leases was $47.7 million, $48.7 million and $67.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities was $22.2 million, $20.4 million and $20.6 million for the years ended December 31, 2015, 2014 and 2013, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses. In April 2013, we concluded a sale and subsequent lease-back transaction on one of our operating facilities for an initial cash receipt of $110 million. Under the terms of the agreement, we will simultaneously sell and then lease back the facility over a fifteen-year period, with an option to repurchase the facility at the end of year ten. During the lease period, we will continue to maintain and operate the entire facility. We accounted for this as a capital sale lease-back transaction, under which a lease payable liability is recognized which is offset by the increase in cash. On January 16, 2014, as required by its regulator, 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 $25.5 million and $19.8 million for the years ended December 31, 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, RGE, 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. RGE shall make monthly payments to GNPP in the amount of $15.4 million. RGE 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. Total future minimum lease payments as of December 31, 2015 consisted of: (Millions) Year Operating Leases(a) Capital Leases(a) Total 2016 $ 216 $ 9 $ 225 2017 90 6 96 2018 26 6 32 2019 24 6 30 2020 25 7 32 2021 and thereafter 298 53 351 Total $ 679 $ 87 $ 766 (a) Payments related to the period of remaining useful life of facilities are on an undiscounted basis. Power, Gas, and Other Arrangements Power and Gas Supply Arrangements – Networks NYSEG and RGE 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 RGE 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, RGE, SCG, CNG and Berkshire Gas Company (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 reasonable 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. 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 lease 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 (six 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. Power sales commitments include: (i) a 55MW Biomass off-take agreement for 12 years (six 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, 2015 consisted of: (Millions) Purchases Sales As of December 31, Gas Power Other Total Gas Power Other Total 2016 $ 232 $ 233 $ 31 $ 496 $ 21 $ 133 $ 3 $ 157 2017 203 123 25 351 3 84 2 89 2018 181 76 14 271 — 67 2 69 2019 149 54 8 211 — 48 1 49 2020 124 53 7 184 — 39 — 39 Thereafter 579 320 58 957 — 46 — 46 Totals $ 1,468 $ 859 $ 143 $ 2,470 $ 24 $ 417 $ 8 $ 449 Guarantee Commitments to Third Parties As of December 31, 2015, we had approximately $2.4 billion of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of the company and its subsidiaries in their normal course of business. The instruments only represent liabilities if the company 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, 2015, 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 $616 million as of December 31, 2015.

Environmental Liability

Environmental Liability	12 Months Ended
	Dec. 31, 2015
Environmental Remediation Obligations [Abstract]
Environmental Liability	Note 14. Environmental Liability Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Fifteen of the twenty-four 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-four 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-four sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $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. 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 of those two sites are a 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-seven of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from a minimum of $235 million to $468 million as of December 31, 2015. 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, 2015 the liability associated with other MGP sites, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $99 million. The liability to investigate and perform remediation at the known inactive gas manufacturing sites was $397 million and $312 million as of December 31, 2015 and 2014, 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 2048. The 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 Regulated Gas 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, 2015 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the Regulated Gas 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 Energy 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. 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. 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. Any recovery will be flowed through to NYSEG ratepayers. Century 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. 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. 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. 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 of 2015. On September 16, 2015, UI signed a Proposed Partial Consent Order that, when issued by the Commissioner of DEEP, and subject to the closing of the merger between UIL and AVANGRID and other terms and conditions in the Proposed Partial Consent Order, would require UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the Proposed Partial Consent Order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut, and the Commissioner of DEEP. Pursuant to the Proposed Partial Consent Order, upon its issuance and subject to its terms and conditions, UI would be obligated to comply with the Proposed Partial 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. On September 30, 2015, the Hearing Officer in DEEP’s administrative proceeding approved a Motion for Stay of further proceedings filed by DEEP, staying all proceedings on the administrative order for 120 days. On January 26, 2016 this Stay was extended for an additional 90 days. A status conference is scheduled for May 11, 2016.

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Income Taxes	Note 15. Income Taxes Current and deferred taxes charged to (benefit) expense for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Current Federal $ (20 ) $ (10 ) $ (22 ) State (33 ) 31 (1 ) Current taxes charged to (benefit) expense (53 ) 21 (23 ) Deferred Federal 136 218 60 State (6 ) 82 42 Deferred taxes charged to expense 130 300 102 Production tax credits (42 ) (37 ) (42 ) Investment tax credits (1 ) (2 ) (2 ) Total Income Tax Expense $ 34 $ 282 $ 35 The differences between tax expense per the statements of operations and tax expense at the 35% statutory federal tax rate for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Tax expense (benefit) at federal statutory rate $ 105 $ 247 $ (5 ) Depreciation and amortization not normalized 15 15 24 Investment tax credit amortization (1 ) (2 ) (2 ) Tax return related adjustments 6 2 7 Production tax credits (42 ) (37 ) (42 ) Tax equity financing arrangements (36 ) (11 ) (23 ) Change in tax reserves — 3 (2 ) Impairment of non-deductible goodwill — — 38 Changes in New York tax law — 41 — State tax expense (benefit), net of federal benefit (25 ) 32 27 Non-deductible acquisition costs 9 — — Other, net 3 (8 ) 13 Total Income Tax Expense $ 34 $ 282 $ 35 Deferred tax assets and liabilities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Non-current Deferred Income Tax Liabilities (Assets) Property related $ 4,763 $ 3,778 Unfunded future income taxes 211 146 Federal and state tax credits (367 ) (317 ) Accumulated deferred investment tax credits 15 16 Federal and state NOL’s (1,367 ) (1,266 ) Joint ventures/partnerships 655 884 Nontaxable grant revenue (595 ) (622 ) Other (17 ) 66 Non-current Deferred Income Tax Liabilities 3,298 2,685 Add: Valuation allowance 19 17 Total Non-current Deferred Income Tax Liabilities 3,317 2,702 Less amounts classified as regulatory liabilities Non-current deferred income taxes 519 433 Non-current Deferred Income Tax Liabilities $ 2,798 $ 2,269 Deferred tax assets $ 2,346 $ 2,205 Deferred tax liabilities 5,663 4,907 Net Accumulated Deferred Income Tax Liabilities $ 3,317 $ 2,702 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 or 2014. A valuation allowance of $8 million, (net of federal benefit) and an additional valuation allowance of $2 million (net of federal benefit) were established on various state NOLs and credits in 2014 and 2015, respectively. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2015, 2014 and 2013 consisted of: Years ended December 31, 2015 2014 2013 (Millions) Beginning Balance $ 38 $ 41 $ 91 Increases for tax positions related to prior years 1 20 4 Reduction for tax position related to settlements with taxing authorities (3 ) (23 ) (54) Ending Balance $ 36 $ 38 $ 41 Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the combined and 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, $3 million, and $11 million for the years ended December 31, 2015, 2014 and 2013, respectively. If recognized, $9 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, 2015 is estimated to be $9 million primarily relating to anticipation of additional guidance to be released by the IRS. 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. 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. As of December 31, 2015, 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, 2015, we had federal tax net operating losses of $3.5 billion, federal renewable energy credits, federal R&D tax credits and other federal credits of $338 million, state tax net operating losses of $154 million in several jurisdictions and miscellaneous state tax credits of $30 million available to carry forward and reduce future income tax liabilities. For state purposes, we recognized a valuation allowance of $19 million. The federal and state net operating losses begin to expire in 2025, while the federal tax credits begin to expire in 2024.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	12 Months Ended
	Dec. 31, 2015
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 substantially all Networks employees. The plans provide defined benefits based on years of service and final average salary for employees hired before 2002. Employees hired in 2002 or later 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. CMP’s unionized employees covered under the cash balance plans ceased to receive accruals as of December 31, 2014. NYSEG’s unionized employees covered under the cash balance plans ceased to receive accruals as of December 31, 2015. Their earned balances will continue to accrue interest but will no longer be increased by a percentage of earnings. Instead, they will receive a minimum contribution to their account under their respective company’s defined contribution plan. There was no change to the defined benefit plans for employees covered under the plans that provide defined benefits based on years of service and final average salary. Networks has other postretirement health care benefit plans covering substantially all Networks’ employees. The healthcare plans are contributory and participants contributions are adjusted annually. The UI pension plan covers the majority of employees of UIL and UI. UI also has a non‑qualified supplemental pension plan for certain employees and a non‑qualified retiree‑only pension plan for certain early retirement benefits. The Regulated Gas Companies have multiple qualified pension plans covering substantially all 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 substantially all of their employees. These benefits consist primarily of health care, prescription drug and life insurance benefits, for retired employees and their dependents. 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, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2015 2014 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 2,620 $ 2,316 $ 435 $ 385 Service cost 35 30 5 5 Interest cost 97 110 16 18 Plan participants’ contributions — — 4 4 Plan amendments — — (1 ) — Actuarial (gain) loss (105 ) 439 (31 ) 64 Special termination benefits 2 — — — Benefits paid (158 ) (275 ) (25 ) (41 ) Benefit Obligation as of December 31, 2,491 2,620 403 435 Change in plan assets Fair value of plan assets as of January 1, 2,143 2,223 129 128 Actual return on plan assets (21 ) 163 (4 ) 4 Employer contributions 27 32 21 38 Plan participants’ contributions — — 4 4 Benefits paid (158 ) (275 ) (25 ) (41 ) Withdrawal from VEBA — — (2 ) (4 ) Fair Value of Plan Assets as of December 31, 1,991 2,143 123 129 Funded Status as of December 31, $ (500 ) $ (477 ) $ (280 ) $ (306 ) Amounts recognized as of December 31, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2015 2014 (Millions) Non-current assets $ — $ — $ — $ — Current liabilities — — (5 ) (5 ) Non-current liabilities (500 ) (477 ) (275 ) (301 ) Total $ (500 ) $ (477 ) $ (280 ) $ (306 ) Networks offered terminated vested employees an option to receive their future pension benefit as a lump sum in 2013. Approximately $59.9 million of payments were made in 2013 as a result of terminated vested employees exercising the lump sum option. An additional $5.8 million was paid in 2014. The lump sum payments did not trigger settlement accounting. Networks made a similar offer during 2014 to retired employees who are currently receiving benefits. 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. The following table represents the change in benefit obligation, change in plan assets and the respective funded status of UIL’s pension and other postretirement plans as of December 31, 2015, including purchase price allocation balances. Plan assets and obligations have been measured as of December 31, 2015. Pension Benefits Other Postretirement Benefits (Millions) 2015 2015 Change in Benefit Obligation: Benefit obligation at December 17 $ 1,019 $ 122 Service cost 1 — Interest cost 2 — Benefits paid (including expenses) (4 ) — Benefit obligation at December 31 $ 1,018 $ 122 Change in Plan Assets: Fair value of plan assets at December 17 $ 687 $ 39 Actual return on plan assets (10 ) — Benefits paid (including expenses) (4 ) — Fair value of plan assets at December 31 $ 673 $ 39 Funded Status at December 31: Projected benefits less than plan assets $ (345 ) $ (83 ) Amounts Recognized in the Statement of Financial Position consist of: Non-current liabilities $ (345 ) $ (83 ) Amounts recognized in OCI, before income taxes, for ARHI for the years ended December 31, 2015, 2014 and 2013 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 (Millions) Net (income) loss $ 25 $ 22 $ 16 $ (1 ) $ 8 $ 14 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, 2015, 2014 and 2013 for Networks consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 (Millions) Net loss $ 982 $ 1,045 $ 704 $ 76 $ 96 $ 24 Prior service cost (credit) 9 12 16 (49 ) (57 ) (67 ) Amounts recognized as regulatory assets for the period from December 17, 2015 to December 31, 2015 for UIL consisted of: Pension Benefits Other Postretirement Benefits (Millions) 2015 2015 Net loss 12 — Our accumulated benefit obligation for all defined benefit pension plans of Networks and ARHI was $2,334 million and $2,436 million as of December 31, 2015 and 2014, respectively. CMP’s and NYSEG’s postretirement benefits were partially funded as of December 31, 2015 and 2014. 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, 2015 and 2014. 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, 2015 and 2014 consisted of: Projected Benefit Obligation Exceeds Fair Value of Plan Assets Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets As of December 31, 2015 2014 2015 2014 (Millions) Projected benefit obligation $ 2,491 $ 2,620 $ 2,491 $ 2,620 Accumulated benefit obligation 2,334 2,436 2,334 2,436 Fair value of plan assets 1,991 2,143 1,991 2,143 The aggregate projected and accumulated benefit obligations and the fair value of plan assets for underfunded plans of UIL as of December 31, 2015consisted of: Pension Benefits As of December 31, 2015 (Millions) Projected benefit obligation $ 1,018 Accumulated benefit obligation 927 Fair value of plan assets 673 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, 2015, 2014 and 2013 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2013 2015 2014 2013 Net Periodic Benefit Cost: Service cost $ 35 $ 30 $ 36 $ 4 $ 4 $ 5 Interest cost 95 107 102 15 17 16 Expected return on plan assets (154 ) (161 ) (166 ) (7 ) (7 ) (7 ) Amortization of prior service cost (benefit) 3 4 4 (9 ) (11 ) (14 ) Amortization of net loss 130 94 120 7 — 3 Special termination benefit charge 2 — — — — — Settlement charge 2 — — — — — Net Periodic Benefit Cost 113 74 96 10 3 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Settlements $ (2 ) $ — $ — $ — $ — $ — Net loss (gain) 69 434 (244 ) (12 ) 72 (50 ) Amortization of net (loss) (130 ) (94 ) (120 ) (7 ) — (3 ) Current year prior service cost — — — (1 ) — (2 ) Amortization of prior service (cost) benefit (3 ) (4 ) (4 ) 9 11 14 Total Other Changes (66 ) 336 (368 ) (11 ) 83 (41 ) Total Recognized $ 47 $ 410 $ (272 ) $ (1 ) $ 86 $ (38 ) Components of UIL’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets for the period from December 17, 2015 to December 31, 2015 consisted of: For the period from December 17, 2015 to December 31, 2015 Pension Benefits Other Postretirement Benefits (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ — Interest cost 2 — Expected return on plan assets (2 ) — Net periodic benefit cost $ 1 $ — Other Changes in Plan Assets and Benefit Obligations Recognized as a Regulatory Asset: Net (gain) loss $ — $ — Total Other Changes — — Total Recognized $ 1 $ — 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, 2015, 2014 and 2013 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2013 2015 2014 2013 Net Periodic Benefit Cost: Service cost $ — $ — $ — $ 1 $ 1 $ 1 Interest cost 2 2 2 1 1 1 Expected return on plan assets (2 ) (3 ) (3 ) — — — Amortization of prior service cost — — — — 1 1 Amortization of net loss 1 — 1 — 1 — Settlement charge — — 2 — — — Net Periodic Benefit Cost (income) 1 (1 ) 2 2 4 3 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) 4 6 (12 ) (8 ) (5 ) 7 Amortization of net (loss) (1 ) — (3 ) — (1 ) — Amortization of prior service (cost) — — — — (1 ) (1 ) Total Other Changes 3 6 (15 ) (8 ) (7 ) 6 Total Recognized $ 4 $ 5 $ (13 ) $ (6 ) $ (3 ) $ 9 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, 2016 consisted of: Year Ended December 31, 2016 Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 123 $ 7 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, 2016 consisted of: Year Ended December 31, 2016 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, 2016. The weighted-average assumptions used to determine benefit obligations for Networks and ARHI as of December 31, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2015 2014 Discount rate - Networks 4.10 % 3.80 % 4.10 % 3.80 % Discount rate - ARHI 3.90 % 3.90 % 3.90 % 3.90 % Rate of compensation increase - Networks 4.00 % 4.10 % — — The weighted-average assumptions used to determine benefit obligations for UIL as of December 31, 2015 consisted of: Pension Benefits Other Postretirement Benefits As of December 31, 2015 2015 Discount rate 4.24 % 4.24 % Average wage increase 3.50-3.80% — Health care trend rate (current year) — 7.00%/9.00% Health care trend rate (2019-2028 forward) — 4.50 % 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, 2015, 2014 and 2013 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 Discount rate - Networks 3.80 % 4.90 % 4.10 % 3.80 % 4.90 % 4.10 % Discount rate - ARHI 3.90 % 5.00 % 4.00 % 3.90 % 5.00 % 4.00 % Expected long-term return on plan assets - Networks 7.50 % 7.50 % 7.50 % — — — Expected long-term return on plan assets - ARHI 5.50 % 6.90 % 6.50 % 5.75 % 6.50 % 6.25 % Expected long-term return on plan assets - nontaxable trust - Networks — — — 7.50 % 7.50 % 7.50 % Expected long-term return on plan assets - taxable trust - Networks — — — 5.00 % 5.00 % 5.00 % Rate of compensation increase - Networks 4.10 % 4.20 % 4.00 % — — — The weighted-average assumptions used to determine net periodic benefit cost for UIL for the period from December 17, 2015 to December 31, 2015 consisted of: For the period from December 17, 2015 to December 31, 2015 Pension Benefits Other Postretirement Benefits Discount rate 4.24% 4.24% Average wage increase 3.50-3.80% — Return on plan assets 7.75-8.00% 5.56-8.00% Health care trend rate (current year) — 7.00% Health care trend rate (2019 forward) — 4.50% We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RGE 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, 2015 and 2014 consisted of: As of December 31, 2015 2014 Health care cost trend rate assumed for next year - Networks 7.50%/7.00% 7.75%/7.25% Health care cost trend rate assumed for next year - ARHI 7.00%/9.00% 7.75%/6.75% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.5 % 4.5 % Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.5 % 4.75 % Year that the rate reaches the ultimate trend rate - Networks 2027 2027 Year that the rate reaches the ultimate trend rate - ARHI 2026 2025 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 9 (7 ) Contributions We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. Networks and UIL expect to contribute $21 million and $22 million, respectively, to the pension benefit plans during 2016. 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, 2015 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2016 $ 154 $ 26 $ — 2017 156 27 — 2018 159 27 — 2019 161 27 — 2020 163 27 — 2021 - 2025 826 135 1 Expected benefit payments and Medicare Prescription Drug, Improvement and Modernization Act of 2003 subsidy receipts reflecting expected future service for UIL as of December 31, 2015 consisted of: (Millions) Pension Benefits Other Postretirement Benefits Medicare Act Subsidy Receipts 2016 $ 48 $ 7 $ — 2017 50 7 — 2018 51 7 — 2019 53 7 — 2020 54 7 — 2021-2025 295 37 1 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 $39 million and $43 million at December 31, 2015 and 2014, respectively. UI has established a supplemental retirement benefit trust and, through this trust, purchased life insurance policies on certain officers of UIL and UI to fund the future liability under the non-qualified supplemental plan. The total liability for these non-qualified plans, which is included in Other Non-current Liabilities, was $20 million as of December 31, 2015. Plan Assets Our pension benefits plan assets for Networks and ARHI are held in two 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 thirty-five-percent in equity securities and twenty-percent in equity alternative investments. The Liability-Hedging asset class has a target allocation percentage of forty-five-percent. 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. 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, 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 511 — 21 490 Partnerships/joint venture interests 84 — — 84 Real estate investments 89 — — 89 Other, principally annuity, fixed income 322 — 4 318 Total $ 1,991 $ 602 $ 408 $ 981 The fair values of pension benefits plan assets, by asset category, as of December 31, 2014 consisted of: As of December 31, 2014 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 48 $ 4 $ 44 $ — U.S. government securities 177 177 — — Common stocks 447 360 87 — Registered investment companies 116 116 — — Corporate bonds 367 23 344 — Preferred stocks 4 — 4 — Common collective trusts 477 — 28 449 Partnership/joint venture interests 79 — — 79 Real estate investments 77 2 — 75 Other, principally annuity, fixed income 351 5 4 342 Total $ 2,143 $ 687 $ 511 $ 945 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. Fair value measurements using Level 3 inputs as of December 31, 2015, 2014 and 2013 consisted of: (Millions) Common Collective Trusts Partnership Joint Venture Interests Real Estate Investments Other Investments Total As of December 31, 2013 $ 458 $ 57 $ 67 $ 337 $ 919 Actual return on plan assets: Relating to assets sold during the year 6 — — — 6 Relating to assets still held at the reporting date 5 3 6 5 19 Purchases, sales and settlements (20 ) 19 2 — 1 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 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 twenty-five-percent 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 forty-seven-percent equity securities, thirty-eight-percent fixed income, and fifteen-percent for all other investment types. The target allocations within allowable ranges are further diversified into twenty-percent large cap domestic equities, twelve-percent medium and small cap domestic equities, ten-percent international developed market, and five-percent emerging market equity securities. Fixed income investment targets and ranges are segregated into core fixed income at thirty-one-percent, global high yield fixed income at four-percent, and international developed market debt at three-percent. Other alternative investment targets are five-percent for real estate, five-percent for absolute return, and five-percent for tangible assets. 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, 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 11 11 — — Total $ 123 $ 121 $ 2 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2014 consisted of: As of December 31, 2014 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 45 45 — — Common stocks 29 29 — — Mutual funds, other 12 12 — — Total $ 128 $ 126 $ 2 $ — 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 December 31, 2015. The following tables set forth the fair values of UIL’s pension and other postretirement benefits plan assets as of December 31, 2015. Fair Value Measurements December 31, 2015 Level 1 Level 2 Level 3 Total (Millions) Pension assets Mutual funds $ — $ 673 $ — $ 673 Other postretirement benefit assets Mutual funds 32 7 — 39 Total $ 32 $ 680 $ — $ 712 The determination of fair values of the Level 2 co-mingled mutual funds were based on the Net Asset Value (NAV) provided by the managers of the underlying fund investments and the unrealized gains and losses. The NAV provided by the managers typically reflect the fair value of each underlying fund investment. 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 $17 million, $20 million and $14 million for 2015, 2014, and 2013 respectively. UIL has several 401(k) plans in which substantially all of its employees are eligible to participate. Employees may defer a portion of the compensation and invest in various investment alternatives. The matching expense for the period from December 17, 2015 to December 31, 2015, was immaterial.

