Avangrid (AGR) 10-K 26 Mar 18 2017 FY Annual report Financial data

Document and Entity Information

Document and Entity Information - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Mar. 20, 2018	Jun. 30, 2017
Document And Entity Information [Abstract]
Document Type	10-K
Amendment Flag	false
Document Period End Date	Dec. 31, 2017
Document Fiscal Year Focus	2,017
Document Fiscal Period Focus	FY
Trading Symbol	AGR
Entity Registrant Name	Avangrid, Inc.
Entity Central Index Key	1,634,997
Current Fiscal Year End Date	--12-31
Entity Well Known Seasoned Issuer	Yes
Entity Voluntary Filers	No
Entity Current Reporting Status	Yes
Entity Filer Category	Large Accelerated Filer
Entity Common Stock, Shares Outstanding		309,086,480
Entity Public Float			$ 2,472

Consolidated Statements of Inco

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Operating Revenues	$ 5,963	$ 6,018	$ 4,367
Operating Expenses
Purchased power, natural gas and fuel used	1,338	1,286	972
Operations and maintenance	2,211	2,206	1,808
Impairment	642		12
Depreciation and amortization	824	804	695
Taxes other than income taxes	563	528	367
Total Operating Expenses	5,578	4,824	3,854
Operating Income (Loss)	385	1,194	513
Other Income and (Expense)
Other income	58	76	56
Earnings from equity method investments	(40)	7
Interest expense, net of capitalization	(280)	(268)	(267)
Income (Loss) Before Income Tax	123	1,009	302
Income tax (benefit) expense	(259)	377	29
Net Income	382	632	273
Less: Net income attributable to noncontrolling interests	1
Net Income Attributable to Avangrid, Inc.	$ 381	$ 632	$ 273
Earnings Per Common Share, Basic:	$ 1.23	$ 2.04	$ 1.07
Earnings Per Common Share, Diluted:	$ 1.23	$ 2.04	$ 1.07
Weighted-average Number of Common Shares Outstanding:
Basic	309,502,861	309,512,553	254,588,212
Diluted	309,661,883	309,817,322	254,605,111
Cash Dividends Declared Per Common Share	$ 1.728	$ 1.728
Avangrid, Inc [Member]
Operating Expenses
Operating expense	$ 3	$ 5	$ 38
Taxes other than income taxes	5	5	5
Total Operating Expenses	8	10	43
Operating Income (Loss)	(8)	(10)	(43)
Other Income and (Expense)
Other income	58	68	10
Earnings from equity method investments	312	567	50
Interest expense, net of capitalization	(29)	(32)	(14)
Income (Loss) Before Income Tax	333	593	3
Income tax (benefit) expense	(48)	(39)	(270)
Net Income	381	632	273
Net Income Attributable to Avangrid, Inc.	$ 381	$ 632	$ 273

Consolidated Statements of Comp

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Net Income		$ 382	$ 632	$ 273
Other Comprehensive Income, Amounts arising during the year:
Gain on defined benefit plans, net of income taxes			7	4
Amortization of pension cost for nonqualified plans, net of income taxes		1	1	3
Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes		25	(26)	33
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes	[1]	14	(16)	7
Other Comprehensive Income (Loss)		