Equity

Equity	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Equity	Note 17. Equity Our share capital consisted of 500,000,000 shares authorized, 309,491,082 shares issued and 308,864,609 shares outstanding, 81.5% owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,653 million as of December 31, 2015. Our share capital consisted of 500,000,000 shares authorized, 252,235,232 shares issued and 252,235,232 shares outstanding, wholly owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $11,375 million as of December 31, 2014. On December 15, 2015, the Board of Directors approved our common stock dividend, accounted for as 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’s approval. All share and per share information included in the combined and consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend. As a result, our share capital consisted of 500,000,000 shares authorized, 252,235,232 shares issued and 252,235,232 shares outstanding, wholly owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $11,375 million as of December 31, 2014. All common shares have the same voting and economic rights. We have 626,473 treasury shares and no convertible preferred shares as of December 31, 2015. We had no treasury shares or convertible preferred shares as of December 31, 2014. In February 2013 prior to the reorganization, in which ARHI became a subsidiary of AVANGRID, ARHI issued shares to Iberdrola in return for $153 million in cash, $550 million in the form of a loan note and the remaining $10 million in accrued interest on the loan note. The loan note was an obligation of AVANGRID and as a result of the reorganization in November 2013 the ARHI loan receivable and the AVANGRID loan payable have been eliminated in the combined and consolidated financial statements. Accumulated OCI (Loss) Accumulated OCI for the years ended December 31, 2015, 2014 and 2013 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2012 2013 Change As of December 31, 2013 2014 Change As of December 31, 2014 2015 Change As of December 31, 2015 (Millions) Loss on revaluation of defined benefit plans, net of income tax expense of $0.5 for 2013, $0.6 for 2014 and $2.2 for 2015 $ (27 ) $ 1 $ (26 ) $ 1 $ (25 ) $ 4 $ (21 ) Loss for nonqualified pension plans, net of income tax expense (benefit) of $1.0 for 2013, ($1.9) for 2014 and $1.7 for 2015 (7 ) (1 ) (8 ) (3 ) (11 ) 3 (8 ) 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 and $20.9 for 2015 — — — (2 ) (2 ) 33 31 Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense of $4.6 for 2013, $4.1 for 2014 and $4.9 for 2015 (a) (73 ) 7 (66 ) 5 (61 ) 7 (54 ) Net unrealized (loss) gain on derivatives qualifying as cash flow hedges (73 ) 7 (66 ) 3 (63 ) 40 (23 ) Accumulated Other Comprehensive (Loss) Income $ (107 ) $ 7 $ (100 ) 1 $ (99 ) $ 47 $ (52 ) (a) Reclassification is reflected in the operating expenses line item in the combined and consolidated statements of operations.

Net Income Per Share

Net Income Per Share	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Net Income Per Share	Note 18. Net Income (Loss) Per Share Basic net income (loss) per share is computed by dividing net income (loss) attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. In 2015, while we did have securities that were dilutive, these securities did not result in a change on our net income (loss) per share calculation result for the year ended December 31, 2015. We did not have any potentially-dilutive securities for the years ended December 31, 2014 and 2013. In accordance with ASC Topic 260, Earnings per Share, we retroactively applied the stock split to prior years. We completed a series of reorganizations of entities under common control in November 2013. For purposes of computing net income (loss) per share, it is assumed that the Reorganization had occurred at the beginning of the earliest period presented consistent with the pooling of interest method. Therefore, the outstanding shares for the periods preceding the Reorganization reflect the series of reorganizations of entities under common control. The calculations of basic and diluted earnings (loss) per share attributable to AVANGRID, including a reconciliation of the numerators and denominators for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions, except for number of shares and per share data) Numerator: Net income (loss) attributable to AVANGRID $ 267 $ 424 $ (51 ) Denominator: Weighted average number of shares outstanding - basic 254,588,212 252,235,232 252,235,232 Weighted average number of shares outstanding - diluted 254,605,111 252,235,232 252,235,232 Earnings per share attributable to AVANGRID Earnings (Loss) Per Common Share, Basic $ 1.05 $ 1.68 $ (0.20 ) Earnings (Loss) Per Common Share, Diluted $ 1.05 $ 1.68 $ (0.20 )

Tax Equity Financing Arrangemen

Tax Equity Financing Arrangements	12 Months Ended
	Dec. 31, 2015
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 combined and consolidated statements of operations. The presentation reflects revenues and expenses from the TEFs’ operations on a fully consolidated basis. 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 8.5% and 8.7% as of December 31, 2015 and 2014, 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. We consider the following five structures to be TEFs: (1) Aeolus Wind Power I LLC, (2) Aeolus Wind Power II LLC, (3) Aeolus Wind Power III LLC, (4) Aeolus Wind Power IV LLC, and (5) 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 located throughout the U.S. 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. We repurchased a portion of the holding of one of the third-party investors for $51.4 million in 2013. 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 combined and consolidated statements of operations.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2015
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, 2015 and 2014 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2013 1,684 19 1,703 Additions — 4 4 Recognized in income (78 ) (8 ) (86 ) 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 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, 2015 and 2014. 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 $390 million and $323 million as of December 31, 2015 and 2014, respectively.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2015
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. Our maximum exposure to loss is our net investment, of which the carrying amount was $41 million and $66 million as of December 31, 2015 and 2014, 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. Our maximum exposure to loss is our net investments, of which the carrying amount totaled $143 million and $146 million for Flat Rock Wind Power LLC, and $69 million and $50 million for Flat Rock Wind Power II LLC, as of December 31, 2015 and 2014, 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 $110 million as of December 31, 2015. Summarized combined financial information for these equity method investments is as follows: Years ended December 31, 2015 2014 2013 (Millions) Revenue $ 53 $ 72 $ 60 Loss from operations (14 ) — (15 ) Net loss (10 ) — (15 ) As of December 31, 2015 2014 (Millions) Current assets $ 45 $ 11 Non-current assets 929 571 Current liabilities 26 10 Non-current liabilities 223 48 Members’ equity 726 524 Ownership share 50 % 50 % Equity method investment $ 363 $ 262 None of our joint ventures have any contingent liabilities or capital commitments. Distributions received from equity method investments amounted to $12 million, $19 million, and $9 million for the years ended December 31, 2015, 2014, and 2013 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. We have other equity method investments with a carrying value of $22 million as of December 31, 2015.

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2015
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, 2015, 2014 and 2013 consisted of: Years ended December 31, 2015 2014 2013 (Millions) Allowance for funds used during construction $ 21 $ 17 $ 14 Carrying costs on regulatory assets 28 29 29 Other 6 6 11 Total Other income and (expense) $ 55 $ 52 $ 54 Accounts Receivable Accounts receivable as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Trade receivables $ 1,036 $ 888 Other receivables - 2 Allowance for bad debts (62 ) (49 ) Total Accounts Receivable $ 974 $ 841 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, 2015 and 2014 consisted of: (Millions) As of January 1, 2013 $ 56 Current period provision 37 Write-off as uncollectible (35 ) 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 DPA receivable balances were $62 million and $78 million as of December 31, 2015 and 2014, respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Prepaid other taxes $ 130 $ 93 Broker margin and collateral accounts 46 57 Loans to third parties 3 3 Fixed-term deposits 11 25 Other pledged deposits 24 51 Prepaid expenses 53 32 Other 18 27 Total $ 285 $ 288 Other current liabilities Other current liabilities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Advances received $ 96 $ 87 Accrued salaries 68 76 Short-term environmental provisions 35 36 Collateral deposits received 59 39 Pension and other postretirement 5 5 Other 22 19 Total $ 285 $ 262

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2015
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 originated in New York and Maine, and upon the acquisition of UIL on December 16, 2015 regulated electric distribution, electric transmission and gas distribution activities originated 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 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 (loss) adding back net income (loss) attributable to other non-controlling interests, income tax expense, depreciation and amortization, impairment of non-current assets and interest expense net of capitalization, and then subtracting other income and (expense) and earnings (losses) 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 combined and consolidated financial statements. 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 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. Segment information as of and for the year ended December 31, 2013 consisted of: For the year ended December 31, 2013 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,311 $ 1,087 $ (98 ) $ 13 $ 4,313 Revenue - intersegment 8 10 71 (89 ) — Impairment of noncurrent assets — 75 545 — 620 Depreciation and amortization 257 310 26 1 594 Operating income (loss) from continuing operations 703 122 (647 ) 1 179 Adjusted EBITDA 960 507 (76 ) 2 1,393 Earnings (losses) from equity method investments — (7 ) — 4 (3 ) Capital expenditures 906 34 4 — 944 As of December 31, 2013 Property, plant and equipment 7,887 8,302 526 — 16,715 Equity method investments — 278 — — 278 Total assets $ 11,771 $ 11,966 $ 1,495 $ (2,062 ) $ 23,170 (a) Does not represent a segment. I Included in revenue-external for the year ended December 31, 2013 are: $2,665 million from regulated electric operations, $644 million from regulated gas operations and $2 million from other operations of Networks; $1,087 million from renewable energy generation of Renewables; $36 million from gas storage services and $(134) million from gas trading operations of Gas. Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Income (Loss) Before Income Tax for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 (Millions) Consolidated Adjusted EBITDA $ 1,220 $ 1,539 $ 1,393 Less: Impairment of non-current assets 12 25 620 Depreciation and amortization 695 629 594 Interest expense, net of capitalization 267 243 245 Add: Other income and (expense) 55 52 54 Earnings (losses) from equity method investments — 12 (3 ) Consolidated Income (Loss) Before Income Tax $ 301 $ 706 $ (15 )

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Related Party Transactions	Note 24. Related Party Transactions We engage in related party transactions which are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Financiación, S.A. — $ (1 ) — $ (2 ) — $ (2 ) Iberdrola Renovables Energia, S.L. — (9 ) — (10 ) — (10 ) Iberdrola Canada Energy Services, Ltd — (55 ) — (49 ) 2 (75 ) Iberdrola Ingeniería y Construcción, S.A. U. — — — — 26 — Scottish Power, Ltd — — — — — (6 ) Other 3 (37 ) 12 (30 ) 16 (33 ) In addition to the statements of operations 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 $70 million and $226 million as of December 31, 2015 and 2014, respectively. In August 2011, we entered into a revolving credit facility with Iberdrola Financiación, S.A., a subsidiary of Iberdrola. The facility was terminated by AVANGRID on October 28, 2015. The facility was never utilized. Related party balances as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd $ 7 $ (5 ) $ 1 $ — Gamesa Corporación Tecnológica, S.A. 68 (77 ) 33 (223 ) Iberdrola Energy Projects, Inc. 1 (3 ) 15 (15 ) Other — (5 ) 1 (1 ) Transactions with our parent company (included in Other), Iberdrola, relate predominantly to 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 guarantying our performance. All costs that can be specifically allocated, to 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 combined and consolidated statements of operations for the year ended December 31, 2015. The collectability of amounts receivable from Gamesa are contingent upon other related parties fulfilling certain payments to Gamesa. 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 Iberdrola subsidiaries. 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.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2015
Subsequent Events [Abstract]
Subsequent Events	Note 26. Subsequent events On February 17, 2016, Board of Directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable April 1, 2016 to shareholders of record at the close of business on March 10, 2016. On February 17, 2016, we approved the sale of our interest in Iroquois Gas Transmission System L.P. (Iroquois) to an unaffiliated third party. The sale closed on March 31, 2016 with a sale price of $53.8 million.

Acquisition of UIL and Issue of

Acquisition of UIL and Issue of Common Stock	12 Months Ended
	Dec. 31, 2015
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 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 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) after applying 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 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 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 combined and consolidated statements of operations. The following unaudited pro forma 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, (millions) 2015 2014 Revenue $ 5,958 $ 6,226 Net income $ 468 $ 539 The revenue and net (loss) of UIL since the acquisition date included in the combined and consolidated statements of operations for the year ended December 31, 2015 were $36 million and $(36) million, respectively (see Merger Settlement Agreement below for further details). The fair value of assets acquired and liabilities assumed from our acquisition of UIL was based on a preliminary valuation and our estimates and assumptions are subject to change within the measurement period. 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. The primary areas of the purchase price that are not yet finalized include, but are not limited to contracts, equity method investments, provisions, contingent liabilities related to certain environmental sites, income taxes and goodwill. We will finalize these amounts no later than December 16, 2016. Under U.S. GAAP, the measurement period shall not exceed one year from the acquisition date. Measurement period adjustments that we determine to be material will be recognized in future periods in our consolidated financial statements. The following is a summary of the preliminary allocation of the purchase price as of the acquisition date: (millions) Current assets, including cash of $48 million $ 500 Other investments 114 Property, plant and equipment, net 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 estimated consideration $ 2,873 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. As part of the preliminary allocation of the purchase price we have determined a fair value of contingent liabilities of approximately $44.0 million relating to certain environmental sites. 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. In connection with the acquisition proceeding, UI signed a proposed partial consent order, or consent order that, when approved by the Commissioner of DEEP, and pursuant to the terms and conditions in the consent order, would require 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, upon its issuance and subject to its terms and conditions, UI would be 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). 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 Berkshire 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. · Berkshire will contribute $1 million to alternative heating programs. · Berkshire 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 Issue 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 February 17, 2016, Board of Directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable April 1, 2016 to shareholders of record at the close of business on March 10, 2016.

Short-Term Credit Arrangements

Short-Term Credit Arrangements	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Short-Term Credit Arrangements	Note 3. Short-Term Credit Arrangements AVANGRID Revolving Credit Facility In May 2012, AVANGRID entered into a $300 million revolving credit facility for the purpose of providing for liquidity needs and those of the unregulated subsidiaries. The facility has a termination date in May 2019. We pay an annual facility fee of $0.7 million. As of December 31, 2015 and December 31, 2014 the facility was undrawn. AVANGRID’s revolving credit facility contains a covenant that requires it to maintain a ratio of consolidated indebtedness to consolidated total capitalization that does not exceed 0.65 to 1.00 at any time. For purposes of calculating this maximum ratio of consolidated indebtedness to consolidated total capitalization, the credit facility excludes from consolidated net worth the balance of AOCI as it appears in the consolidated balance sheets. Iberdrola Financiación, S.A. Credit Facility In August 2011, AVANGRID entered into a revolving credit facility with Iberdrola Financiación, S.A., a subsidiary of Iberdrola, under which AVANGRID may borrow up to $600 million. The facility was terminated by AVANGRID on October 28, 2015. The facility was never utilized.

Cash Dividends Paid by Subsidia

Cash Dividends Paid by Subsidiaries	12 Months Ended
	Dec. 31, 2015
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, 2015 2014 2013 (In millions) AVANGRID Networks $ 59 $ 200 $ 110 AVANGRID Renewables 750 — — Other AVANGRID subsidiaries 302 — 12 $ 1,111 $ 200 $ 122 During 2015, Renewables authorized dividend payments of $1.4 billion to AVANGRID, of which $950 million was in cash ($750 million paid in 2015) and the remainder in financial instruments. On February 4, 2016, AVANGRID subsidiary, CMP, declared a dividend of $100 million payable to AVANGRID.

Summary of Significant Accoun39

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Policies)	12 Months Ended
	Dec. 31, 2015
Accounting Policies [Abstract]
Principles of Consolidation and Combination	(a) Principles of consolidation and combination 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 combined and consolidated statements of operations 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.
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 combined and consolidated statements of operations 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 combined and consolidated statements of operations 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 30-35 Hydroelectric power stations 40-90 Plant Wind power stations 25 Gas storage 17-119 Transport facilities 33-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 17-41 Computer software 3-10 Other Buildings 9-75 Operations offices 5-32 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 combined and 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 recognized at fair value 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 amounts related to AROs are included as other non-current assets in 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 company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as 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	(n) Tax equity financing arrangements 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.
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.
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 sheet within “Materials and supplies.” Inventory items are combined for the cash flow statement 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 combined and consolidated statements of operations 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 to 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, and to depreciate the capitalized cost over the useful life of the related asset. 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 2048.
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, RGE 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. O
Income Tax	(v) Income tax For the 2015 tax year, AVANGRID will file a consolidated federal income tax return, which will include the UIL taxable income or loss for the period from December 17, 2015 to December 31, 2015. UIL will file 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 most recently 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. In addition, a consolidated federal income tax return, that included the taxable income or loss of ARHI and all of its subsidiaries for the entire 2013 tax year and the taxable income or loss of AVANGRID (without UIL) and all of its subsidiaries for the tax period of November 21, 2013 through December 31, 2013, was filed. For the period of January 1, 2013 through November 20, 2013, AVANGRID (excluding ARHI and UIL) filed a consolidated federal income tax return that included the taxable income or loss of all its subsidiaries, which are 80% or more owned. 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, 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. 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 combined and 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 combined and consolidated statements of operations. 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 combined and consolidated statements of operations. 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. We account for stock-based payment transactions based on the estimated fair value of awards, net of estimated forfeitures at the date of issuance. 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 for certain share-based awards until the employee becomes retirement eligible, if earlier. The total stock-based compensation expense, which is included in operations and maintenance of the combined and consolidated statements of operations for the years ended December 31, 2015, 2014 and 2013 was $6.0 million, $4.8 million and $7.6 million, respectively. The total liability relating to stock-based compensation, which is included in other non-current liabilities, was $17.5 million and $16.8 million as of December 31, 2015 and 2014. The Company’s historical stock-based expense and liabilities are based on shares of its parent, Iberdrola S.A, and not on shares of the Company. The Company has total unrecognized costs for stock-based compensation of approximately $1.0 million as of December 31, 2015. As of December 31, 2015 the Company maintained unvested performance shares that may be settled through the issuance of additional Company shares in future periods upon the achievement of certain conditions.
Reclassifications	Reclassifications Certain amounts have been reclassified in the consolidated balance sheet and combined and consolidated statements of operations to conform to the 2015 presentation. Amounts pertaining to sales and use tax of $8 million and $11 million for the years ended December 31, 2014 and 2013, respectively, have been reclassified from “Taxes other than income taxes” to “Operations and maintenance” in the combined and consolidated statements of operations. Additionally, current and non-current liabilities amounting to $12 million and $23 million, pertaining to the Rate refund – FERC ROE proceeding have been reclassified from “Other current liability” and “Other non-current liability” to current and non-current regulatory liabilities in the consolidated balance sheet as of December 31, 2014.
New Accounting Standards and Interpretations	New Accounting Standards and Interpretations (a) Simplifying the presentation of debt issuance costs The Financial Accounting Standards Board (FASB) issued an amendment in April 2015 that is intended to simplify the presentation of debt issuance costs. Instead of presenting debt issuance costs as a deferred charge (that is, as an asset), the amendments require debt issuance costs related to a recognized debt liability to be presented in the balance sheet as a direct deduction from the carrying amount of that debt liability, consistent with the presentation for debt discounts. The amendment is effective for public entities for financial statements issued for fiscal years beginning after December 15, 2015, and for interim periods within those fiscal years. As permitted, we have early adopted the amendment as of the beginning of the fourth quarter of 2015 and have applied it retrospectively to all periods presented. Accordingly, we reclassified the debt issuance costs from other noncurrent assets to noncurrent debt on our December 31, 2014 consolidated balance sheet, which decreased total assets, noncurrent debt and total liabilities by $27 million. (b) Balance sheet classification of deferred taxes The FASB issued an amendment in November 2015 that is intended to simplify the presentation of deferred income taxes by requiring entities that present a classified statement of financial position to classify deferred tax liabilities and assets as noncurrent in their balance sheet. This aligns the presentation of deferred income tax liabilities and assets with International Financial Reporting Standards. The amendments do not affect the current requirement that deferred tax liabilities and assets of a tax-paying component of an entity be offset and presented as a single amount. The amendments are effective for public entities for financial statements issued for annual periods beginning after December 15, 2016, and interim periods within those annual periods. As permitted, we have early adopted the amendments as of the beginning of the fourth quarter of 2015, and have elected retrospective application to all periods presented in order to simplify the presentation in our balance sheet. Accordingly, we reclassified the current deferred taxes to noncurrent on our December 31, 2014 consolidated balance sheet, which decreased noncurrent deferred tax assets and liabilities by $97 million. (c) Pushdown accounting In November 2014 the FASB issued an amendment on when and how an acquired entity that is a business or nonprofit activity, whether public or nonpublic, can apply pushdown accounting in its separate financial statements upon the occurrence of an event in which an acquirer, either an individual or an entity, obtains control of the acquired entity. The guidance provides an acquired entity with an option to apply pushdown accounting in its separate financial statements. As a result of the amendment, which was effective when issued, we were not required to apply pushdown accounting to the acquisition of Energy East by Iberdrola in 2008. Therefore, the net assets of Networks in these combined and consolidated financial statements are recorded at the historical accounting basis of AVANGRID, which do not include purchase accounting adjustments related to that acquisition. (d) Discontinued operations and disposals of components of an entity The FASB issued an amendment in April 2014 that changed the requirements for the reporting of discontinued operations. The new definition of discontinued operations limits reporting to disposals of components that represent strategic shifts that have, or will have, a major effect on an entity’s operations and financial results. The amendments are effective for public business entities for annual periods beginning on or after December 15, 2014, and interim periods within those years. The adoption of the amendment did not materially affect our results of operations, financial position or cash flows. (e) Revenue from contracts with customers In May 2014 the FASB issued an amendment related to the recognition of revenue from contracts with customers and required disclosures. The core principle is for an entity to recognize revenue to represent the transfer of goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. The standard is effective for public entities for annual reporting periods beginning after December 15, 2016, including interim periods within that reporting period. In August 2015 the FASB issued an accounting standards update that defers by one year the effective date of the revenue standard for all entities. Thus, the standard is now effective for annual reporting periods beginning after December 15, 2017, and interim periods therein, with early adoption as of the original effective date permitted. In March 2016 the FASB issued an accounting standards update that amends and clarifies the implementation guidance on principal versus agent considerations for reporting revenue gross rather than net, with the same deferred effective date. We are currently evaluating how the adoption of the amendment will affect our results of operations, financial position, and cash flows. (f) Presentation of an unrecognized tax benefit In July 2013 the FASB issued guidance on the financial statement presentation of an unrecognized tax benefit when a net operating loss (NOL) carryforward, a similar tax loss, or a tax credit carryforward exists. An unrecognized tax benefit, or a portion of an unrecognized tax benefit, is to be presented as a reduction to a deferred tax asset for an NOL carryforward, a similar tax loss, or a tax credit carryforward, with certain exceptions. The unrecognized tax benefit is to be presented as a liability and should not be combined with deferred tax assets to the extent that an NOL carryforward, a similar tax loss, or a tax credit carryforward is not available at the reporting date under the tax law of the applicable jurisdiction to settle any additional income taxes that would result from the disallowance of a tax position or the tax law of the applicable jurisdiction does not require the entity to use, and the entity does not intend to use, the deferred tax asset for such purpose. AVANGRID adopted these amendments effective January 1, 2014. The adoption of these amendments did not materially affect our results of operations, financial position or cash flows. (g) Fair value measurement disclosures for certain investments The FASB issued amendments in May 2015 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. We do not expect our adoption of the amendments to materially affect our results of operations, financial position, or cash flows. (h) 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 do not expect our adoption of the amendments to affect our results of operations, financial position, or cash flows. (i) Application of the normal purchases and normal sales scope exception The FASB issued amendments in August 2015 to specify that the use of locational marginal pricing by an independent system operator (ISO) does not constitute net settlement of a contract for the purchase or sale of electricity on a forward basis that necessitates transmission through, or delivery to a location within, a nodal energy market, even when legal title to the associated electricity is conveyed to the ISO during transmission. As a result, the use of locational marginal pricing by the ISO does not cause that contract to fail to meet the physical delivery criterion of the normal purchases and normal sales (NPNS) scope exception. If the physical delivery criterion is met, along with all of the other criteria of the NPNS scope exception, an entity may elect to designate that contract as a normal purchase or normal sale. The amendments were effective upon issuance of the accounting standards update, which was August 10, 2015, and require prospective application. The adoption of these amendments did not materially affect our results of operations, financial position or cash flows. (j) 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. This 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 these changes will be reclassified from accumulated other comprehensive income to earnings if the financial liability is settled before maturity. Public business 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 do not expect our adoption of the guidance to materially affect our results of operations, financial position, or cash flows. (k) Business combinations: simplifying the accounting for measurement-period adjustments The FASB issued amendments in September 2015 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. We cannot predict how our adoption of the amendments will affect our results of operation, financial position, or cash flows as it relates to the business combination with UIL. See Note 4 - “Acquisition of UIL.” (l) 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 expect our adoption of the new guidance will materially affect our results of operations and financial position. (m) Derivative contract novations The FASB issued amendments in March 2016 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 do not expect our adoption will materially affect our results of operations, financial position, and cash flows.
Use of Estimates and Assumptions	Use of Estimates and Assumptions The preparation of our combined and 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 combined and 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 combined and 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 Bargain Agreements	Union bargain 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 1% of our employees.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2015
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Summary of Effect of Correction on Consolidated Balance Sheet	A summary of the effect of the correction on the consolidated balance sheet as of December 31, 2014 is as follows: As of December 31, 2014 As Reported Correction As Revised (Millions) Accumulated depreciation $ (5,796 ) $ 34 $ (5,762 ) Net Property, Plant and Equipment in Service 15,703 34 15,737 Total Property, Plant and Equipment 17,099 34 17,133 Total assets 24,128 34 24,162 Deferred income taxes 2,256 13 2,269 Total Other Non-current Liabilities 5,749 13 5,762 Total Non-current Liabilities 9,900 13 9,913 Total liabilities 11,672 13 11,685 Retained earnings 1,161 21 1,182 Total Stockholders' Equity 12,440 21 12,461 Total Equity 12,456 21 12,477 Total Liabilities and Equity $ 24,128 $ 34 $ 24,162
Summary of Effect of Correction on Combined and Consolidated Statement of Operations	A summary of the effect of the correction on the combined and consolidated statement of operations for the year ended December 31, 2013 is as follows: Year Ended December 31, 2013 As Reported Correction As Revised (Millions, except per share data) Depreciation and amortization $ 617 $ (23 ) $ 594 Total Operating Expenses 4,157 $ (23 ) 4,134 Operating income 156 23 179 Loss Before Income Tax (38 ) 23 (15 ) Income tax expense 26 9 35 Net Loss (64 ) 14 (50 ) Net Loss Per Common Share, Basic and Diluted: $ (0.26 ) $ (0.06 ) $ (0.20 )

Summary of Significant Accoun41

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2015
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 30-35 Hydroelectric power stations 40-90 Plant Wind power stations 25 Gas storage 17-119 Transport facilities 33-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 17-41 Computer software 3-10 Other Buildings 9-75 Operations offices 5-32

Acquisition of UIL (Tables)

Acquisition of UIL (Tables)	12 Months Ended
	Dec. 31, 2015
Business Combinations [Abstract]
Summary of Fair Value of Purchase Consideration	The fair value 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) after applying 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 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 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, (millions) 2015 2014 Revenue $ 5,958 $ 6,226 Net income $ 468 $ 539
Summary of Preliminary Allocation of Purchase Price	The following is a summary of the preliminary allocation of the purchase price as of the acquisition date: (millions) Current assets, including cash of $48 million $ 500 Other investments 114 Property, plant and equipment, net 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 estimated consideration $ 2,873

Electric And Gas Delivery Rate

Electric And Gas Delivery Rate Increase (Tables)	12 Months Ended
	Dec. 31, 2015
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 % RGE Electric 3.0 0.70 % 21.6 5.00 % 25.9 5.70 % RGE Gas 8.8 5.20 % 7.7 4.40 % 9.5 5.20 %

Regulatory Assets and Liabili44

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Regulated Operations [Abstract]
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Current Pension and other postretirement benefits cost deferrals $ 8 $ — Pension and other postretirement benefits 13 — Storm costs 8 14 Temporary supplemental assessment surcharge 7 12 Hedges losses 37 34 Contracts for differences 18 — Hardship programs 13 — Deferred purchased gas 12 — Deferred transmission expense 12 — Environmental remediation costs 37 — Other 54 20 Total Current Regulatory Assets 219 80 Non-current Pension and other postretirement benefits cost deferrals 151 125 Pension and other postretirement benefits 1,509 1,101 Storm costs 251 259 Deferred meter replacement costs 34 36 Unamortized losses on reacquired debt 23 25 Environmental remediation costs 271 247 Unfunded future income taxes 549 366 Asset retirement obligation 24 32 Deferred property tax 45 30 Federal tax depreciation normalization adjustment 158 128 Merger capital expense target customer credit 15 10 Debt premium 141 — Contracts for differences 50 — Hardship programs 29 14 Other 64 26 Total Non-current Regulatory Assets $ 3,314 $ 2,399
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Current Reliability support services (Cayuga) $ 16 $ 18 Plant decommissioning — 13 Non by-passable charges 7 19 Energy efficiency portfolio standard 33 34 Gas supply charge and deferred natural gas cost 6 6 Transmission revenue reconciliation mechanism 16 23 Yankee DOE Phase I 5 23 Merger related rate credits 20 — Revenue decoupling mechanism 14 8 Other 30 21 Total Current Regulatory Liabilities 147 165 Non-current Accrued removal obligations 1,084 721 Asset sale gain account 8 19 Carrying costs on deferred income tax bonus depreciation 116 81 Economic development 36 33 Merger capital expense target customer credit account 17 17 Pension and other postretirement benefits 90 50 Positive benefit adjustment 51 51 New York state tax rate change 17 16 Post term amortization 25 20 Theoretical reserve flow thru impact 31 24 Deferred property tax 15 51 Net plant reconciliation 10 10 Variable rate debt 32 25 Carrying costs on deferred income tax - Mixed Services 263(a) 31 20 Rate refund – FERC ROE proceeding 21 23 Merger related rate credits 24 — Accumulated deferred investment tax credits 10 — Asset retirement obligation 13 — Middletown/Norwalk local transmission network service collections 19 — Excess generation service charge 21 — Low income programs 42 10 Unfunded future income taxes 27 — Non-firm margin sharing credits 8 — Deferred income taxes regulatory 519 433 Other 93 58 Total Non-current Regulatory Liabilities $ 2,360 $ 1,662

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2015
Goodwill And Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Networks $ 2,733 $ 979 Renewables 380 380 Gas — — Other (a) 2 2 Total $ 3,115 $ 1,361 (a) Does not represent a reportable segment. It mainly includes Corporate and company eliminations.
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, 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 As of December 31, 2014 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 325 $ (117 ) $ 208 Wind development 574 (220 ) 354 Other 56 (49 ) 7 Total Intangible Assets $ 955 $ (386 ) $ 569
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2015, to be as follows: Year ending December 31, (Millions) 2016 $ 27 2017 25 2018 24 2019 26 2020 25

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2015
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 30-35 Hydroelectric power stations 40-90 Plant Wind power stations 25 Gas storage 17-119 Transport facilities 33-75 Distribution facilities 15-80 Equipment Conventional meters and measuring devices 17-41 Computer software 3-10 Other Buildings 9-75 Operations offices 5-32
Regulated and Unregulated [Member]
Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives	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. Property, plant and equipment as of December 31, 2014 consisted of: As of December 31, 2014 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 8,625 $ 9,798 $ 18,423 Natural gas transportation, distribution and other 1,723 648 2,371 Other common operating property 654 51 705 Total Property, Plant and Equipment in Service (a) 11,002 10,497 21,499 Total accumulated depreciation (b) (3,491 ) (2,271 ) (5,762 ) Total Net Property, Plant and Equipment in Service 7,511 8,226 15,737 Construction work in progress 878 518 1,396 Total Property, Plant and Equipment $ 8,389 $ 8,744 $ 17,133 ( a ) Includes capitalized leases of $158 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $47 million.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Table Text Block Supplement [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2015 and 2014 consisted of: (Millions) As of December 31, 2013 $ 209 Liabilities settled during the year (1 ) Liabilities incurred during the year 6 Accretion expense 14 Revisions in estimated cash flows 6 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

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2015
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long- term debt as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2016-2045 $ 1,815 3.07%-10.60% $ 1,405 3.07%-8.00% Unsecured pollution control notes - fixed 2020 200 2.00%-2.375% 132 2.125%-2.25% Unsecured pollution control notes – variable 2032-2034 219 0.195%-1.181% 159 0.03%-0.461% Other various non-current debt - fixed 2016-2045 2,440 2.89%-10.48% 889 3.24%-10.48% Total Debt $ 4,674 $ 2,585 Obligations under capital leases 2020-2023 87 4%-4.44% 81 4%-4.44% Unamortized debt (costs) premium, net (25 ) (29 ) Less: debt due within one year, included in current liabilities 206 148 Total Non-current Debt $ 4,530 $ 2,489 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s properties of approximately $5,682 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) 2016 2017 2018 2019 2020 Total $ 206 $ 302 $ 162 $ 354 $ 721 $ 1,745

Fair Value of Financial Instr49

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2015
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2015 and 2014 consisted of: 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 (CfDs) — — 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 (CfDs) — — (96 ) — (96 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (236 ) $ (52 ) $ (164 ) $ 267 $ (185 ) As of December 31, 2014 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 33 $ — $ — $ — $ 33 Derivative assets Derivative financial instruments - power 11 83 48 (53 ) 89 Derivative financial instruments - gas 18 638 61 (579 ) 138 Total 29 721 109 (632 ) $ 227 Derivative liabilities Derivative financial instruments - power (40 ) (42 ) (7 ) 53 (36 ) Derivative financial instruments - gas (25 ) (614 ) (42 ) 579 (102 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (65 ) $ (656 ) $ (52 ) $ 632 $ (141 )
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, 2015, 2014 and 2013 consisted of: (Millions) 2015 2014 2013 Fair value as of January 1, $ 57 $ 53 $ 5 Gains for the year recognized in operating revenues 33 11 21 Losses for the year recognized in operating revenues (8 ) (1 ) (3 ) Total gains or losses for the period recognized in operating revenues 25 10 18 Gains recognized in OCI 2 — — Losses recognized in OCI (3 ) (3 ) — Total gains or losses recognized in OCI (1 ) (3 ) — Purchases (73 ) 14 47 Settlements (14 ) (26 ) (15 ) Transfers out of Level 3 (a) (13 ) 9 (2 ) Fair value as of December 31, $ (19 ) $ 57 $ 53 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 $ 25 $ 10 $ 18 (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: Unobservable Input Range at December 31, 2015 Risk of non-performance 0.06% - 0.88% Discount rate 1.31% - 2.27% Forward pricing ($ per MW) $3.15 - $11.19
Fair Value, Assets and Liabilities Level 3 Measurement , Valuation Techniques	They represent the variability in prices for those transactions that fall into the illiquid period (beyond 2 years), using past and current views of prices for those future periods. Variability Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions with delivery periods Transactions are valued against forward market prices Observable and extrapolated forward gas and power prices not all of which can be NYMEX ($/MMBtu) $ 4.56 $ 7.37 $ 1.76 with delivery exceeding two on a corroborated by SP15 ($/MWh) $ 46.82 $ 80.28 $ 19.75 period > two years discounted market data for Mid C ($/MWh) $ 37.93 $ 83.93 $ 6.75 years basis identical or Cinergy ($/MWh) $ 37.73 $ 77.49 $ 19.98 similar products

Derivative Instruments and He50

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2015
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 period from December 17, 2015 to December 31, 2015 were as follows: (Millions) Period from December 17, 2015 to December 31, 2015 Regulatory Assets - Derivative liabilities $ (1 ) Regulatory Liabilities - Derivative assets $ —
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, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Wholesale electricity purchase contracts (MWh) 6.7 6.6 Natural gas purchase contracts (Dth) 4.8 3.8 Fleet fuel purchase contracts (Gallons) 3.8 2.8 The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (MWh/Dth in Millions) Wholesale electricity purchase contracts 3 2 Wholesale electricity sales contracts 6 7 Foreign exchange forward purchase contracts 4 — Natural gas and other fuel purchase contracts 332 275 Financial power contracts 7 8 Basis swaps - purchases 67 160 Basis swaps - sales 80 161
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location and Amount	The location and amounts of derivatives designated as hedging instruments associated with Networks activities as of December 31, 2015 and 2014 consisted of: Asset Derivatives Liability Derivatives (Millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value As of December 31, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ — Non-current Other assets — Other liabilities — Natural gas derivatives: Current Current assets — Current liabilities — Non-current Other assets — Other liabilities — Fleet fuel contracts Current Current assets — Current liabilities (2 ) Non-current Other assets — Other liabilities (1 ) Total $ — $ (3 ) As of December 31, 2014 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ (20 ) Non-current Other assets — Other liabilities (9 ) Natural gas derivatives: Current Current assets — Current liabilities (4 ) Non-current Other assets — Other liabilities (1 ) Fleet fuel contracts Current assets — Current liabilities (3 ) Total $ — $ (37 ) 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 location and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of December 31, 2015 consisted of: Asset Derivatives Liability Derivatives (Millions) Balance Sheet Location Fair Value Balance Sheet Location Fair Value As of December 31, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ 2 Current liabilities $ — Non-current Other assets 1 Other liabilities — Natural gas derivatives: Current Current assets 50 Current liabilities (9 ) Non-current Other assets 9 Other liabilities — Total $ 62 $ (9 )
Schedule of Derivative Instruments, Effect of Cashflow 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, 2015, 2014 and 2013 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) 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 ) 2013 Interest rate contracts $ — Interest expense $ (11 ) Commodity contracts — Operating expenses (1 ) Total $ — $ (12 ) (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 combined and consolidated statements of operations. Year Ended December 31, 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) 2015 Commodity contracts $ 57 Revenues $ (2 ) Total $ 57 $ (2 ) (a) Changes in OCI are reported on a pre-tax basis.
Schedule of Offsetting of Derivative Assets	The offsetting of derivative assets as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Assets Gross Amounts Not Offset in the Balance Sheet As of December 31, Amounts of Recognized Assets Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ 10 $ (10 ) $ — $ — $ — $ — 2014 Derivatives 11 (11 ) — — — — The offsetting of derivative assets as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Assets Gross Amounts Offset in the Balance Sheet As of December 31, Amounts of Recognized Assets Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ 489 $ (341 ) $ 148 $ (36 ) $ (15 ) $ 97 2014 Derivatives 847 (620 ) 227 (66 ) (73 ) 88
Schedule of Offsetting of Derivative Liabilities	The offsetting of derivative liabilities as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Liabilities Gross Amounts Not Offset in the Balance Sheet As of December 31, Amounts of Recognized Liabilities Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ (49 ) $ 46 $ (3 ) $ — $ — $ (3 ) 2014 Derivatives (48 ) 11 (37 ) — 37 — The offsetting of derivative liabilities as of December 31, 2015 and 2014 consisted of: Gross Gross Net Amounts of Liabilities Gross Amounts Not Offset in the Balance Sheet As of December 31, Amounts of Recognized Liabilities Amounts Offset in the Balance Sheet Presented in the Balance Sheet Financial Instruments Cash Collateral Pledged Net Amount (Millions) 2015 Derivatives $ (307 ) $ 221 $ (86 ) $ 36 $ 4 $ (46 ) 2014 Derivatives (724 ) 620 (104 ) 66 1 (37 )
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables and Gas activities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Wholesale electricity purchase contracts $ (13 ) $ (12 ) Wholesale electricity sales contracts 35 44 Foreign exchange forward purchase contracts (1 ) (3 ) Natural gas and other fuel purchase contracts 10 54 Financial power contracts 32 48 Basis swaps- purchases 1 (4 ) Basis swaps- sales (2 ) (4 ) Total $ 62 $ 123
Effect of Trading and Non-trading Derivatives Associated with Renewables and Gas Activities	The effect of trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Wholesale electricity purchase contracts $ 6 $ (9 ) $ 2 Wholesale electricity sales contracts (5 ) 9 (1 ) Financial power contracts — (2 ) (4 ) Financial and natural gas contracts (26 ) 125 (21 ) Total Gain (Loss) $ (25 ) $ 123 $ (24 ) The effect of non-trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Wholesale electricity purchase contracts $ (8 ) $ (8 ) $ 9 Wholesale electricity sales contracts (5 ) 15 (2 ) Financial power contracts 24 30 (19 ) Natural gas and other fuel purchase contracts 18 (1 ) 16 Total Gain (Loss) $ 29 $ 36 $ 4

Commitments and Contingent Li51

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2015
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Lease Payments	Total future minimum lease payments as of December 31, 2015 consisted of: (Millions) Year Operating Leases(a) Capital Leases(a) Total 2016 $ 216 $ 9 $ 225 2017 90 6 96 2018 26 6 32 2019 24 6 30 2020 25 7 32 2021 and thereafter 298 53 351 Total $ 679 $ 87 $ 766
Forward Purchase and Sales Commitment Arrangement	Forward purchases and sales commitments under power, gas, and other arrangements as of December 31, 2015 consisted of: (Millions) Purchases Sales As of December 31, Gas Power Other Total Gas Power Other Total 2016 $ 232 $ 233 $ 31 $ 496 $ 21 $ 133 $ 3 $ 157 2017 203 123 25 351 3 84 2 89 2018 181 76 14 271 — 67 2 69 2019 149 54 8 211 — 48 1 49 2020 124 53 7 184 — 39 — 39 Thereafter 579 320 58 957 — 46 — 46 Totals $ 1,468 $ 859 $ 143 $ 2,470 $ 24 $ 417 $ 8 $ 449

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2015
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, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Current Federal $ (20 ) $ (10 ) $ (22 ) State (33 ) 31 (1 ) Current taxes charged to (benefit) expense (53 ) 21 (23 ) Deferred Federal 136 218 60 State (6 ) 82 42 Deferred taxes charged to expense 130 300 102 Production tax credits (42 ) (37 ) (42 ) Investment tax credits (1 ) (2 ) (2 ) Total Income Tax Expense $ 34 $ 282 $ 35
Schedule of Differences between Tax Expense Per Statements of Operations and Tax Expense at Statutory Federal Tax Rate	The differences between tax expense per the statements of operations and tax expense at the 35% statutory federal tax rate for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Tax expense (benefit) at federal statutory rate $ 105 $ 247 $ (5 ) Depreciation and amortization not normalized 15 15 24 Investment tax credit amortization (1 ) (2 ) (2 ) Tax return related adjustments 6 2 7 Production tax credits (42 ) (37 ) (42 ) Tax equity financing arrangements (36 ) (11 ) (23 ) Change in tax reserves — 3 (2 ) Impairment of non-deductible goodwill — — 38 Changes in New York tax law — 41 — State tax expense (benefit), net of federal benefit (25 ) 32 27 Non-deductible acquisition costs 9 — — Other, net 3 (8 ) 13 Total Income Tax Expense $ 34 $ 282 $ 35
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Non-current Deferred Income Tax Liabilities (Assets) Property related $ 4,763 $ 3,778 Unfunded future income taxes 211 146 Federal and state tax credits (367 ) (317 ) Accumulated deferred investment tax credits 15 16 Federal and state NOL’s (1,367 ) (1,266 ) Joint ventures/partnerships 655 884 Nontaxable grant revenue (595 ) (622 ) Other (17 ) 66 Non-current Deferred Income Tax Liabilities 3,298 2,685 Add: Valuation allowance 19 17 Total Non-current Deferred Income Tax Liabilities 3,317 2,702 Less amounts classified as regulatory liabilities Non-current deferred income taxes 519 433 Non-current Deferred Income Tax Liabilities $ 2,798 $ 2,269 Deferred tax assets $ 2,346 $ 2,205 Deferred tax liabilities 5,663 4,907 Net Accumulated Deferred Income Tax Liabilities $ 3,317 $ 2,702
Schedule of Unrecognized Tax Benefits Roll Forward [Table Text Block]	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2015, 2014 and 2013 consisted of: Years ended December 31, 2015 2014 2013 (Millions) Beginning Balance $ 38 $ 41 $ 91 Increases for tax positions related to prior years 1 20 4 Reduction for tax position related to settlements with taxing authorities (3 ) (23 ) (54) Ending Balance $ 36 $ 38 $ 41

Post-retirement and Similar O53

Post-retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2015
Schedule of Amounts Recognized in Balance Sheet	Amounts recognized as of December 31, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2015 2014 (Millions) Non-current assets $ — $ — $ — $ — Current liabilities — — (5 ) (5 ) Non-current liabilities (500 ) (477 ) (275 ) (301 ) Total $ (500 ) $ (477 ) $ (280 ) $ (306 )
Summary of Amounts Recognized in OCI	Amounts recognized in OCI, before income taxes, for ARHI for the years ended December 31, 2015, 2014 and 2013 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 (Millions) Net (income) loss $ 25 $ 22 $ 16 $ (1 ) $ 8 $ 14
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 rate base or are accruing a carrying cost until they will be included in rate base. The primary items that are not included in 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, asset retirement obligations, hedge losses and contracts for differences. The total amount of these items is $2,825 million. 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. Most of the items related to NYSEG for which the amortization period has been characterized as to be determined in a future proceeding have been addressed in the Proposal. If the Proposal is approved, most of these items would be amortized over a five year period, except the portion of storm costs to be recovered over ten years and plant related tax items which will be amortized over the life of associated plant. Annual amortization expense for NYSEG would be approximately $16.5 million per rate year. The RGE items that would begin being amortized are plant related tax items. A majority of the other items related to RGE, which net to a regulatory liability, will not be amortized until future proceedings or will be used to recover costs of the Ginna RSSA agreement. Current and non-current regulatory assets as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Current Pension and other postretirement benefits cost deferrals $ 8 $ — Pension and other postretirement benefits 13 — Storm costs 8 14 Temporary supplemental assessment surcharge 7 12 Hedges losses 37 34 Contracts for differences 18 — Hardship programs 13 — Deferred purchased gas 12 — Deferred transmission expense 12 — Environmental remediation costs 37 — Other 54 20 Total Current Regulatory Assets 219 80 Non-current Pension and other postretirement benefits cost deferrals 151 125 Pension and other postretirement benefits 1,509 1,101 Storm costs 251 259 Deferred meter replacement costs 34 36 Unamortized losses on reacquired debt 23 25 Environmental remediation costs 271 247 Unfunded future income taxes 549 366 Asset retirement obligation 24 32 Deferred property tax 45 30 Federal tax depreciation normalization adjustment 158 128 Merger capital expense target customer credit 15 10 Debt premium 141 — Contracts for differences 50 — Hardship programs 29 14 Other 64 26 Total Non-current Regulatory Assets $ 3,314 $ 2,399 “Pension and other postretirement benefits” represent the actuarial losses on the pension and other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG, and RGE 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. Since the approval of the 2010 rate plan in New York, NYSEG has experienced unusually high levels of restoration costs resulting from various storms including Hurricane Sandy, Hurricane Irene, and Tropical Storm Lee. NYSEG’s deferred storm costs, reflecting the over (under) spending of actual costs compared with amounts currently allowed in rates, was $(9) million and $5 million for the years ended December 31, 2015 and 2014, respectively. NYSEG’s total deferral, including carrying costs, was $247 million and $241 million as of December 31, 2015 and 2014, respectively. The amortization will be determined in a future NYPSC proceeding. CMP’s deferred service restoration costs, primarily as a result of an ice storm in late December 2014, reflecting over (under) spending of actual costs compared with amounts allowed in rates, was $(6) million and $15 million for the years ended December 31, 2015 and 2014, respectively. CMP’s total deferral, including carrying costs, was $12 million and $32 million as of December 31, 2015 and 2014, respectively. Recovery of CMP’s deferred storm costs in the amount of $28 million began with the effective date of its last rate case and occurs over a twenty-four month period. Recovery of incremental deferrals will be determined in a future proceeding. “Deferred meter replacement costs” represent the deferral of the value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized at the related existing depreciation amounts. “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. 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. “Asset retirement obligation” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred property taxes” represent the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amortization period is awaiting a future NYPSC rate proceeding. “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 will be determined in future NYPSC and 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. “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, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Current Reliability support services (Cayuga) $ 16 $ 18 Plant decommissioning — 13 Non by-passable charges 7 19 Energy efficiency portfolio standard 33 34 Gas supply charge and deferred natural gas cost 6 6 Transmission revenue reconciliation mechanism 16 23 Yankee DOE Phase I 5 23 Merger related rate credits 20 — Revenue decoupling mechanism 14 8 Other 30 21 Total Current Regulatory Liabilities 147 165 Non-current Accrued removal obligations 1,084 721 Asset sale gain account 8 19 Carrying costs on deferred income tax bonus depreciation 116 81 Economic development 36 33 Merger capital expense target customer credit account 17 17 Pension and other postretirement benefits 90 50 Positive benefit adjustment 51 51 New York state tax rate change 17 16 Post term amortization 25 20 Theoretical reserve flow thru impact 31 24 Deferred property tax 15 51 Net plant reconciliation 10 10 Variable rate debt 32 25 Carrying costs on deferred income tax - Mixed Services 263(a) 31 20 Rate refund – FERC ROE proceeding 21 23 Merger related rate credits 24 — Accumulated deferred investment tax credits 10 — Asset retirement obligation 13 — Middletown/Norwalk local transmission network service collections 19 — Excess generation service charge 21 — Low income programs 42 10 Unfunded future income taxes 27 — Non-firm margin sharing credits 8 — Deferred income taxes regulatory 519 433 Other 93 58 Total Non-current Regulatory Liabilities $ 2,360 $ 1,662 “Reliability support services (Cayuga)” represent 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 fixed 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 awaiting a future NYPSC rate proceeding. “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 awaiting a future NYPSC rate proceeding. “Economic development” represents the economic development program which enables NYSEG and RGE 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 RGE varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is awaiting a future NYPSC rate proceeding. “Merger capital expense target customer credit” account was created as a result of NYSEG and RGE not meeting certain capital expenditure requirements established in the order approving the purchase of Energy East by Iberdrola. The amortization period is awaiting a future NYPSC rate proceeding. “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. It also represents 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 acquisitions of Energy East. This is being used to moderate increases in rates. The amortization period is awaiting a future NYPSC rate proceeding. “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 awaiting a future NYPSC rate proceeding. “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is awaiting a future NYPSC rate proceeding. “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 awaiting a future NYPSC rate proceeding. “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. “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. 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.
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Current Pension and other postretirement benefits cost deferrals $ 8 $ — Pension and other postretirement benefits 13 — Storm costs 8 14 Temporary supplemental assessment surcharge 7 12 Hedges losses 37 34 Contracts for differences 18 — Hardship programs 13 — Deferred purchased gas 12 — Deferred transmission expense 12 — Environmental remediation costs 37 — Other 54 20 Total Current Regulatory Assets 219 80 Non-current Pension and other postretirement benefits cost deferrals 151 125 Pension and other postretirement benefits 1,509 1,101 Storm costs 251 259 Deferred meter replacement costs 34 36 Unamortized losses on reacquired debt 23 25 Environmental remediation costs 271 247 Unfunded future income taxes 549 366 Asset retirement obligation 24 32 Deferred property tax 45 30 Federal tax depreciation normalization adjustment 158 128 Merger capital expense target customer credit 15 10 Debt premium 141 — Contracts for differences 50 — Hardship programs 29 14 Other 64 26 Total Non-current Regulatory Assets $ 3,314 $ 2,399
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, 2016 consisted of: Year Ended December 31, 2016 Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 123 $ 7 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, 2016 consisted of: Year Ended December 31, 2016 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, 2015 and 2014 consisted of: As of December 31, 2015 2014 Health care cost trend rate assumed for next year - Networks 7.50%/7.00% 7.75%/7.25% Health care cost trend rate assumed for next year - ARHI 7.00%/9.00% 7.75%/6.75% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.5 % 4.5 % Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.5 % 4.75 % Year that the rate reaches the ultimate trend rate - Networks 2027 2027 Year that the rate reaches the ultimate trend rate - ARHI 2026 2025
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 9 (7 )
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, 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 511 — 21 490 Partnerships/joint venture interests 84 — — 84 Real estate investments 89 — — 89 Other, principally annuity, fixed income 322 — 4 318 Total $ 1,991 $ 602 $ 408 $ 981 The fair values of pension benefits plan assets, by asset category, as of December 31, 2014 consisted of: As of December 31, 2014 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 48 $ 4 $ 44 $ — U.S. government securities 177 177 — — Common stocks 447 360 87 — Registered investment companies 116 116 — — Corporate bonds 367 23 344 — Preferred stocks 4 — 4 — Common collective trusts 477 — 28 449 Partnership/joint venture interests 79 — — 79 Real estate investments 77 2 — 75 Other, principally annuity, fixed income 351 5 4 342 Total $ 2,143 $ 687 $ 511 $ 945
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, 2015, 2014 and 2013 consisted of: (Millions) 2015 2014 2013 Fair value as of January 1, $ 57 $ 53 $ 5 Gains for the year recognized in operating revenues 33 11 21 Losses for the year recognized in operating revenues (8 ) (1 ) (3 ) Total gains or losses for the period recognized in operating revenues 25 10 18 Gains recognized in OCI 2 — — Losses recognized in OCI (3 ) (3 ) — Total gains or losses recognized in OCI (1 ) (3 ) — Purchases (73 ) 14 47 Settlements (14 ) (26 ) (15 ) Transfers out of Level 3 (a) (13 ) 9 (2 ) Fair value as of December 31, $ (19 ) $ 57 $ 53 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 $ 25 $ 10 $ 18 (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: Unobservable Input Range at December 31, 2015 Risk of non-performance 0.06% - 0.88% Discount rate 1.31% - 2.27% Forward pricing ($ per MW) $3.15 - $11.19
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, 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 11 11 — — Total $ 123 $ 121 $ 2 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2014 consisted of: As of December 31, 2014 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 45 45 — — Common stocks 29 29 — — Mutual funds, other 12 12 — — Total $ 128 $ 126 $ 2 $ —
Level 3 [Member]
Fair Value, Financial instrument Based on Level 3 Reconciliation	Fair value measurements using Level 3 inputs as of December 31, 2015, 2014 and 2013 consisted of: (Millions) Common Collective Trusts Partnership Joint Venture Interests Real Estate Investments Other Investments Total As of December 31, 2013 $ 458 $ 57 $ 67 $ 337 $ 919 Actual return on plan assets: Relating to assets sold during the year 6 — — — 6 Relating to assets still held at the reporting date 5 3 6 5 19 Purchases, sales and settlements (20 ) 19 2 — 1 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
Networks and ARHI [Member]
Obligations and Funded Status	Obligations and funded status of Networks and ARHI as of December 31, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2015 2014 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 2,620 $ 2,316 $ 435 $ 385 Service cost 35 30 5 5 Interest cost 97 110 16 18 Plan participants’ contributions — — 4 4 Plan amendments — — (1 ) — Actuarial (gain) loss (105 ) 439 (31 ) 64 Special termination benefits 2 — — — Benefits paid (158 ) (275 ) (25 ) (41 ) Benefit Obligation as of December 31, 2,491 2,620 403 435 Change in plan assets Fair value of plan assets as of January 1, 2,143 2,223 129 128 Actual return on plan assets (21 ) 163 (4 ) 4 Employer contributions 27 32 21 38 Plan participants’ contributions — — 4 4 Benefits paid (158 ) (275 ) (25 ) (41 ) Withdrawal from VEBA — — (2 ) (4 ) Fair Value of Plan Assets as of December 31, 1,991 2,143 123 129 Funded Status as of December 31, $ (500 ) $ (477 ) $ (280 ) $ (306 )
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, 2015 and 2014 consisted of: Projected Benefit Obligation Exceeds Fair Value of Plan Assets Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets As of December 31, 2015 2014 2015 2014 (Millions) Projected benefit obligation $ 2,491 $ 2,620 $ 2,491 $ 2,620 Accumulated benefit obligation 2,334 2,436 2,334 2,436 Fair value of plan assets 1,991 2,143 1,991 2,143
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, 2015 and 2014 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2015 2014 Discount rate - Networks 4.10 % 3.80 % 4.10 % 3.80 % Discount rate - ARHI 3.90 % 3.90 % 3.90 % 3.90 % Rate of compensation increase - Networks 4.00 % 4.10 % — — The weighted-average assumptions used to determine net periodic benefit cost for Networks and ARHI for the years ended December 31, 2015, 2014 and 2013 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 Discount rate - Networks 3.80 % 4.90 % 4.10 % 3.80 % 4.90 % 4.10 % Discount rate - ARHI 3.90 % 5.00 % 4.00 % 3.90 % 5.00 % 4.00 % Expected long-term return on plan assets - Networks 7.50 % 7.50 % 7.50 % — — — Expected long-term return on plan assets - ARHI 5.50 % 6.90 % 6.50 % 5.75 % 6.50 % 6.25 % Expected long-term return on plan assets - nontaxable trust - Networks — — — 7.50 % 7.50 % 7.50 % Expected long-term return on plan assets - taxable trust - Networks — — — 5.00 % 5.00 % 5.00 % Rate of compensation increase - Networks 4.10 % 4.20 % 4.00 % — — —
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, 2015 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2016 $ 154 $ 26 $ — 2017 156 27 — 2018 159 27 — 2019 161 27 — 2020 163 27 — 2021 - 2025 826 135 1
UIL Holdings [Member]
Schedule of Current and Non-Current Regulatory Assets	Amounts recognized as regulatory assets for the period from December 17, 2015 to December 31, 2015 for UIL consisted of: Pension Benefits Other Postretirement Benefits (Millions) 2015 2015 Net loss 12 —
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 UIL as of December 31, 2015consisted of: Pension Benefits As of December 31, 2015 (Millions) Projected benefit obligation $ 1,018 Accumulated benefit obligation 927 Fair value of plan assets 673
Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations	Components of UIL’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets for the period from December 17, 2015 to December 31, 2015 consisted of: For the period from December 17, 2015 to December 31, 2015 Pension Benefits Other Postretirement Benefits (Millions) Net Periodic Benefit Cost: Service cost $ 1 $ — Interest cost 2 — Expected return on plan assets (2 ) — Net periodic benefit cost $ 1 $ — Other Changes in Plan Assets and Benefit Obligations Recognized as a Regulatory Asset: Net (gain) loss $ — $ — Total Other Changes — — Total Recognized $ 1 $ —
Weighted Average Assumptions Used to Determine Benefit Obligations and Net periodic Benefit Cost	The weighted-average assumptions used to determine benefit obligations for UIL as of December 31, 2015 consisted of: Pension Benefits Other Postretirement Benefits As of December 31, 2015 2015 Discount rate 4.24 % 4.24 % Average wage increase 3.50-3.80% — Health care trend rate (current year) — 7.00%/9.00% Health care trend rate (2019-2028 forward) — 4.50 % The weighted-average assumptions used to determine net periodic benefit cost for UIL for the period from December 17, 2015 to December 31, 2015 consisted of: For the period from December 17, 2015 to December 31, 2015 Pension Benefits Other Postretirement Benefits Discount rate 4.24% 4.24% Average wage increase 3.50-3.80% — Return on plan assets 7.75-8.00% 5.56-8.00% Health care trend rate (current year) — 7.00% Health care trend rate (2019 forward) — 4.50%
UIL Holdings [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 UIL as of December 31, 2015 consisted of: (Millions) Pension Benefits Other Postretirement Benefits Medicare Act Subsidy Receipts 2016 $ 48 $ 7 $ — 2017 50 7 — 2018 51 7 — 2019 53 7 — 2020 54 7 — 2021-2025 295 37 1
UIL Holdings [Member] | Other Postretirement Benefit Plan [Member]
Represents Change in Benefit Obligation, Change in Plan Assets and Respective Funded Status	The following table represents the change in benefit obligation, change in plan assets and the respective funded status of UIL’s pension and other postretirement plans as of December 31, 2015, including purchase price allocation balances. Plan assets and obligations have been measured as of December 31, 2015. Pension Benefits Other Postretirement Benefits (Millions) 2015 2015 Change in Benefit Obligation: Benefit obligation at December 17 $ 1,019 $ 122 Service cost 1 — Interest cost 2 — Benefits paid (including expenses) (4 ) — Benefit obligation at December 31 $ 1,018 $ 122 Change in Plan Assets: Fair value of plan assets at December 17 $ 687 $ 39 Actual return on plan assets (10 ) — Benefits paid (including expenses) (4 ) — Fair value of plan assets at December 31 $ 673 $ 39 Funded Status at December 31: Projected benefits less than plan assets $ (345 ) $ (83 ) Amounts Recognized in the Statement of Financial Position consist of: Non-current liabilities $ (345 ) $ (83 )
Changes in Fair value of Assets as per Hierarchy	The following tables set forth the fair values of UIL’s pension and other postretirement benefits plan assets as of December 31, 2015. Fair Value Measurements December 31, 2015 Level 1 Level 2 Level 3 Total (Millions) Pension assets Mutual funds $ — $ 673 $ — $ 673 Other postretirement benefit assets Mutual funds 32 7 — 39 Total $ 32 $ 680 $ — $ 712
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, 2015, 2014 and 2013 for Networks consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2015 2014 2013 2015 2014 2013 (Millions) Net loss $ 982 $ 1,045 $ 704 $ 76 $ 96 $ 24 Prior service cost (credit) 9 12 16 (49 ) (57 ) (67 )
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, 2015, 2014 and 2013 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2013 2015 2014 2013 Net Periodic Benefit Cost: Service cost $ 35 $ 30 $ 36 $ 4 $ 4 $ 5 Interest cost 95 107 102 15 17 16 Expected return on plan assets (154 ) (161 ) (166 ) (7 ) (7 ) (7 ) Amortization of prior service cost (benefit) 3 4 4 (9 ) (11 ) (14 ) Amortization of net loss 130 94 120 7 — 3 Special termination benefit charge 2 — — — — — Settlement charge 2 — — — — — Net Periodic Benefit Cost 113 74 96 10 3 3 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Settlements $ (2 ) $ — $ — $ — $ — $ — Net loss (gain) 69 434 (244 ) (12 ) 72 (50 ) Amortization of net (loss) (130 ) (94 ) (120 ) (7 ) — (3 ) Current year prior service cost — — — (1 ) — (2 ) Amortization of prior service (cost) benefit (3 ) (4 ) (4 ) 9 11 14 Total Other Changes (66 ) 336 (368 ) (11 ) 83 (41 ) Total Recognized $ 47 $ 410 $ (272 ) $ (1 ) $ 86 $ (38 )
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, 2015, 2014 and 2013 consisted of: (Millions) Pension Benefits Postretirement Benefits As of December 31, 2015 2014 2013 2015 2014 2013 Net Periodic Benefit Cost: Service cost $ — $ — $ — $ 1 $ 1 $ 1 Interest cost 2 2 2 1 1 1 Expected return on plan assets (2 ) (3 ) (3 ) — — — Amortization of prior service cost — — — — 1 1 Amortization of net loss 1 — 1 — 1 — Settlement charge — — 2 — — — Net Periodic Benefit Cost (income) 1 (1 ) 2 2 4 3 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) 4 6 (12 ) (8 ) (5 ) 7 Amortization of net (loss) (1 ) — (3 ) — (1 ) — Amortization of prior service (cost) — — — — (1 ) (1 ) Total Other Changes 3 6 (15 ) (8 ) (7 ) 6 Total Recognized $ 4 $ 5 $ (13 ) $ (6 ) $ (3 ) $ 9

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2015
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) Accumulated OCI for the years ended December 31, 2015, 2014 and 2013 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2012 2013 Change As of December 31, 2013 2014 Change As of December 31, 2014 2015 Change As of December 31, 2015 (Millions) Loss on revaluation of defined benefit plans, net of income tax expense of $0.5 for 2013, $0.6 for 2014 and $2.2 for 2015 $ (27 ) $ 1 $ (26 ) $ 1 $ (25 ) $ 4 $ (21 ) Loss for nonqualified pension plans, net of income tax expense (benefit) of $1.0 for 2013, ($1.9) for 2014 and $1.7 for 2015 (7 ) (1 ) (8 ) (3 ) (11 ) 3 (8 ) 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 and $20.9 for 2015 — — — (2 ) (2 ) 33 31 Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense of $4.6 for 2013, $4.1 for 2014 and $4.9 for 2015 (a) (73 ) 7 (66 ) 5 (61 ) 7 (54 ) Net unrealized (loss) gain on derivatives qualifying as cash flow hedges (73 ) 7 (66 ) 3 (63 ) 40 (23 ) Accumulated Other Comprehensive (Loss) Income $ (107 ) $ 7 $ (100 ) 1 $ (99 ) $ 47 $ (52 ) (a) Reclassification is reflected in the operating expenses line item in the combined and consolidated statements of operations.

Net Income Per Share (Tables)

Net Income Per Share (Tables)	12 Months Ended
	Dec. 31, 2015
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings (loss) per share attributable to AVANGRID, including a reconciliation of the numerators and denominators for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions, except for number of shares and per share data) Numerator: Net income (loss) attributable to AVANGRID $ 267 $ 424 $ (51 ) Denominator: Weighted average number of shares outstanding - basic 254,588,212 252,235,232 252,235,232 Weighted average number of shares outstanding - diluted 254,605,111 252,235,232 252,235,232 Earnings per share attributable to AVANGRID Earnings (Loss) Per Common Share, Basic $ 1.05 $ 1.68 $ (0.20 ) Earnings (Loss) Per Common Share, Diluted $ 1.05 $ 1.68 $ (0.20 )

Grants, Government Incentives56

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2015
Deferred Revenue Disclosure [Abstract]
Schedule of Changes in Deferred Income	The changes in deferred income as of December 31, 2015 and 2014 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2013 1,684 19 1,703 Additions — 4 4 Recognized in income (78 ) (8 ) (86 ) 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

Equity Method Investments (Tabl

Equity Method Investments (Tables)	12 Months Ended
	Dec. 31, 2015
Equity Method Investments And Joint Ventures [Abstract]
Summary of Combined Financial Information	Summarized combined financial information for these equity method investments is as follows: Years ended December 31, 2015 2014 2013 (Millions) Revenue $ 53 $ 72 $ 60 Loss from operations (14 ) — (15 ) Net loss (10 ) — (15 ) As of December 31, 2015 2014 (Millions) Current assets $ 45 $ 11 Non-current assets 929 571 Current liabilities 26 10 Non-current liabilities 223 48 Members’ equity 726 524 Ownership share 50 % 50 % Equity method investment $ 363 $ 262

Other Financial Statements It58

Other Financial Statements Items (Tables)	12 Months Ended
	Dec. 31, 2015
Receivables [Abstract]
Schedule of Other Income and (Expense)	Other income and (expense) for the years ended December 31, 2015, 2014 and 2013 consisted of: Years ended December 31, 2015 2014 2013 (Millions) Allowance for funds used during construction $ 21 $ 17 $ 14 Carrying costs on regulatory assets 28 29 29 Other 6 6 11 Total Other income and (expense) $ 55 $ 52 $ 54
Schedule of Accounts Receivable	Accounts receivable as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Trade receivables $ 1,036 $ 888 Other receivables - 2 Allowance for bad debts (62 ) (49 ) Total Accounts Receivable $ 974 $ 841
Schedule of Change in Allowance For Bad Debts	The change in the allowance for bad debts as of December 31, 2015 and 2014 consisted of: (Millions) As of January 1, 2013 $ 56 Current period provision 37 Write-off as uncollectible (35 ) 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
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Prepaid other taxes $ 130 $ 93 Broker margin and collateral accounts 46 57 Loans to third parties 3 3 Fixed-term deposits 11 25 Other pledged deposits 24 51 Prepaid expenses 53 32 Other 18 27 Total $ 285 $ 288
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Advances received $ 96 $ 87 Accrued salaries 68 76 Short-term environmental provisions 35 36 Collateral deposits received 59 39 Pension and other postretirement 5 5 Other 22 19 Total $ 285 $ 262

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2015
Segment Reporting [Abstract]
Schedule of Segment Information	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 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 Segment information as of and for the year ended December 31, 2013 consisted of: For the year ended December 31, 2013 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,311 $ 1,087 $ (98 ) $ 13 $ 4,313 Revenue - intersegment 8 10 71 (89 ) — Impairment of noncurrent assets — 75 545 — 620 Depreciation and amortization 257 310 26 1 594 Operating income (loss) from continuing operations 703 122 (647 ) 1 179 Adjusted EBITDA 960 507 (76 ) 2 1,393 Earnings (losses) from equity method investments — (7 ) — 4 (3 ) Capital expenditures 906 34 4 — 944 As of December 31, 2013 Property, plant and equipment 7,887 8,302 526 — 16,715 Equity method investments — 278 — — 278 Total assets $ 11,771 $ 11,966 $ 1,495 $ (2,062 ) $ 23,170 (a) Does not represent a segment. I
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Income Before Income Tax	Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Income (Loss) Before Income Tax for the years ended December 31, 2015, 2014 and 2013 is as follows: Years Ended December 31, 2015 2014 2013 (Millions) Consolidated Adjusted EBITDA $ 1,220 $ 1,539 $ 1,393 Less: Impairment of non-current assets 12 25 620 Depreciation and amortization 695 629 594 Interest expense, net of capitalization 267 243 245 Add: Other income and (expense) 55 52 54 Earnings (losses) from equity method investments — 12 (3 ) Consolidated Income (Loss) Before Income Tax $ 301 $ 706 $ (15 )

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2015
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the years ended December 31, 2015, 2014 and 2013 consisted of: Years Ended December 31, 2015 2014 2013 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Financiación, S.A. — $ (1 ) — $ (2 ) — $ (2 ) Iberdrola Renovables Energia, S.L. — (9 ) — (10 ) — (10 ) Iberdrola Canada Energy Services, Ltd — (55 ) — (49 ) 2 (75 ) Iberdrola Ingeniería y Construcción, S.A. U. — — — — 26 — Scottish Power, Ltd — — — — — (6 ) Other 3 (37 ) 12 (30 ) 16 (33 )
Schedule of Related Party Balances	Related party balances as of December 31, 2015 and 2014 consisted of: As of December 31, 2015 2014 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd $ 7 $ (5 ) $ 1 $ — Gamesa Corporación Tecnológica, S.A. 68 (77 ) 33 (223 ) Iberdrola Energy Projects, Inc. 1 (3 ) 15 (15 ) Other — (5 ) 1 (1 )

Quarterly Financial Data (unaud

Quarterly Financial Data (unaudited)	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Quarterly Financial Data (unaudited)	Note 25. Quarterly financial data (unaudited) Selected quarterly financial data for 2015 and 2014 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 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 $ 106 $ 11 $ 54 $ 96 Earnings Per Common Share, Basic and Diluted: (1) $ 0.42 $ 0.04 $ 0.22 $ 0.37 2014 Operating Revenues $ 1,556 $ 938 $ 982 $ 1,118 Operating Income $ 414 $ 132 $ 153 $ 186 Net Income $ 201 $ 62 $ 64 $ 97 Net Income attributable to AVANGRID $ 200 $ 63 $ 64 $ 97 Earnings Per Common Share, Basic and Diluted: (1) $ 0.79 $ 0.25 $ 0.25 $ 0.38 (1) Based on weighted average number of 252 million shares outstanding each quarter, 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, 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.

Quarterly Financial Data (una62

Quarterly Financial Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2015
Selected Quarterly Financial Information [Abstract]
Schedule of Quarterly Financial Data	Selected quarterly financial data for 2015 and 2014 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 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 $ 106 $ 11 $ 54 $ 96 Earnings Per Common Share, Basic and Diluted: (1) $ 0.42 $ 0.04 $ 0.22 $ 0.37 2014 Operating Revenues $ 1,556 $ 938 $ 982 $ 1,118 Operating Income $ 414 $ 132 $ 153 $ 186 Net Income $ 201 $ 62 $ 64 $ 97 Net Income attributable to AVANGRID $ 200 $ 63 $ 64 $ 97 Earnings Per Common Share, Basic and Diluted: (1) $ 0.79 $ 0.25 $ 0.25 $ 0.38

Cash Dividends Paid by Subsid63

Cash Dividends Paid by Subsidiaries (Tables)	12 Months Ended
	Dec. 31, 2015
Avangrid, Inc [Member]
Schedule of Cash Dividends Paid by Subsidiaries	Cash dividends paid by subsidiaries are as follows: Years ended December 31, 2015 2014 2013 (In millions) AVANGRID Networks $ 59 $ 200 $ 110 AVANGRID Renewables 750 — — Other AVANGRID subsidiaries 302 — 12 $ 1,111 $ 200 $ 122

Background and Nature Of Oper64

Background and Nature Of Operations - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015$ / 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 SA [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 ($) $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Retained earnings	$ 1,449				$ 1,182				$ 1,449	$ 1,182
Net Income (Loss)	96	$ 54	$ 11	$ 106	97	$ 64	$ 62	$ 201	267	424	$ (50)
Avangrid, Inc [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Retained earnings	$ 1,449				1,182				1,449	1,182
Net Income (Loss)									$ 267	424	(51)
Correction [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Retained earnings					21					21	21	$ 7
Net Income (Loss)											14
Correction [Member] | Avangrid, Inc [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Retained earnings					$ 21					$ 21
Net Income (Loss)											$ 14

Basis of Presentation - Summary

Basis of Presentation - Summary of Effect of Correction on Consolidated Balance Sheet (Detail) - USD ($) $ in Millions	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013	Dec. 31, 2012
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Accumulated depreciation	$ (6,372)	[1]	$ (5,762)	[2]
Net Property, Plant and Equipment	20,711		17,133		$ 16,715
Total assets	30,743		24,162		23,170
Deferred income taxes	2,798		2,269
Total Other Non-current Liabilities	6,752		5,762
Total Non-current Liabilities	13,642		9,913
Total liabilities	15,677		11,685
Retained earnings	1,449		1,182
Total Stockholders' Equity	15,053		12,461
Total Equity	15,066		12,477		12,051	$ 11,348
Total Liabilities and Equity	30,743		24,162
Energy Equipment [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Net Property, Plant and Equipment	$ 19,373		15,737
As Reported [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Accumulated depreciation			(5,796)
Net Property, Plant and Equipment			17,099
Total assets			24,128
Deferred income taxes			2,256
Total Other Non-current Liabilities			5,749
Total Non-current Liabilities			9,900
Total liabilities			11,672
Retained earnings			1,161
Total Stockholders' Equity			12,440
Total Equity			12,456
Total Liabilities and Equity			24,128
As Reported [Member] | Energy Equipment [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Net Property, Plant and Equipment			15,703
Correction [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Accumulated depreciation			34
Net Property, Plant and Equipment			34
Total assets			34
Deferred income taxes			13
Total Other Non-current Liabilities			13
Total Non-current Liabilities			13
Total liabilities			13
Retained earnings			21		$ 21	$ 7
Total Stockholders' Equity			21
Total Equity			21
Total Liabilities and Equity			34
Correction [Member] | Energy Equipment [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Net Property, Plant and Equipment			$ 34
[1]	Includes accumulated amortization of capitalized leases of $53 million.
[2]	Includes accumulated amortization of capitalized leases of $47 million.

Basis of Presentation - Summa67

Basis of Presentation - Summary of Effect of Correction on Combined and Consolidated Statement of Operations (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization																	$ 695	$ 629	$ 594
Total Operating Expenses																	3,854	3,709	4,134
Operating income	$ 83		$ 161		$ 73		$ 196		$ 186		$ 153		$ 132		$ 414		513	885	179
Loss Before Income Tax																	301	706	(15)
Income tax expense																	34	282	35
Net income (loss)	$ 96		$ 54		$ 11		$ 106		$ 97		$ 64		$ 62		$ 201		$ 267	$ 424	$ (50)
Net Loss Per Common Share, Basic and Diluted:	$ 0.37	[1]	$ 0.22	[1]	$ 0.04	[1]	$ 0.42	[1]	$ 0.38	[1]	$ 0.25	[1]	$ 0.25	[1]	$ 0.79	[1]			$ (0.20)
As Reported [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization																			$ 617
Total Operating Expenses																			4,157
Operating income																			156
Loss Before Income Tax																			(38)
Income tax expense																			26
Net income (loss)																			$ (64)
Net Loss Per Common Share, Basic and Diluted:																			$ (0.26)
Correction [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Depreciation and amortization																			$ (23)
Total Operating Expenses																			(23)
Operating income																			23
Loss Before Income Tax																			23
Income tax expense																			9
Net income (loss)																			$ 14
Net Loss Per Common Share, Basic and Diluted:																			$ (0.06)
[1]	Based on weighted average number of 252 million shares outstanding each quarter, except for fourth quarter of 2015, which is based on weighted average of 262 million shares as a result of the acquisition of UIL

Summary of Significant Accoun68

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accounting Polices [Line Items]
Percentage of tax returns included in taxable income	80.00%
Stock-based compensation expense	$ 6	$ 4.8	$ 7.6
Amount of liability relating to stock-based compensation included in other non-current liabilities	17.5	16.8
Unrecognized costs for stock-based compensation	1
Operations and maintenance	1,808	1,560	1,541
Regulatory liabilities, Current	147	165
Regulatory liabilities, Non-current	$ 1,841	1,229
Percentage of employees covered by collective bargaining agreement	48.00%
Percentage of expiry	1.00%
Reclassifications To Conform2015 Presentation
Accounting Polices [Line Items]
Operations and maintenance		8	$ 11
Regulatory liabilities, Current		12
Regulatory liabilities, Non-current		23
Adjustments For New Accounting Principle, Early Adoption [Member]
Accounting Polices [Line Items]
Debt issuance costs reclassified to non-current debt		27
Deferred taxes reclassified to noncurrent		$ 97
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 Accoun69

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, 2015
Plant [Member] | Wind Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	25 years
Plant [Member] | Minimum [Member] | Combined Cycle Plants [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	30 years
Plant [Member] | Minimum [Member] | Hydroelectric Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	40 years
Plant [Member] | Minimum [Member] | Gas Storage [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	17 years
Plant [Member] | Minimum [Member] | Transport Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	33 years
Plant [Member] | Minimum [Member] | Distribution Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	15 years
Plant [Member] | Maximum [Member] | Combined Cycle Plants [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	35 years
Plant [Member] | Maximum [Member] | Hydroelectric Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	90 years
Plant [Member] | Maximum [Member] | Gas Storage [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	119 years
Plant [Member] | Maximum [Member] | Transport Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	75 years
Plant [Member] | Maximum [Member] | Distribution Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	80 years
Equipment [Member] | Minimum [Member] | Conventional Meters And Measuring Devices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	17 years
Equipment [Member] | Maximum [Member] | Conventional Meters And Measuring Devices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	41 years
Other [Member] | Minimum [Member] | Buildings [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	9 years
Other [Member] | Minimum [Member] | Operations Offices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	5 years
Other [Member] | Minimum [Member] | Computer Software[Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	3 years
Other [Member] | Maximum [Member] | Buildings [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	75 years
Other [Member] | Maximum [Member] | Operations Offices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	32 years
Other [Member] | Maximum [Member] | Computer Software[Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	10 years

Acquisition of UIL - Additional

Acquisition of UIL - Additional Information (Detail) - USD ($)	Dec. 16, 2015	Dec. 31, 2015	Dec. 31, 2014
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
Net income		468,000,000	$ 539,000,000
Fair value of contingent liability		44,000,000
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, Inc [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		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) | 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
Common stock, par value	$ 10.50
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
Net income		(36,000,000)
UIL Holdings [Member] | Avangrid, Inc [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, Inc [Member] | Iberdrola SA [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	252,234,989
UIL Holdings [Member] | Avangrid, Inc [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, 2015	Dec. 31, 2014
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Common shares			308,864,609	252,235,232
Business acquisition, share price			$ 10.50
Shares issued in connection with acquisition			309,490,839
Total consideration		$ 2,873
UIL Holdings [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Common shares	[1]	56,629,377
Business acquisition, share price		$ 50.10	$ 10.50
Subtotal value of common shares		$ 2,837
Other shares	[2]	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	[3]	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	[2]	626,473
Price per share used	[4]	$ 39.60
Subtotal value of shares		$ 25
UIL Holdings [Member] | Performance Shares [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Vesting shares	[5]	211,904
Equity exchange factor		1.2806%
Total shares after applying an equity exchange factor		271,368
Price per share used	[4]	$ 39.60
Subtotal value of shares		$ 11
Total consideration		$ 2,873
[1]	Based on UIL’s common shares outstanding on December 16, 2015
[2]	Based on UIL’s restricted shares vested upon the change in control.
[3]	Based on UIL’s shares of vested restricted stock.
[4]	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 UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.
[5]	Based on UIL’s vested performance shares award.

Acquisition of UIL - Summary 72

Acquisition of UIL - Summary of Fair Value of Purchase Consideration (Detail) (Parenthetical)	Dec. 31, 2015$ / shares
Business Combinations [Abstract]
Business acquisition, share price	$ 10.50

Acquisition of UIL - Summary 73

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 74

Acquisition of UIL - Summary of Components of Estimated Consideration Transferred (Parenthetical) (Detail) - $ / shares		Dec. 31, 2015	Dec. 16, 2015	Dec. 31, 2014
Business Combination Consideration Transferred [Line Items]
Cash paid per common share		$ 0.01		$ 0.01
Common shares outstanding		308,864,609		252,235,232
UIL Holdings [Member]
Business Combination Consideration Transferred [Line Items]
Cash paid per common share			$ 10.50
Common shares outstanding	[1]		56,629,377
[1]	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 - Schedule76

Acquisition of UIL - Schedule of Preliminary Allocation of Purchase Price (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Business Acquisition [Line Items]
Goodwill – consideration transferred in excess of fair value assigned	$ 3,115	$ 1,361
UIL Holdings [Member]
Business Acquisition [Line Items]
Current assets, including cash of $48 million	500
Other investments	114
Property, plant and equipment, net	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 estimated consideration	$ 2,873

Acquisition of UIL - Schedule77

Acquisition of UIL - Schedule of Preliminary Allocation of Purchase Price (Detail) (Parenthetical) $ in Millions	Dec. 31, 2015USD ($)
Business Combinations [Abstract]
Purchase price allocation, cash	$ 48

Industry Regulation - Additiona

Industry Regulation - Additional Information (Detail)

Nov. 06, 2015

Oct. 21, 2015USD ($)

Apr. 02, 2015

Mar. 05, 2015

Jul. 03, 2014

Jan. 22, 2014

Oct. 23, 2013USD ($)MWh

Sep. 01, 2012USD ($)

Dec. 31, 2014

Nov. 30, 2014

Jan. 31, 2014ContractMW

Aug. 31, 2013

Aug. 31, 2010USD ($)

Dec. 31, 2015USD ($)CompanyProjectPlant

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Nov. 03, 2014USD ($)

Jul. 11, 2014USD ($)

Sep. 30, 2012USD ($)

Mar. 31, 2010USD ($)MW

Industry Regulation [Line Items]

Number of networks supply companies | Company

4

Purchase obligation per year

$ 2,470,000,000

Approved return on equity

9.18%

10.50%

Depreciation and amortization

$ 695,000,000

$ 629,000,000

$ 594,000,000

Customer receiving percentage

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 first half of 2015

80.00%

Percentage of standard service customers with wholesale power supply agreements in place for the first half of 2016

30.00%

Public utilities regulatory authority distribution rate

8.75%

Increase (decrease) in distribution rates

9.15%

Modified agreement monthly payment amount

$ 15,400,000

Minimum deferred cost required for offset per month

$ 2,300,000

Requested return on equity base percentage

9.55%

10.00%

9.20%

Applicants requested

0.50%

Common equity ratio maximum dividend restriction threshold to set rates

3.00%

Number of average months used to set rate

13 months

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

10

Basis point added to return on equity

0.25%

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

Number of inter-related transmission projects with portions sited in Connecticut | Project

3

Number of inter related transmission projects | Project

4

Amount of transmission assets

$ 45,000,000

Cumulative amount of deposits

$ 44,600,000

Ratio of equity investment in peaking generation for joint venture

50-50

Number of peaking generation plants | Plant

2

New York Transco [Member]

Industry Regulation [Line Items]

Customer receiving percentage

60.00%

20.00%

Amount of regulatory costs requested for approval

$ 1,700,000,000

Equity contribution amount over the period 2015 through 2018

$ 183,000,000

Requested return on equity base percentage

10.60%

Requested return on equity basis points incentive

1.50%

Maximum [Member]

Industry Regulation [Line Items]

Approved return on equity

11.74%

FERC [Member]

Industry Regulation [Line Items]

Approved return on equity

10.57%

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

Exposure limit of storm cost

$ 3,000,000

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

$ 28,000,000

NYSEG [Member]

Industry Regulation [Line Items]

Depreciation and amortization

$ 15,200,000

Excess depreciation reserve

$ 303,900,000

Depreciation amortization period

20 years

RGE [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%

Customer receiving percentage

50.00%

Return on equity

9.50%

RGE Electric [Member]

Industry Regulation [Line Items]

Approved return on equity

9.00%

Equity Ratio

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

RGE Electric [Member] | Maximum [Member]

Industry Regulation [Line Items]

Reliability support service agreement final payment

2,300,000

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

Industry Regulation [Line Items]

Amortization Of Deferred Storm Cost

$ 2,500,000

RGE Gas [Member]

Industry Regulation [Line Items]

Approved return on equity

9.00%

Equity Ratio

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

Solicitation period obligations will phase-in

6 years

Maximum annual commitment level obligation after year six

$ 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.

Ginna Nuclear Power Plant LLC [Member]

Industry Regulation [Line Items]

Cumulative Loss

$ (100,000,000)

Percentage of revenue entitled

30.00%

30.00%

One time payment

$ 11,500,000

RGE & GNPP [Member]

Industry Regulation [Line Items]

Modified agreement monthly payment amount

15,400,000

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] | Electric Distribution and Transmission [Member]

Industry Regulation [Line Items]

Revenue requirements for equity investment in peaking generation

29,500,000

GenConn Middletown [Member] | Electric Distribution and Transmission [Member]

Industry Regulation [Line Items]

Revenue requirements for equity investment in peaking generation

$ 36,500,000

Industry Regulation - Delivery

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

Regulatory Assets and Liabili80

Regulatory Assets and Liabilities - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Station	Dec. 31, 2014USD ($)
Regulatory Assets And Liabilities [Line Items]
Unrecorded Regulatory Assets	$ 2,825
Number of nuclear generating stations | Station	2
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%
NYSEG [Member]
Regulatory Assets And Liabilities [Line Items]
Annual amortization of regulatory items	$ 16.5
Deferred storm costs, (under) or over spending	$ (9)	$ 5
NYSEG [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period	5 years
Regulatory Assets	$ 247	241
NYSEG [Member] | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period	10 years
CMP Distribution [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred storm costs, (under) or over spending	$ (6)	15
Recovery of deferred storm costs	$ 28
Deferred storm costs recovery period	24 months
CMP Distribution [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory Assets	$ 12	$ 32

Regulatory Assets and Liabili81

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Asset [Line Items]
Regulatory Assets, current	$ 219	$ 80
Regulatory Assets, noncurrent	3,314	2,399
Pension And Other Post Retirement Benefits Deferrals [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	8
Regulatory Assets, noncurrent	151	125
Pension And Other Postretirement Benefits [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	13
Regulatory Assets, noncurrent	1,509	1,101
Storm Costs
Regulatory Asset [Line Items]
Regulatory Assets, current	8	14
Regulatory Assets, noncurrent	251	259
Temporary Supplemental Assessment Surcharge [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	7	12
Hedges Loss [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	37	34
Contracts For Differences [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	18
Regulatory Assets, noncurrent	50
Hardship Programs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	13
Regulatory Assets, noncurrent	29	14
Deferred Purchased Gas [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	12
Deferred Transmission Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	12
Environmental Restoration Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	37
Regulatory Assets, noncurrent	271	247
Other [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	54	20
Regulatory Assets, noncurrent	64	26
Deferred Meter Replacement Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	34	36
Unamortized Loss On Reacquired Debt [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	23	25
Future Income Tax [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	549	366
Asset Retirement Obligation Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	24	32
Deferred Property Tax Asset [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	45	30
Federal Tax Depreciation Normalization Adjustment [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	158	128
Merger Capital Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	15	$ 10
Debt Premium [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	$ 141

Regulatory Assets and Liabili82

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 147	$ 165
Regulatory liabilities including deferred income taxes, noncurrent	1,841	1,229
Deferred income taxes regulatory	519	433
Regulatory liabilities including deferred income taxes, noncurrent	2,360	1,662
Support Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	16	18
Plant Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities		13
Non By Passable Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	7	19
Energy Efficiency Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	33	34
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	16	23
Yankee DOE Phase One [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	5	23
Merger Related Rate Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	20
Regulatory liabilities including deferred income taxes, noncurrent	24
Revenue Decoupling Mechanism [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	14	8
Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	30	21
Regulatory liabilities including deferred income taxes, noncurrent	93	58
Accrued Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	1,084	721
Asset Sale Gain Account [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	8	19
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	116	81
Economic Development [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	36	33
Merger Capital Expense [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	17	17
Pension And Other Postretirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	90	50
Positive Benefit Adjustment [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	51	51
New York State Tax Rate Change [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	17	16
Post Term Amortization [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	25	20
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	31	24
Deferred Property Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	15	51
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	32	25
Carrying Costs On Deferred Income Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	31	20
Rate Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	21	23
Accumulated Deferred Investment Tax Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	10
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	13
Middletown/Norwalk Local Transmission Network Service Collections [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	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	42	$ 10
Unfunded Future Income Taxes [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	27
Non-Firm Margin Sharing Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	$ 8

Goodwill and Intangible asset83

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Detail) - USD ($) $ in Millions		Dec. 31, 2015	Dec. 31, 2014
Goodwill [Line Items]
Goodwill		$ 3,115	$ 1,361
Network [Member]
Goodwill [Line Items]
Goodwill		2,733	979
Renewables [Member]
Goodwill [Line Items]
Goodwill		380	380
Other [Member]
Goodwill [Line Items]
Goodwill	[1]	$ 2	$ 2
[1]	Does not represent a reportable segment. It mainly includes Corporate and company eliminations.

Goodwill and Intangible asset84

Goodwill and Intangible assets - Additional Information (Detail)	12 Months Ended
	Dec. 31, 2015USD ($)Segment	Dec. 16, 2015USD ($)	Dec. 31, 2014USD ($)Segment	Dec. 31, 2013USD ($)	Dec. 31, 2002USD ($)	Dec. 31, 2000USD ($)
Goodwill [Line Items]
Number of reporting units | Segment	3		2
Impairment of goodwill	$ 0		$ 0
Amortization expense	$ 54,000,000		66,000,000	$ 72,000,000
Gas Storage Rights [Member]
Goodwill [Line Items]
Finite lived intangible assets useful economic life	40 years
Impairment of intangible assets	$ 6,500,000
Wind Development [Member]
Goodwill [Line Items]
Impairment of intangible assets				$ 42,000,000
UIL Holdings [Member]
Goodwill [Line Items]
Goodwill		$ 1,754,000,000
Other [Member]
Goodwill [Line Items]
Goodwill, gross	2,000,000		2,000,000
Network [Member]
Goodwill [Line Items]
Goodwill, gross	2,733,000,000		2,733,000,000
Goodwill, period increase	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
Renewables [Member]
Goodwill [Line Items]
Estimated fair value exceeds carrying value, percentage	1.55%		1.00%	11.00%
Gas [Member]
Goodwill [Line Items]
Impairment of goodwill				$ 163,000,000
Goodwill, fair value				$ 0

Goodwill and Intangible asset85

Goodwill and Intangible assets - Summary of Intangible Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 923	$ 955
Accumulated Amortization	(367)	(386)
Net Carrying Amount	556	569
Gas Storage Rights [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	324	325
Accumulated Amortization	(116)	(117)
Net Carrying Amount	208	208
Wind Development [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	584	574
Accumulated Amortization	(243)	(220)
Net Carrying Amount	341	354
Other [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	15	56
Accumulated Amortization	(8)	(49)
Net Carrying Amount	$ 7	$ 7

Goodwill and Intangible asset86

Goodwill and Intangible assets - Schedule of Amortization Expense (Detail) $ in Millions	Dec. 31, 2015USD ($)
Goodwill And Intangible Assets Disclosure [Abstract]
2,016	$ 27
2,017	25
2,018	24
2,019	26
2,020	$ 25

Property, Plant and Equipment87

Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2015		Dec. 31, 2014		Dec. 31, 2013
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	$ 25,745	[1]	$ 21,499	[2]
Less: accumulated depreciation	(6,372)	[3]	(5,762)	[4]
Net Property, Plant and Equipment	20,711		17,133		$ 16,715
Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	14,996	[1]	11,002	[2]
Less: accumulated depreciation	(3,727)	[3]	(3,491)	[4]
Net Property, Plant and Equipment	12,363		8,389
Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	10,749	[1]	10,497	[2]
Less: accumulated depreciation	(2,645)	[3]	(2,271)	[4]
Net Property, Plant and Equipment	8,348		8,744
Electric Generation, Distribution and Transmission Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	21,564		18,423
Electric Generation, Distribution and Transmission Equipment [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	11,506		8,625
Electric Generation, Distribution and Transmission Equipment [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	10,058		9,798
Natural Gas, Transportation and Distribution Equipment [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	3,324		2,371
Natural Gas, Transportation and Distribution Equipment [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	2,673		1,723
Natural Gas, Transportation and Distribution Equipment [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	651		648
Other Common Operating Property [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	857		705
Other Common Operating Property [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	817		654
Other Common Operating Property [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Property, plant and equipment, at cost	40		51
Energy Equipment [Member]
Property Plant And Equipment [Line Items]
Net Property, Plant and Equipment	19,373		15,737
Energy Equipment [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Net Property, Plant and Equipment	11,269		7,511
Energy Equipment [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Net Property, Plant and Equipment	8,104		8,226
Construction In Progress [Member]
Property Plant And Equipment [Line Items]
Net Property, Plant and Equipment	1,338		1,396
Construction In Progress [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Net Property, Plant and Equipment	1,094		878
Construction In Progress [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Net Property, Plant and Equipment	$ 244		$ 518
[1]	Includes capitalized leases of $178 million primarily related to electric generation, distribution, transmission and other.
[2]	Includes capitalized leases of $158 million primarily related to electric generation, distribution, transmission and other.
[3]	Includes accumulated amortization of capitalized leases of $53 million.
[4]	Includes accumulated amortization of capitalized leases of $47 million.

Property, Plant and Equipment -

Property, Plant and Equipment - (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Property Plant And Equipment [Line Items]
Capital lease obligations	$ 87	$ 81
Accumulated Capitalized Interest Costs	53	47
Electric Generation, Distribution and Transmission Equipment [Member]
Property Plant And Equipment [Line Items]
Capital lease obligations	$ 178	$ 158

Property, Plant and Equipment89

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Property Plant And Equipment [Line Items]
Interest costs capitalized	$ 13	$ 12	$ 9
Tangible asset impairment charges	12	24	33
Depreciation	$ 641	$ 563	522
Gas Storage Projects And Other Facilities Under Construction
Property Plant And Equipment [Line Items]
Tangible asset impairment charges			$ 382

Asset Retirement Obligations-Re

Asset Retirement Obligations-Reconciliation of ARO (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$ 234	$ 209
Liabilities settled during the year	(16)	(1)
Liabilities incurred during the year		6
Accretion expense	14	14
Revisions in estimated cash flows	(48)	6
Ending Balance	$ 184	$ 234

Asset Retirement Obligations -

Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted Cash	$ 1.8	$ 1.7
Estimated annual reduction in expense upon revision	$ 5

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Detail) - USD ($) $ in Millions	Apr. 30, 2015	Dec. 31, 2015	Dec. 31, 2014	Jan. 31, 2015
Debt Instrument [Line Items]
Long-Term Debt		$ 4,674	$ 2,585	$ 150
Capital lease obligations		87	81
Unamortized debt (costs) premium, net		25	29
Current portion of debt		206	148
Total Non-current Debt		$ 4,530	2,489
First Mortgage Bonds - Fixed [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start		2,016
Debt Instrument, Maturity Date, End		2,045
Long-Term Debt		$ 1,815	$ 1,405
Debt Instrument, Interest Rate, Minimum		3.07%	3.07%
Debt Instrument, Interest Rate, Maximum		10.60%	8.00%
Unsecured Pollution Control Notes - Fixed [Member]
Debt Instrument [Line Items]
Debt instrument maturity year	2,020	2,020
Long-Term Debt	$ 200	$ 200	$ 132
Debt Instrument, Interest Rate, Minimum		2.00%	2.125%
Debt Instrument, Interest Rate, Maximum		2.375%	2.25%
Unsecured Pollution Control Notes – Variable [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start		2,032
Debt Instrument, Maturity Date, End		2,034
Long-Term Debt		$ 219	$ 159
Debt Instrument, Interest Rate, Minimum		0.195%	0.03%
Debt Instrument, Interest Rate, Maximum		1.181%	0.461%
Other Various Non-current Debt - Fixed [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start		2,016
Debt Instrument, Maturity Date, End		2,045
Long-Term Debt		$ 2,440	$ 889
Debt Instrument, Interest Rate, Minimum		2.89%	3.24%
Debt Instrument, Interest Rate, Maximum		10.48%	10.48%
Obligations Under Capital Leases [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start		2,020
Debt Instrument, Maturity Date, End		2,023
Debt Instrument, Interest Rate, Minimum		4.00%	4.00%
Debt Instrument, Interest Rate, Maximum		4.44%	4.44%

Debt - Schedule of Long-term 93

Debt - Schedule of Long-term Debt (Parenthetical) (Detail) $ in Millions	Dec. 31, 2015USD ($)
First Mortgage Bonds - Fixed [Member]
Debt Instrument [Line Items]
Bond pledged as collateral	$ 5,682

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($)	Apr. 30, 2015	Dec. 31, 2015	Jan. 31, 2015	Dec. 31, 2014	May. 31, 2012	Nov. 30, 2011	Aug. 31, 2011	Jul. 31, 2011
Debt Instrument [Line Items]
Long-Term Debt		$ 4,674,000,000	$ 150,000,000	$ 2,585,000,000
Estimated fair value of debt		$ 4,985,000,000		2,962,000,000
Iberdrola Financiacion, S.A. Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity							$ 600,000,000
Credit facility, expiration date		Oct. 28, 2015
Joint Utility Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity								$ 600,000,000
Credit facility, covenant terms		In the Joint Utility Facility each joint borrower covenants not to permit, without the lender’s consent, its ratio of total indebtedness to total capitalization to exceed 0.65 to 1.00 at any time.
Ratio Of indebtedness to capitalization		65.00%
Credit facility, expiration date		Jul. 31, 2018
Credit facility, fees description		Each borrower pays a facility fee ranging from fifteen to twenty basis points annually depending on the rating of its unsecured debt
Outstanding letters of credit		$ 14,000,000		14,000,000
Amounts outstanding under the credit facility		$ 0		0
Avangrid Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity					$ 300,000,000
Credit facility, termination date		2019-05
Credit facility, annual fee		$ 700,000
Credit facility, covenant terms		The revolving credit facility contains a covenant that requires us to maintain a ratio of consolidated indebtedness to consolidated total capitalization that does not exceed 0.65 to 1.00 at any time
Ratio Of indebtedness to capitalization		65.00%
Credit facility, expiration date		May 31, 2019
Amounts outstanding under the credit facility					$ 300,000,000
Commercial Paper [Member] | Joint Utility Revolving Credit Facility [Member]
Debt Instrument [Line Items]
Amounts outstanding under the credit facility		$ 0		0
Commercial Paper [Member] | Joint Utility Revolving Credit Facility [Member] | CMP Distribution [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		200,000,000
Commercial Paper [Member] | Joint Utility Revolving Credit Facility [Member] | NYSEG [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity		$ 200,000,000
UIL Credit Facility [Member]
Debt Instrument [Line Items]
Interest rate on outstanding loans		1.57%
Credit facility maximum borrowing capacity						$ 400,000,000
Credit facility, covenant terms		The UIL Credit Facility contains a covenant that requires each borrower to maintain a ratio of consolidated indebtedness to consolidated total capitalization that does not exceed 0.65 to 1.00 at any time.
Ratio Of indebtedness to capitalization		65.00%
Credit facility, expiration date		Nov. 30, 2016
Outstanding letters of credit		$ 4,000,000
Amounts outstanding under the credit facility		163,000,000
UIL Credit Facility [Member] | UI [Member]
Debt Instrument [Line Items]
Available credit under the Credit Facility						250,000,000
UIL Credit Facility [Member] | Connecticut Natural Gas Corporation (CNG) [Member]
Debt Instrument [Line Items]
Available credit under the Credit Facility						150,000,000
UIL Credit Facility [Member] | Gas Companies [Member]
Debt Instrument [Line Items]
Available credit under the Credit Facility						25,000,000
UIL Credit Facility [Member] | The Berkshire Gas Company [Member]
Debt Instrument [Line Items]
Available credit under the Credit Facility						$ 25,000,000
Unsecured Pollution Control Notes - Fixed [Member]
Debt Instrument [Line Items]
Long-Term Debt	$ 200,000,000	$ 200,000,000		132,000,000
Debt instrument maturity year	2,020	2,020
Unsecured Pollution Control Notes – Variable [Member]
Debt Instrument [Line Items]
Long-Term Debt		$ 219,000,000		159,000,000
Unsecured Pollution Control Notes – Variable [Member] | Level 3 [Member]
Debt Instrument [Line Items]
Estimated fair value of debt		$ 204,000,000		$ 145,000,000
Tranche One [Member]
Debt Instrument [Line Items]
Long-Term Debt			$ 65,000,000
Debt instrument maturity year		2,025
Debt instrument, coupon rate			3.15%
Tranche Two [Member]
Debt Instrument [Line Items]
Long-Term Debt			$ 20,000,000
Debt instrument maturity year		2,030
Debt instrument, coupon rate			3.37%
Tranche Three [Member]
Debt Instrument [Line Items]
Long-Term Debt			$ 65,000,000
Debt instrument maturity year		2,045
Debt instrument, coupon rate			4.07%
2.375% Interest Notes [Member] | Unsecured Pollution Control Notes - Fixed [Member]
Debt Instrument [Line Items]
Long-Term Debt	$ 99,000,000
Interest rate on outstanding loans	2.375%
2.00% Interest Notes [Member] | Unsecured Pollution Control Notes - Fixed [Member]
Debt Instrument [Line Items]
Long-Term Debt	$ 101,000,000
Interest rate on outstanding loans	2.00%

Debt - Schedule of Maturities a

Debt - Schedule of Maturities and Repayments of Long-term Debt (Detail) $ in Millions	Dec. 31, 2015USD ($)
Debt Disclosure [Abstract]
2,016	$ 206
2,017	302
2,018	162
2,019	354
2,020	721
Total	$ 1,745

Fair Value of Financial Instr96

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 177	$ 227
Derivative financial instruments, liabilities	(185)	(141)
Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(351)	(632)
Derivative financial instruments, liabilities	267	632
Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	39	33
Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	68	89
Derivative financial instruments, liabilities	(14)	(36)
Derivative Financial Instrument Power [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(71)	(53)
Derivative financial instruments, liabilities	55	53
Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	80	138
Derivative financial instruments, liabilities	(72)	(102)
Derivative Financial Instrument Gas [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(280)	(579)
Derivative financial instruments, liabilities	212	579
Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	29
Derivative financial instruments, liabilities	(96)
Derivative Financial Instrument Other [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	(3)	(3)
Fair Value, Inputs, Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	277	29
Derivative financial instruments, liabilities	(236)	(65)
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	39	33
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	10	11
Derivative financial instruments, liabilities	(43)	(40)
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	267	18
Derivative financial instruments, liabilities	(193)	(25)
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	106	721
Derivative financial instruments, liabilities	(52)	(656)
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	81	83
Derivative financial instruments, liabilities	(12)	(42)
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	25	638
Derivative financial instruments, liabilities	(40)	(614)
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	145	109
Derivative financial instruments, liabilities	(164)	(52)
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	48	48
Derivative financial instruments, liabilities	(14)	(7)
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	68	61
Derivative financial instruments, liabilities	(51)	(42)
Level 3 [Member] | Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	29
Derivative financial instruments, liabilities	(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)	$ (3)

Fair Value of Financial Instr97

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Debt Instrument Fair Value Carrying Value [Abstract]
Fair value as of January 1,		$ 57	$ 53	$ 5
Gains for the year recognized in operating revenues		33	11	21
Losses for the year recognized in operating revenues		(8)	(1)	(3)
Total gains or losses for the period recognized in operating revenues		25	10	18
Gains recognized in OCI		2
Losses recognized in OCI		(3)	(3)
Total gains or losses recognized in OCI		(1)	(3)
Purchases		(73)	14	47
Settlements		(14)	(26)	(15)
Transfers out of Level 3	[1]	(13)	9	(2)
Fair value as of December 31,		(19)	57	53
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		$ 25	$ 10	$ 18
[1]	(a) Transfers out of Level 3 were the result of increased observability of market data.

Fair Value of Financial Instr98

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	12 Months Ended
	Dec. 31, 2015$ / MMBTU$ / MWh
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Instruments	Fixed price power and gas swaps with delivery period > two years
Instrument Description	Transactions with delivery periods exceeding two years
Valuation Technique	Transactions are valued against forward market prices on a discounted basis
Valuation Inputs	Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products
CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	NYMEX ($/MMBtu)
CME SWAPS MARKETS (NYMEX) [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	4.56
CME SWAPS MARKETS (NYMEX) [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	7.37
CME SWAPS MARKETS (NYMEX) [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	1.76
SP15 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	SP15 ($/MWh)
SP15 [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	46.82
SP15 [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	80.28
SP15 [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	19.75
Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Mid C ($/MWh)
Mid C [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	37.93
Mid C [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	83.93
Mid C [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	6.75
Cinergy [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Cinergy ($/MWh)
Cinergy [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	37.73
Cinergy [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	77.49
Cinergy [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	19.98

Fair Value of Financial Instr99

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, 2015$ / MWh
Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.06%
Discount rate	1.31%
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	0.88%
Discount rate	2.27%
Forward pricing ($ per MW)	11.19

Derivative Instruments and H100

Derivative Instruments and Hedging - Additional Information (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets			$ (74)	$ (175)	$ 27
Derivative financial instruments, assets			177	227
Gross Amounts of Recognized Liabilities			185	141
Regulatory liabilities			19.8
Reclassification to net income of losses on cash flow hedges	[1]		7	5	7
UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets			29
Regulatory Assets			68
Gross Amounts of Recognized Liabilities			96
Regulatory liabilities			$ 1
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			$ 1
Gross Amounts of Recognized Liabilities			61
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities			3	37
Net derivative losses related to discontinued cash flow hedges	[2]		(3)	(4)
Network [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges			8.6	8.9	11.2
Unrealized gain(loss) from hedging activities reported on OCI			$ (2.7)
Derivative Instruments Gain Loss To Be Reclassified From Accumulated Oci Into Interest Expense During Next Twelve Months			24 months
Network [Member] | Cash Flow Hedging [Member] | Scenario Forecast
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification to net income of losses on cash flow hedges		$ 8.1
Network [Member] | Electricity Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets			$ (34.3)	(28.8)
Gain (Loss) reclassified from regulatory assets and liabilities into income			46.9	21.3	2.2
Network [Member] | Natural Gas Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets			(3.1)	(4.7)
Gain (Loss) reclassified from regulatory assets and liabilities into income			6.3	2.2	1.8
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			84.9	93.5	$ 102.5
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets			62
Gross Amounts of Recognized Liabilities			9
Gain Recognized in OCI Derivatives Effective Portion	[3]		57
Cash Collateral Pledged			15	73
Renewables and Gas Activities [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain(loss) from hedging activities reported on OCI			$ 43.5
Derivative Instruments Gain Loss To Be Reclassified From Accumulated Oci Into Interest Expense During Next Twelve Months			12 months
Ineffective portion of Cash flow hedge			$ 4.8
Gain Recognized in OCI Derivatives Effective Portion			2.3
Counter Party [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities			39.7
Cash collateral used to offset against net derivative positions			84
Cash Collateral Pledged			0.1	$ 0.2
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			$ 18
[1]	Reclassification is reflected in the operating expenses line item in the combined and consolidated statements of operations.
[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 combined and consolidated statements of operations.
[3]	Changes in OCI are reported on a pre-tax basis.

Derivative Instruments and H101

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

Derivative Instruments and H102

Derivative Instruments and Hedging - Net Notional Volume (Detail)	Dec. 31, 2015MWhDTHgal	Dec. 31, 2014MWhDTHgal
Network [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	6,700,000	6,600,000
Network [Member] | Natural Gas Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	4,800,000	3,800,000
Network [Member] | Fleet Fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | gal	3,800,000	2,800,000
Renewables and Gas Activities [Member] | Long [Member] | Foreign Exchange Forward [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	4,000,000
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	2,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	6,000,000	7,000,000
Renewables and Gas Activities [Member] | Natural Gas and Other fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	332,000,000	275,000,000
Renewables and Gas Activities [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	7,000,000	8,000,000
Renewables and Gas Activities [Member] | Basis Swap [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	67,000,000	160,000,000
Renewables and Gas Activities [Member] | Basis Swap [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	80,000,000	161,000,000

Derivative Instruments and H103

Derivative Instruments and Hedging - Locations and Amounts of Derivatives Designated as Hedging (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets	$ 177	$ 227
Derivative financial instruments, liabilities	(185)	(141)
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities	(3)	(37)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets	62
Derivative financial instruments, liabilities	(9)
Commodity Contract [Member] | Network [Member] | Electricity Derivatives [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities		(20)
Commodity Contract [Member] | Network [Member] | Electricity Derivatives [Member] | Other liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities		(9)
Commodity Contract [Member] | Network [Member] | Natural Gas Derivatives [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities		(4)
Commodity Contract [Member] | Network [Member] | Natural Gas Derivatives [Member] | Other liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities		(1)
Commodity Contract [Member] | Network [Member] | Fleet Fuel Contracts [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities	(2)	$ (3)
Commodity Contract [Member] | Network [Member] | Fleet Fuel Contracts [Member] | Other liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities	(1)
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Electricity Derivatives [Member] | Current assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets	2
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Electricity Derivatives [Member] | Other assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets	1
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Natural Gas Derivatives [Member] | Current assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets	50
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Natural Gas Derivatives [Member] | Other assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets	9
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Natural Gas Derivatives [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, liabilities	$ (9)

Derivative Instruments and H104

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[1]	$ (3)	$ (4)
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[1]	(12)	(10)	$ (12)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Recognized in OCI Derivatives Effective Portion	[2]	57
Gain Reclassified from Accumulated OCI Income Effective Portion	[2]	(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	[1]	(9)	(9)	(11)
Commodity Contract [Member] | Network [Member] | Operating expenses [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[1]	(3)	(4)
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[1]	(3)	$ (1)	$ (1)
Commodity Contract [Member] | Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Recognized in OCI Derivatives Effective Portion	[2]	57
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	[2]	$ (2)
[1]	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 combined and consolidated statements of operations.
[2]	Changes in OCI are reported on a pre-tax basis.

Derivative Instruments and H105

Derivative Instruments and Hedging - Offsetting Derivative Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Assets	$ 10	$ 11
Gross Amounts Offset in the Balance Sheet	(10)	(11)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Assets	489	847
Gross Amounts Offset in the Balance Sheet	(341)	(620)
Net Amounts of Assets Presented in the Balance Sheet	148	227
Financial Instruments	(36)	(66)
Cash Collateral Pledged	(15)	(73)
Net Amount	$ 97	$ 88

Derivative Instruments and H106

Derivative Instruments and Hedging - Offsetting Derivative Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities	$ (49)	$ (48)
Gross Amounts Offset in the Balance Sheet	46	11
Net Amounts of Liabilities Presented in the Balance Sheet	(3)	(37)
Cash Collateral Pledged		37
Net Amount	(3)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities	(307)	(724)
Gross Amounts Offset in the Balance Sheet	221	620
Net Amounts of Liabilities Presented in the Balance Sheet	(86)	(104)
Financial Instruments	36	66
Cash Collateral Pledged	4	1
Net Amount	$ (46)	$ (37)

Derivative Instruments and H107

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 62	$ 123
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	32	48
Long [Member] | Foreign Exchange Forward [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(1)	(3)
Long [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(13)	(12)
Long [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	10	54
Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	1	(4)
Short [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	35	44
Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ (2)	$ (4)

Derivative Instruments and H108

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	$ (25)	$ 123	$ (24)
Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	6	(9)	2
Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(5)	9	(1)
Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net		(2)	(4)
Trading Derivatives [Member] | Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(26)	125	(21)
Non-Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	29	36	4
Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(8)	(8)	9
Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(5)	15	(2)
Non-Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	24	30	(19)
Non-Trading Derivatives [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	$ 18	$ (1)	$ 16

Commitments and Contingent L109

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

Mar. 25, 2016USD ($)

Mar. 22, 2016

Nov. 06, 2015USD ($)

Oct. 21, 2015USD ($)

Mar. 05, 2015USD ($)

Dec. 31, 2014USD ($)

Jul. 31, 2014

Jan. 22, 2014

Sep. 03, 2013USD ($)

Dec. 26, 2012

Nov. 30, 2013USD ($)

Apr. 30, 2013USD ($)

Dec. 31, 2012USD ($)

Dec. 31, 2015USD ($)ContractorUnitMW

Dec. 31, 2014USD ($)

Dec. 31, 2013USD ($)

Dec. 31, 2012USD ($)

Loss Contingencies [Line Items]

Requested return on equity base percentage

9.55%

10.00%

9.20%

Customer receiving percentage

50.00%

50.00%

One-time gross plant investment disallowance

$ 6,000

$ 19,950

Investment phase in amount

$ 10,000

Approved return on equity

9.18%

10.50%

Disclosure of Rate Matters

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

Regulatory liabilities

$ 1,229,000

$ 1,841,000

$ 1,229,000

Spent fuel litigation damages awarded, value

$ 235,400

$ 160,000

Adjustment regulatory deferral and earning sharing accruals

$ 9,800

Staff issue settlement reserve

3,400

3,400

Customer share of earnings sharing

2,400

Operating lease expenses

47,700

48,700

$ 67,600

Contingent rent payment for electricity generation facility

$ 22,200

20,400

$ 20,600

Sale leaseback transaction, date

2013-04

Sale Leaseback Transaction Initial Cash Receipt

$ 110,000

Sale leaseback transaction, lease terms

P15Y

Sale Leaseback Transaction Asset Repurchase Terms

P10Y

Sale of ownership interest percent

10.00%

Proceeds from sale of ownership Interest

$ 19,600

Modified agreement monthly payment amount

$ 15,400

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

Property, Plant and Equipment [Member]

Loss Contingencies [Line Items]

Future purchase commitment

$ 616,000

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 (six 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

Power purchase commitment | MW

55

Period of purchase commitment

12 months

Power purchase commitment, remaining period

6 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 sales commitments [Member]

Loss Contingencies [Line Items]

Purchase power, description

Power sales commitments include: (i) a 55MW Biomass off-take agreement for 12 years (six 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

6 months

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

Loss Contingencies [Line Items]

Power purchase commitment | MW

34.4

Support Services [Member] | Coal Fired Generating Station

Loss Contingencies [Line Items]

Operating lease expenses

$ 25,500

$ 19,800

Number of Coal-Fired Generating Unit | Unit

2

Middletown/Norwalk Transmission Projects [Member]

Loss Contingencies [Line Items]

Amount sought for change order requests

$ 33,300

Percentage of general contractor mark-up on approved subcontractor change order claims

10.00%

Amount of general contractor mark up on approved subcontractor change order claims

$ 2,300

Subcontractors responsible for civil construction | Contractor

2

Revised estimate for change order requests

$ 7,700

Connecticut Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Court of Federal Claims award

40,300

40,300

Spent fuel litigation damages awarded, value

126,300

Maine Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Court of Federal Claims award

$ 65,000

65,000

Spent fuel litigation damages awarded, value

37,700

CMP Distribution [Member]

Loss Contingencies [Line Items]

Share of the award credited back to customers

28,200

$ 36,500

Period of purchase commitment

20 years

UI [Member]

Loss Contingencies [Line Items]

Share of the award credited back to customers

$ 3,800

Yankee Atomic Energy Corporation [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

73,300

United Illuminating Company [Member]

Loss Contingencies [Line Items]

Share of the award credited back to customers

12,000

United Illuminating Company (UI)

Loss Contingencies [Line Items]

Period of purchase commitment

21 years

United Illuminating Company (UI) | Middletown/Norwalk Transmission Projects [Member]

Loss Contingencies [Line Items]

Damages amount paid to customer

$ 1,300

RGE Electric [Member]

Loss Contingencies [Line Items]

Customer receiving percentage

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%

Subsequent Event [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 76,800

Subsequent Event [Member] | Connecticut Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

32,600

Subsequent Event [Member] | Maine Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

24,600

Subsequent Event [Member] | Yankee Atomic Energy Corporation [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 19,600

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

37,800

Minimum [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 82,000

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

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 21,400

Complaint One [Member]

Loss Contingencies [Line Items]

Regulatory liabilities

$ 23,900

Complaint Two [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.70%

Regulatory liabilities

23,900

Complaint Two [Member] | Maximum [Member] | Subsequent Event [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Complaint Three [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.84%

Regulatory liabilities

$ 4,200

Complaint Three [Member] | Maximum [Member] | Subsequent Event [Member]

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Complaint Two and Three [Member]

Loss Contingencies [Line Items]

Disclosure of Rate Matters

On November 24, 2014, FERC accepted the third complaint, established a refund effective date of July 31, 2014, and set for consolidated hearing with Complaint II 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. 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 New England transmission owners 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 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 late 2016 or early 2017.

Reasonably possible loss, in additional reserve, net of tax

$ 10,200

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

Loss Contingencies [Line Items]

Approved return on equity

10.57%

Unfavorable Regulatory Action [Member] | Complaint Two [Member] | Subsequent Event [Member]

Loss Contingencies [Line Items]

Approved return on equity

9.59%

Unfavorable Regulatory Action [Member] | Complaint Three [Member] | Subsequent Event [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Guarantee Commitments Outstanding [Member]

Loss Contingencies [Line Items]

Line of credits

$ 2,400,000

Before Amendment [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.14%

Commitments and Contingent L110

Commitments and Contingent Liabilities - Schedule of Future Minimum Lease Payment (Detail) $ in Millions	Dec. 31, 2015USD ($)
Commitments And Contingencies Disclosure [Abstract]
Operating leases, 2016	$ 216	[1]
Operating lease, 2017	90	[1]
Operating lease, 2018	26	[1]
Operating leases, 2019	24	[1]
Operating leases, 2020	25	[1]
Operating leases, 2021 and thereafter	298	[1]
Total operating lease	679	[1]
Capital leases, 2016	9	[1]
Capital lease, 2017	6	[1]
Capital lease, 2018	6	[1]
Capital leases, 2019	6	[1]
Capital leases, 2020	7	[1]
Capital leases, 2021 and thereafter	53	[1]
Total capital lease	87	[1]
Operating and capital leases, 2016	225
Operating and capital leases, 2017	96
Operating and capital leases, 2018	32
Operating and capital leases, 2019	30
Operating and capital leases, 2020	32
Operating and capital leases, 2021 and thereafter	351
Total operating and capital leases	$ 766
[1]	(a) Payments related to the period of remaining useful life of facilities are on an undiscounted basis.

Commitments and Contingent L111

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, 2015USD ($)
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2016	$ 496
Forward purchase commitments, 2017	351
Forward purchase commitments, 2018	271
Forward purchase commitments, 2019	211
Forward purchase commitments, 2020	184
Forward purchase commitments, thereafter	957
Total forward purchase commitments	2,470
Forward sales commitments, 2016	157
Forward sales commitments, 2017	89
Forward sales commitments, 2018	69
Forward sales commitments, 2019	49
Forward sales commitments, 2020	39
Forward sales commitments, thereafter	46
Total forward sales commitments	449
Derivative Financial Instrument Gas [Member]
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2016	232
Forward purchase commitments, 2017	203
Forward purchase commitments, 2018	181
Forward purchase commitments, 2019	149
Forward purchase commitments, 2020	124
Forward purchase commitments, thereafter	579
Total forward purchase commitments	1,468
Forward sales commitments, 2016	21
Forward sales commitments, 2017	3
Total forward sales commitments	24
Power [Member]
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2016	233
Forward purchase commitments, 2017	123
Forward purchase commitments, 2018	76
Forward purchase commitments, 2019	54
Forward purchase commitments, 2020	53
Forward purchase commitments, thereafter	320
Total forward purchase commitments	859
Forward sales commitments, 2016	133
Forward sales commitments, 2017	84
Forward sales commitments, 2018	67
Forward sales commitments, 2019	48
Forward sales commitments, 2020	39
Forward sales commitments, thereafter	46
Total forward sales commitments	417
Other Forward Purchases And Sales Commitments
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2016	31
Forward purchase commitments, 2017	25
Forward purchase commitments, 2018	14
Forward purchase commitments, 2019	8
Forward purchase commitments, 2020	7
Forward purchase commitments, thereafter	58
Total forward purchase commitments	143
Forward sales commitments, 2016	3
Forward sales commitments, 2017	2
Forward sales commitments, 2018	2
Forward sales commitments, 2019	1
Total forward sales commitments	$ 8

Environmental Liability - Addit

Environmental Liability - Additional Information (Detail) $ in Millions	Sep. 16, 2015USD ($)	Sep. 11, 2014USD ($)	Aug. 14, 2013USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)	Dec. 31, 2015USD ($)siteLocation	Jan. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							24
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							47
Costs related to investigation and remediation							$ 397		$ 312
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
DEEP [Member]
Environmental Exit Cost [Line Items]
Proceedings on the administrative days	120 days
Extended for an additional proceedings days	90 days
First Energy [Member]
Environmental Exit Cost [Line Items]
Amount that would be required to be paid based on past and future cleanup costs						$ 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]
Amount that would be required to be paid based on past and future cleanup costs			$ 89
Number of hazardous waste sites | Location							22
Estimated clean-up costs			$ 282
Legal discovery process expected closing year description							Century 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							$ 9.5
Costs related to investigation and remediation	$ 30						$ 20.5
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
Nine of Twenty-three Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 6
Another Ten Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 8
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 | Minimum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 235
Manufactured Gas Plants | Maximum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							468
Other MGP Sites [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 99

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Current
Federal	$ (20)	$ (10)	$ (22)
State	(33)	31	(1)
Current taxes charged to (benefit) expense	(53)	21	(23)
Deferred
Federal	136	218	60
State	(6)	82	42
Deferred taxes charged to expense	130	300	102
Production tax credits	(42)	(37)	(42)
Investment tax credits	(1)	(2)	(2)
Total Income Tax Expense	$ 34	$ 282	$ 35

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Differences between Tax Expense Per Statements of Operations and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Tax expense (benefit) at federal statutory rate	$ 105	$ 247	$ (5)
Depreciation and amortization not normalized	15	15	24
Investment tax credit amortization	(1)	(2)	(2)
Tax return related adjustments	6	2	7
Production tax credits	(42)	(37)	(42)
Tax equity financing arrangements	(36)	(11)	(23)
Change in tax reserves		3	(2)
Impairment of non-deductible goodwill			38
Changes in New York tax law		41
State tax expense (benefit), net of federal benefit	(25)	32	27
Non-deductible acquisition costs	9
Other, net	3	(8)	13
Total Income Tax Expense	$ 34	$ 282	$ 35

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Non-current Deferred Income Tax Liabilities (Assets)
Property related	$ 4,763	$ 3,778
Unfunded future income taxes	211	146
Federal and state tax credits	(367)	(317)
Accumulated deferred investment tax credits	15	16
Federal and state NOL’s	(1,367)	(1,266)
Joint ventures/partnerships	655	884
Nontaxable grant revenue	(595)	(622)
Other	(17)	66
Non-current Deferred Income Tax Liabilities	3,298	2,685
Add: Valuation allowance	19	17
Total Non-current Deferred Income Tax Liabilities	3,317	2,702
Less amounts classified as regulatory liabilities non-current deferred income taxes	519	433
Deferred income taxes	2,798	2,269
Deferred tax assets	2,346	2,205
Deferred tax liabilities	$ 5,663	$ 4,907

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Income Taxes [Line Items]
Valuation allowance, net of federal benefit	$ 2	$ 8		$ 9
Accruals for interest and penalties on tax reserves	2	$ 3	$ 11
Unrecognized tax benefits that would impact effective tax rate	9
Net decrease to unrecognized tax benefits	9
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	$ 3,500
Expiration year for net operating losses	2,025
Expiration year for tax credits	2,024
State
Income Taxes [Line Items]
Net operating loss carry forwards	$ 154
Tax credit carry forward	30
Recognized valuation allowance	$ 19
Expiration year for net operating losses	2,025
Renewable Energy | Federal
Income Taxes [Line Items]
Tax credit carry forward	$ 338
R&D | Federal
Income Taxes [Line Items]
Tax credit carry forward	338
Other | Federal
Income Taxes [Line Items]
Tax credit carry forward	$ 338

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Income Tax Disclosure [Abstract]
Beginning Balance	$ 38	$ 41	$ 91
Increases for tax positions related to prior years	1	20	4
Reduction for tax position related to settlements with taxing authorities	(3)	(23)	(54)
Ending Balance	$ 36	$ 38	$ 41

Post-Retirement and Similar 118

Post-Retirement and Similar Obligations - Obligations and Funded Status (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	Dec. 31, 2014USD ($)
Pension Plan [Member]
Change in plan assets
Fair value of plan assets, Beginning balance	$ 2,143
Fair Value of Plan Assets, Ending balance	1,991	$ 2,143
Other Postretirement Benefit Plan [Member]
Change in plan assets
Fair value of plan assets, Beginning balance	128
Fair Value of Plan Assets, Ending balance	123	128
Networks and ARHI [Member] | Pension Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance	2,620	2,316
Service cost	35	30
Interest cost	97	110
Actuarial (gain) loss	(105)	439
Special termination benefits	2
Benefits paid	(158)	(275)
Benefit Obligation, Ending balance	2,491	2,620
Change in plan assets
Fair value of plan assets, Beginning balance	2,143	2,223
Actual return on plan assets	(21)	163
Employer contributions	27	32
Benefits paid	(158)	(275)
Fair Value of Plan Assets, Ending balance	1,991	2,143
Funded Status as of December 31,	(500)	(477)
Networks and ARHI [Member] | Other Postretirement Benefit Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance	435	385
Service cost	5	5
Interest cost	16	18
Plan participants’ contributions	4	4
Plan amendments	(1)
Actuarial (gain) loss	(31)	64
Benefits paid	(25)	(41)
Benefit Obligation, Ending balance	403	435
Change in plan assets
Fair value of plan assets, Beginning balance	129	128
Actual return on plan assets	(4)	4
Employer contributions	21	38
Plan participants’ contributions	4	4
Benefits paid	(25)	(41)
Withdrawal from VEBA	(2)	(4)
Fair Value of Plan Assets, Ending balance	123	129
Funded Status as of December 31,	$ (280)	$ (306)

Post-Retirement and Similar 119

Post-Retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-current liabilities	$ (500)	$ (477)
Total	(500)	(477)
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(275)	(301)
Total	$ (280)	$ (306)

Post-Retirement and Similar 120

Post-Retirement and Similar Obligations - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
Other	$ 330,000,000	$ 254,000,000
Benefits plan, target asset allocation	25.00%
Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	35.00%
Benefits plan, target asset allocation	47.00%
Equity Alternative Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	20.00%
Liability Hedging Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	38.00%
Other Investment Types [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	15.00%
Large Cap Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	20.00%
Medium and Small Cap Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	12.00%
International Developed Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	10.00%
Emerging Market Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Core Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	31.00%
Global High Yield Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	4.00%
International Developed Market Debt [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	3.00%
Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Absolute Return [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Tangible Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Scenario Forecast | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan assets				$ 0
Scenario Forecast | 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]
Termination of vested employees exercising		5,800,000	$ 59,900,000
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 2016	$ 21,000,000
Asset return seeking percentage category	7.50%	7.50%	7.50%
Networks and ARHI [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 2,334,000,000	$ 2,436,000,000
Networks and ARHI [Member] | Non-Qualified Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Other	39,000,000	43,000,000
Networks and ARHI [Member] | Defined Contribution Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Annual contributions made	17,000,000	$ 20,000,000	$ 14,000,000
Networks and ARHI [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Termination of vested employees exercising	2,000,000
UIL Holdings [Member] | Non-Qualified Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Other	20,000,000
UIL Holdings [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution for pension benefit plans during 2016	$ 22,000,000

Post-Retirement and Similar 121

Post-Retirement and Similar Obligations - Summary of Changed in Benefit Obligation and Change in Plan Asset (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014
Pension Plan [Member]
Change in Plan Assets:
Fair value of plan assets, Beginning balance		$ 2,143
Fair Value of Plan Assets, Ending balance	$ 1,991	1,991	$ 2,143
Amounts Recognized in the Statement of Financial Position consist of:
Non-current liabilities	(500)	(500)	(477)
Other Postretirement Benefit Plan [Member]
Change in Plan Assets:
Fair value of plan assets, Beginning balance		128
Fair Value of Plan Assets, Ending balance	123	123	128
Amounts Recognized in the Statement of Financial Position consist of:
Non-current liabilities	(275)	(275)	(301)
UIL Holdings [Member]
Change in Plan Assets:
Fair Value of Plan Assets, Ending balance	712	712
UIL Holdings [Member] | Pension Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance		1,019
Service cost	1	1
Interest cost	2	2
Benefits paid		(4)
Benefit Obligation, Ending balance	1,018	1,018	1,019
Change in Plan Assets:
Fair value of plan assets, Beginning balance		687
Actual return on plan assets		(10)
Benefits paid		(4)
Fair Value of Plan Assets, Ending balance	673	673	687
Projected benefits less than plan assets		(345)
Amounts Recognized in the Statement of Financial Position consist of:
Non-current liabilities	(345)	(345)
UIL Holdings [Member] | Other Postretirement Benefit Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance		122
Benefit Obligation, Ending balance	122	122	122
Change in Plan Assets:
Fair value of plan assets, Beginning balance		39
Fair Value of Plan Assets, Ending balance	39	39	$ 39
Projected benefits less than plan assets		(83)
Amounts Recognized in the Statement of Financial Position consist of:
Non-current liabilities	$ (83)	$ (83)

Post-Retirement and Similar 122

Post-Retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Detail) - ARHI - Other Comprehensive Income [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net (income) loss	$ 25	$ 22	$ 16
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net (income) loss	$ (1)	$ 8	$ 14

Post-Retirement and Similar 123

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, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss	$ 982	$ 1,045	$ 704
Prior service cost (credit)	9	12	16
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss	76	96	24
Prior service cost (credit)	$ (49)	$ (57)	$ (67)

Post-Retirement and Similar 124

Post-Retirement and Similar Obligations - Summary of Amounts Recognized as Regulatory Assets (Detail) $ in Millions	Dec. 31, 2015USD ($)
UIL Holdings [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss	$ 12

Post-Retirement and Similar 125

Post-Retirement and Similar Obligations - Schedule of Aggregate Projected and Accumulated Benefit Obligations of Fair Value of Plan Assets for Underfunded Plans (Detail) - Pension Plan [Member] - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Networks and ARHI [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Projected benefit obligation	$ 2,491	$ 2,620
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Accumulated benefit obligation	2,334	2,436
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Fair value of plan assets	1,991	2,143
Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets, Projected benefit obligation	2,491	2,620
Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets, Accumulated benefit obligation	2,334	2,436
Accumulated Benefit Obligation Exceeds Fair Value of Plan Assets, Fair value of plan assets	1,991	$ 2,143
UIL Holdings [Member]
Defined Benefit Plan Disclosure [Line Items]
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Projected benefit obligation	1,018
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Accumulated benefit obligation	927
Projected Benefit Obligation Exceeds Fair Value of Plan Assets, Fair value of plan assets	$ 673

Post-Retirement and Similar 126

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	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Net Periodic Benefit Cost:
Service cost		$ 35	$ 30	$ 36
Interest cost		95	107	102
Expected return on plan assets		(154)	(161)	(166)
Amortization of prior service cost (benefit)		3	4	4
Amortization of net loss		130	94	120
Special termination benefit charge		2
Settlement charge		2
Net Periodic Benefit Cost		113	74	96
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlements		(2)
Net loss (gain)		69	434	(244)
Amortization of net (loss)		(130)	(94)	(120)
Amortization of prior service (cost) benefit		(3)	(4)	(4)
Total Other Changes		(66)	336	(368)
Total Recognized		47	410	(272)
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Net Periodic Benefit Cost:
Service cost		4	4	5
Interest cost		15	17	16
Expected return on plan assets		(7)	(7)	(7)
Amortization of prior service cost (benefit)		(9)	(11)	(14)
Amortization of net loss		7		3
Net Periodic Benefit Cost		10	3	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)		(12)	72	(50)
Amortization of net (loss)		(7)		(3)
Current year prior service cost		(1)		(2)
Amortization of prior service (cost) benefit		9	11	14
Total Other Changes		(11)	83	(41)
Total Recognized		(1)	86	(38)
UIL Holdings [Member] | Pension Plan [Member]
Net Periodic Benefit Cost:
Service cost	$ 1	1
Interest cost	2	2
Expected return on plan assets	(2)
Net Periodic Benefit Cost	1
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Total Recognized	$ 1
ARHI | Pension Plan [Member]
Net Periodic Benefit Cost:
Interest cost		2	2	2
Expected return on plan assets		(2)	(3)	(3)
Amortization of net loss		1		1
Settlement charge				2
Net Periodic Benefit Cost		1	(1)	2
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Total Recognized		4	5	(13)
Other Changes in plan assets and benefit obligations recognized in OCI:
Net loss (gain)		4	6	(12)
Amortization of net (loss)		(1)		(3)
Total Other Changes		3	6	(15)
ARHI | Other Postretirement Benefit Plan [Member]
Net Periodic Benefit Cost:
Service cost		1	1	1
Interest cost		1	1	1
Amortization of prior service cost (benefit)			1	1
Amortization of net loss			1
Net Periodic Benefit Cost		2	4	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Total Recognized		(6)	(3)	9
Other Changes in plan assets and benefit obligations recognized in OCI:
Net loss (gain)		(8)	(5)	7
Amortization of net (loss)			(1)
Amortization of prior service (cost)			(1)	(1)
Total Other Changes		$ (8)	$ (7)	$ 6

Post-Retirement and Similar 127

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 $ in Millions	12 Months Ended
	Dec. 31, 2016USD ($)
Pension Plan [Member] | Other Comprehensive Income [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	123
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	7
Estimated prior service cost (benefit)	$ (9)

Post-Retirement and Similar 128

Post-Retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Detail)	Dec. 31, 2015	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.24%
Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.50%	3.50%
Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.80%	3.80%
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate		4.24%
Health care trend rate (2019-2028 forward)		4.50%
Other Postretirement Benefit Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (current year)		7.00%
Other Postretirement Benefit Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (current year)		9.00%
Iberdrola Renewables Holding, Inc. (IRHI) [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (current year)		4.50%	4.50%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (2019-2028 forward)		7.00%	7.25%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (2019-2028 forward)		7.50%	7.75%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.10%	4.10%	3.80%
Rate of compensation increase	4.00%	4.00%	4.10%
Discount rate		3.80%	4.90%	4.10%
Expected long-term return on plan assets		7.50%	7.50%	7.50%
Rate of compensation increase - Networks		4.10%	4.20%	4.00%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.10%	4.10%	3.80%
Discount rate		3.80%	4.90%	4.10%
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		7.50%	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		5.00%	5.00%	5.00%
ARHI
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (current year)		4.50%	4.75%
ARHI | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (2019-2028 forward)		7.00%	6.75%
ARHI | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care trend rate (2019-2028 forward)		9.00%	7.75%
ARHI | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.90%	3.90%	3.90%
Discount rate		3.90%	5.00%	4.00%
Expected long-term return on plan assets		5.50%	6.90%	6.50%
ARHI | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.90%	3.90%	3.90%
Discount rate		3.90%	5.00%	4.00%
Expected long-term return on plan assets		5.75%	6.50%	6.25%
UI [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.24%
UI [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.50%	3.50%
Expected long-term return on plan assets	7.75%
UI [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Rate of compensation increase	3.80%	3.80%
Expected long-term return on plan assets	8.00%
UI [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	4.24%
Health care trend rate (current year)	7.00%
Health care trend rate (2019-2028 forward)	4.50%
UI [Member] | Other Postretirement Benefit Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	5.56%
UI [Member] | Other Postretirement Benefit Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	8.00%

Post-Retirement and Similar 129

Post-Retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Detail)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
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	2,027
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.50%	7.75%
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%	7.25%
ARHI
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.75%
Year that the rate reaches the ultimate trend rate	2,026	2,025
ARHI | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	9.00%	7.75%
ARHI | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.00%	6.75%

Post-Retirement and Similar 130

Post-Retirement and Similar Obligations - Schedule of Effects of One-Percent Change In Assumed Health Care Cost Trend Rates (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 16, 2015
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		$ 9
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	$ (7)

Post-Retirement and Similar 131

Post-Retirement and Similar Obligations - Estimated Future Benefit Payments (Detail) - Improvement and Modernization Act of 2003 [Member] $ in Millions	Dec. 31, 2015USD ($)
Networks and ARHI [Member] | Medicare Act Subsidy Receipts [Member]
Defined Benefit Plan Disclosure [Line Items]
2021 - 2025	$ 1
UIL Holdings [Member]
Defined Benefit Plan Disclosure [Line Items]
2021 - 2025	1
Pension Plan [Member] | Networks and ARHI [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	154
2,017	156
2,018	159
2,019	161
2,020	163
2021 - 2025	826
Pension Plan [Member] | UIL Holdings [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	48
2,017	50
2,018	51
2,019	53
2,020	54
2021 - 2025	295
Other Postretirement Benefit Plan [Member] | Networks and ARHI [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	26
2,017	27
2,018	27
2,019	27
2,020	27
2021 - 2025	135
Other Postretirement Benefit Plan [Member] | UIL Holdings [Member]
Defined Benefit Plan Disclosure [Line Items]
2,016	7
2,017	7
2,018	7
2,019	7
2,020	7
2021 - 2025	$ 37

Post-Retirement and Similar 132

Post-Retirement and Similar Obligations - Fair Value of Benefits Plan Assets by Asset Category (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 981	$ 945	$ 919
Level 3 [Member] | Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	89	75	67
Level 3 [Member] | Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	490	449	458
Level 3 [Member] | Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	84	79	57
Level 3 [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	318	342	$ 337
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1,991	2,143
Pension Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	324	367
Pension Plan [Member] | Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	89	77
Pension Plan [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	314	447
Pension Plan [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	5	4
Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	57	48
Pension Plan [Member] | U.S. Government Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	171	177
Pension Plan [Member] | Registered Investment Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	114	116
Pension Plan [Member] | Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	511	477
Pension Plan [Member] | Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	84	79
Pension Plan [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	322	351
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	602	687
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category		23
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category		2
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	314	360
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	4
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	171	177
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	114	116
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category		5
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	408	511
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	324	344
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category		87
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	5	4
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	54	44
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	21	28
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	4	4
Pension Plan [Member] | Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	981	945
Pension Plan [Member] | Level 3 [Member] | Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	89	75
Pension Plan [Member] | Level 3 [Member] | Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	490	449
Pension Plan [Member] | Level 3 [Member] | Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	84	79
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	318	342
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	123	128
Other Postretirement Benefit Plan [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	24	29
Other Postretirement Benefit Plan [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] | Mutual Funds Fixed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	36	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	46	45
Other Postretirement Benefit Plan [Member] | Mutual Funds, Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	11	12
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	121	126
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	24	29
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	36	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	46	45
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	11	12
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [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] | Government and Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 2	$ 2

Post-Retirement and Similar 133

Post-Retirement and Similar Obligations - Fair Value of Measurements Using Level 3 Inputs (Detail) - Level 3 [Member] - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	$ 945	$ 919
Actual return on plan assets:
Relating to assets sold during the year	(21)	6
Relating to assets still held at the reporting date	3	19
Purchases, sales and settlements	54	1
Fair Value of Plan Assets, Ending balance	981	945
Real Estate Investment [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	75	67
Actual return on plan assets:
Relating to assets still held at the reporting date	10	6
Purchases, sales and settlements	4	2
Fair Value of Plan Assets, Ending balance	89	75
Common Collective Trusts [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	449	458
Actual return on plan assets:
Relating to assets sold during the year	(3)	6
Relating to assets still held at the reporting date	(5)	5
Purchases, sales and settlements	49	(20)
Fair Value of Plan Assets, Ending balance	490	449
Partnership/joint Venture Interests [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	79	57
Actual return on plan assets:
Relating to assets sold during the year	(19)
Relating to assets still held at the reporting date	19	3
Purchases, sales and settlements	5	19
Fair Value of Plan Assets, Ending balance	84	79
Other Investments [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of plan assets, Beginning balance	342	337
Actual return on plan assets:
Relating to assets sold during the year	1
Relating to assets still held at the reporting date	(21)	5
Purchases, sales and settlements	(4)
Fair Value of Plan Assets, Ending balance	$ 318	$ 342

Post-Retirement and Similar 134

Post-Retirement and Similar Obligations - Summary of Changes in Fair values of Asset (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 1,991	$ 2,143
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	123	128
Fair Value, Inputs, Level 1 [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	602	687
Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	121	126
Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	408	511
Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	2	2
Level 3 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	981	945	$ 919
Level 3 [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	981	945
UIL Holdings [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	712
UIL Holdings [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	673	687
UIL Holdings [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	39	$ 39
UIL Holdings [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	32
UIL Holdings [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	680
UIL Holdings [Member] | Mutual Funds | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	673
UIL Holdings [Member] | Mutual Funds | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	39
UIL Holdings [Member] | Mutual Funds | Fair Value, Inputs, Level 1 [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	32
UIL Holdings [Member] | Mutual Funds | Fair Value, Inputs, Level 2 [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	673
UIL Holdings [Member] | Mutual Funds | Fair Value, Inputs, Level 2 [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 7

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Dec. 16, 2015	Feb. 28, 2013	Dec. 16, 2011	Dec. 31, 2015	Dec. 31, 2014	Nov. 30, 2011
Class Of Stock [Line Items]
Common stock, authorized				500,000,000	500,000,000
Common stock, issued				309,491,082	252,235,232	243
Common stock, outstanding				308,864,609	252,235,232
Percentage of equity owned by parent				50.00%	50.00%
Common stock, par value				$ 0.01	$ 0.01
Common stock				$ 3	$ 3
Additional paid-in capital				$ 13,653	$ 11,375
Treasury stock, shares				626,473
Convertible preferred stock, shares outstanding				0
Payments to acquire business, cash paid	$ 595
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%
Payments to acquire business, cash paid		$ 153
Loan note		550
Accrued interest		$ 10

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans		$ 4	$ 1	$ 1
Unrealized gain (loss) during the year on derivatives qualified as cash flow hedges		33	(2)
Reclassification to net income of losses on cash flow hedges	[1]	7	5	7
Reclassification to net income of losses on cash flow hedges		(23)	(63)	(66)	$ (73)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax		40	3	7
Other comprehensive income, net of tax		47	1	7
Accumulated other comprehensive loss		(52)	(99)	(100)	(107)
Designated as Hedging Instrument [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) during the year on derivatives qualified as cash flow hedges		31	(2)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Reclassification to net income of losses on cash flow hedges		(54)	(61)	(66)	(73)
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans		(21)	(25)	(26)	(27)
Gain (loss) on defined benefit plans		4	1	1
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans		(8)	(11)	(8)	$ (7)
Gain (loss) on defined benefit plans		$ 3	$ (3)	$ (1)
[1]	Reclassification is reflected in the operating expenses line item in the combined and consolidated statements of operations.

Equity - Accumulated Other C137

Equity - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	$ 20.9	$ (1.4)	$ 0
Reclassification to net income of losses on cash flow hedges, income tax expense	4.9	4.1	4.6
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense (benefit)	2.2	0.6	0.5
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense (benefit)	$ 1.7	$ (1.9)	$ 1

Net Income per Share - Basic an

Net Income per Share - Basic and Diluted (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Numerator:
Net Income (Loss)	$ 96	$ 54	$ 11	$ 106	$ 97	$ 64	$ 63	$ 200	$ 267	$ 424	$ (51)
Denominator:
Weighted average number of shares outstanding - basic									254,588,212	252,235,232	252,235,232
Weighted average number of shares outstanding - diluted									254,605,111	252,235,232	252,235,232
Earnings per share attributable to AVANGRID
Earnings (Loss) Per Common Share, Basic:									$ 1.05	$ 1.68	$ (0.20)
Earnings (Loss) Per Common Share, Diluted:									$ 1.05	$ 1.68	$ (0.20)

Tax Equity Financing Arrange139

Tax Equity Financing Arrangements - Additional Information (Detail) - USD ($)	1 Months Ended	12 Months Ended
	Oct. 31, 2015	Dec. 31, 2015	Dec. 31, 2013	Dec. 31, 2014
Tax Equity Financing Arrangements [Line Items]
Accrued interest average rate		8.50%		8.70%
Upfront cash payments		$ 0
Exercised option to repurchase a portion of holding from one of the third-party investors			$ 51,400,000
Gain on other income and (expense)	$ 5,000,000
Aeolus I [Member]
Tax Equity Financing Arrangements [Line Items]
Percentage of equity owned by subsidiaries				10.00%

Grants, Government Incentive140

Grants, Government Incentives and Deferred Income - Schedule of Changes in Deferred Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014
Deferred Revenue Arrangement [Line Items]
Beginning Balance	$ 1,621	$ 1,703
Additions		4
Recognized in income	(68)	(86)
Ending Balance	1,553	1,621
Government Grants [Member]
Deferred Revenue Arrangement [Line Items]
Beginning Balance	1,606	1,684
Recognized in income	(77)	(78)
Ending Balance	1,529	1,606
Other Deferred Income [Member]
Deferred Revenue Arrangement [Line Items]
Beginning Balance	15	19
Additions		4
Recognized in income	9	(8)
Ending Balance	$ 24	$ 15

Grants, Government Incentive141

Grants, Government Incentives and Deferred Income - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Government Grants [Member]
Deferred Revenue Arrangement [Line Items]
Depreciable assets and contributions credited to property plant and equipment	$ 390	$ 323

Equity Method Investments - Add

Equity Method Investments - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Plant	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Schedule Of Investments [Line Items]
Joint venture, ownership percentage	50.00%	50.00%
Equity method investments	$ 385	$ 262	$ 278
Number of peaking generation plants | Plant	2
Equity method investment, distributions received	$ 12	19	$ 9
Other Affiliates [Member]
Schedule Of Investments [Line Items]
Equity method investments	$ 22
Shell Wind Energy Inc [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage	50.00%
Equity method investments	$ 41	66
Horizon Wind Energy L L C
Schedule Of Investments [Line Items]
Joint venture, ownership percentage	50.00%
Flat Rock Wind Power LLC [Member]
Schedule Of Investments [Line Items]
Equity method investments	$ 143	146
Flat Rock Wind Power II LLC [Member]
Schedule Of Investments [Line Items]
Equity method investments	$ 69	$ 50
NRG Energy Inc [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage	50.00%
Equity method investments	$ 110
Number of peaking generation plants | Plant	2

Equity Method Investments - Sum

Equity Method Investments - Summary of Combined Financial Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Equity Method Investments And Joint Ventures [Abstract]
Revenue	$ 53	$ 72	$ 60
Loss from operations	(14)		(15)
Net loss	(10)		$ (15)
Current assets	45	11
Non-current assets	929	571
Current liabilities	26	10
Non-current liabilities	223	48
Members’ equity	$ 726	$ 524
Joint venture, ownership percentage	50.00%	50.00%
Equity method investment	$ 363	$ 262

Other Financial Statements I144

Other Financial Statements Items - Schedule of Other Income and (Expense) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Other Nonoperating Income Expense [Abstract]
Allowance for funds used during construction	$ 21	$ 17	$ 14
Carrying costs on regulatory assets	28	29	29
Other	6	6	11
Total Other income and (expense)	$ 55	$ 52	$ 54

Other Financial Statements I145

Other Financial Statements Items - Schedule of Accounts Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Dec. 31, 2012
Receivables [Abstract]
Trade receivables	$ 1,036	$ 888
Other receivables		2
Allowance for bad debts	(62)	(49)	$ (58)	$ (56)
Total Accounts Receivable	$ 974	$ 841

Other Financial Statements I146

Other Financial Statements Items - Schedule of Change in Allowance For Bad Debts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Receivables [Abstract]
Beginning balance	$ 49	$ 58	$ 56
Current period provision	46	39	37
Write-off as uncollectible	(33)	(48)	(35)
Ending balance	$ 62	$ 49	$ 58

Other Financial Statements I147

Other Financial Statements Items - Additional Information (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Deferred Payment Arrangements [Member]
Accounts Notes And Loans Receivable [Line Items]
Accounts receivable	$ 62	$ 78

Other Financial Statements I148

Other Financial Statements Items - Schedule of Prepayments and Other Current Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Receivables [Abstract]
Prepaid other taxes	$ 130	$ 93
Broker margin and collateral accounts	46	57
Loans to third parties	3	3
Fixed-term deposits	11	25
Other pledged deposits	24	51
Prepaid expenses	53	32
Other	18	27
Total	$ 285	$ 288

Other Financial Statements I149

Other Financial Statements Items - Schedule of Other Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Payables And Accruals [Abstract]
Advances received	$ 96	$ 87
Accrued salaries	68	76
Short-term environmental provisions	35	36
Collateral deposits received	59	39
Pension and other postretirement	5	5
Other	22	19
Total	$ 285	$ 262

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)Segment	Dec. 31, 2014USD ($)	Dec. 31, 2013USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	3
Operating Revenues	$ 4,367	$ 4,594	$ 4,313
Regulated Electric Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	2,779	2,726	2,665
Regulated Gas Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	605	668	644
Other Networks [Member]
Segment Reporting Information [Line Items]
Operating Revenues	2	2	2
Renewable Energy Generation Of Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues	1,051	1,180	1,087
Gas Storage Services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	21	8	36
Gas Trading Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	$ (92)	$ 4	$ (134)
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, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015	Dec. 31, 2014	Sep. 30, 2014	Jun. 30, 2014	Mar. 31, 2014	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting Information [Line Items]
Operating Revenues										$ 4,367	$ 4,594	$ 4,313
Impairment of non-current assets										12	25	620
Depreciation and amortization										695	629	594
Operating income (loss) from continuing operations		$ 83	$ 161	$ 73	$ 196	$ 186	$ 153	$ 132	$ 414	513	885	179
Adjusted EBITDA										1,220	1,539	1,393
Earnings from equity method investments											12	(3)
Capital expenditures										1,082	1,030	944
Property, plant and equipment		20,711				17,133				20,711	17,133	16,715
Equity method investments		385				262				385	262	278
Total assets		30,743				24,162				30,743	24,162	23,170
Network [Member]
Segment Reporting Information [Line Items]
Operating Revenues										3,386	3,396	3,311
Depreciation and amortization										328	275	257
Operating income (loss) from continuing operations										537	616	703
Adjusted EBITDA										865	891	960
Earnings from equity method investments										1
Capital expenditures										773	775	906
Property, plant and equipment		12,363				8,389				12,363	8,389	7,887
Equity method investments		110								110
Total assets		20,126				12,858				20,126	12,858	11,771
Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues										1,051	1,180	1,087
Impairment of non-current assets										12	24	75
Depreciation and amortization										344	332	310
Operating income (loss) from continuing operations										100	257	122
Adjusted EBITDA										456	613	507
Earnings from equity method investments										(5)	2	(7)
Capital expenditures										304	250	34
Property, plant and equipment		7,835				8,219				7,835	8,219	8,302
Equity method investments		253				262				253	262	278
Total assets		10,685				12,328				10,685	12,328	11,966
Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues										(71)	12	(98)
Impairment of non-current assets												545
Depreciation and amortization										23	22	26
Operating income (loss) from continuing operations										(85)	16	(647)
Adjusted EBITDA										(62)	38	(76)
Capital expenditures										5	5	4
Property, plant and equipment		513				525				513	525	526
Total assets		1,265				1,393				1,265	1,393	1,495
Other Segments [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]									1	6	13
Impairment of non-current assets	[1]										1
Depreciation and amortization	[1]											1
Operating income (loss) from continuing operations	[1]									(39)	(4)	1
Adjusted EBITDA	[1]									(39)	(3)	2
Earnings from equity method investments	[1]									4	10	4
Equity method investments	[1]	22								22
Total assets	[1]	$ (1,333)				$ (2,417)				(1,333)	(2,417)	(2,062)
Intersegment [Member] | Network [Member]
Segment Reporting Information [Line Items]
Operating Revenues											1	8
Intersegment [Member] | Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues										16	9	10
Intersegment [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues										52	72	71
Intersegment [Member] | Other Segments [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]									$ (68)	$ (82)	$ (89)
[1]	(a) Does not represent a segment. It mainly includes Corporate and intercompany eliminations.

Segment information - Reconcili

Segment information - Reconciliation of Adjusted EBITDA to Income Before Income Taxes (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Segment Reporting [Abstract]
Consolidated Adjusted EBITDA	$ 1,220	$ 1,539	$ 1,393
Impairment of non-current assets	12	25	620
Depreciation and amortization	695	629	594
Interest expense, net of capitalization	267	243	245
Other income and (expense)	55	52	54
Earnings from equity method investments		12	(3)
Income (Loss) Before Income Tax	$ 301	$ 706	$ (15)

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Iberdrola Financiacion, S.A. [Member]
Related Party Transaction [Line Items]
Purchases From	$ (1)	$ (2)	$ (2)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Purchases From	(9)	(10)	(10)
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Sales To			2
Purchases From	(55)	(49)	(75)
Iberdrola Ingenieria y Construccion, S.A. [Member]
Related Party Transaction [Line Items]
Sales To			26
Scottish Power, Ltd [Member]
Related Party Transaction [Line Items]
Purchases From			(6)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Sales To	3	12	16
Purchases From	$ (37)	$ (30)	$ (33)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Related Party Transaction [Line Items]
Receivable from related party, write-off	$ 33,000,000	$ 48,000,000	$ 35,000,000
Impairments	12,000,000	25,000,000	$ 620,000,000
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 SA [Member] | Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%
Related party transaction, amount	$ 70,000,000	$ 226,000,000

Related Party Transactions -155

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2014
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Owed By	$ 7	$ 1
Owed To	(5)
Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Owed By	68	33
Owed To	(77)	(223)
Iberdrola Energy Projects, Inc. [Member]
Related Party Transaction [Line Items]
Owed By	1	15
Owed To	(3)	(15)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Owed By		1
Owed To	$ (5)	$ (1)

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, 2015		Sep. 30, 2015		Jun. 30, 2015		Mar. 31, 2015		Dec. 31, 2014		Sep. 30, 2014		Jun. 30, 2014		Mar. 31, 2014		Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Quarterly Financial Information Disclosure [Abstract]
Operating Revenues	$ 1,153		$ 1,048		$ 939		$ 1,227		$ 1,118		$ 982		$ 938		$ 1,556
Operating income	83		161		73		196		186		153		132		414		$ 513	$ 885	$ 179
Net Income (Loss)	96		54		11		106		97		64		62		201		267	424	(50)
Net Income attributable to AVANGRID	$ 96		$ 54		$ 11		$ 106		$ 97		$ 64		$ 63		$ 200		$ 267	$ 424	$ (51)
Earnings Per Common Share, Basic and Diluted:	$ 0.37	[1]	$ 0.22	[1]	$ 0.04	[1]	$ 0.42	[1]	$ 0.38	[1]	$ 0.25	[1]	$ 0.25	[1]	$ 0.79	[1]			$ (0.20)
[1]	Based on weighted average number of 252 million shares outstanding each quarter, 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 Financ157

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

Quarterly Financial Data (un158

Quarterly Financial Data (unaudited) - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended
	Dec. 31, 2015	Sep. 30, 2015	Jun. 30, 2015	Mar. 31, 2015
Selected Quarterly Financial Information [Line Items]
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

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Feb. 17, 2016	Dec. 31, 2014
Subsequent Event [Line Items]
Proceeds from sale of ownership Interest		$ 19.6
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividend declared date	Feb. 17, 2016
Quarterly dividend payable, per share	$ 0.432
Dividend payment date	Apr. 1, 2016
Dividend record date	Mar. 10, 2016
Subsequent Event [Member] | Iroquois [Member]
Subsequent Event [Line Items]
Proceeds from sale of ownership Interest	$ 53.8

Acquisition of UIL and Issue160

Acquisition of UIL and Issue of Common Stock - Additional Information (Detail) - $ / shares	Feb. 22, 2016	Feb. 17, 2016	Dec. 16, 2015	Dec. 31, 2015	Dec. 31, 2014
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
Subsequent Event [Member]
Business Acquisition [Line Items]
Dividend declared date		Feb. 17, 2016
Dividend payment date		Apr. 1, 2016
Dividend record date		Mar. 10, 2016
UIL Holdings [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition			57,255,850
Business acquisition, share price			$ 50.10	$ 10.50
Common stock, par value			$ 10.50
Avangrid, Inc [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Dividend declared date	Feb. 17, 2016
Quarterly dividend payable, per share	$ 0.432
Dividend payment date	Apr. 1, 2016
Dividend record date	Mar. 10, 2016
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 SA [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition			252,234,989

Short-Term Credit Arrangements

Short-Term Credit Arrangements (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2015USD ($)	May. 31, 2012USD ($)	Aug. 31, 2011USD ($)
AGR Revolving Credit Facility [Member]
Line Of Credit Facility [Line Items]
Line of credits		$ 300
Credit facility, expiration date	May 31, 2019
Annual facility fee paid during the year	$ 0.7
AGR Revolving Credit Facility [Member] | Minimum [Member]
Line Of Credit Facility [Line Items]
Debt to capital ratio	0.65
AGR Revolving Credit Facility [Member] | Maximum [Member]
Line Of Credit Facility [Line Items]
Debt to capital ratio	1
Iberdrola Financiacion, S.A. Credit Facility [Member]
Line Of Credit Facility [Line Items]
Line of credits			$ 600
Credit facility, expiration date	Oct. 28, 2015

Cash Dividends Paid by Subsi162

Cash Dividends Paid by Subsidiaries (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013
Cash Dividend [Line Items]
Cash dividends paid	$ 1,111	$ 200	$ 122
AVANGRID Networks [Member]
Cash Dividend [Line Items]
Cash dividends paid	59	$ 200	110
AVANGRID Renewables [Member]
Cash Dividend [Line Items]
Cash dividends paid	750
Other AVANGRID subsidiaries [Member]
Cash Dividend [Line Items]
Cash dividends paid	$ 302		$ 12

Cash Dividends Paid by Subsi163

Cash Dividends Paid by Subsidiaries - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2015	Dec. 31, 2014	Dec. 31, 2013	Feb. 04, 2016
Cash Dividend [Line Items]
Cash dividends paid	$ 1,111	$ 200	$ 122
Avangrid, Inc [Member]
Cash Dividend [Line Items]
Renewables authorized dividend payments	1,400
Authorized cash dividend	950
Cash dividends paid	$ 750
Central Maine Power Company [Member] | Subsequent Event [Member]
Cash Dividend [Line Items]
Dividends declared and payable				$ 100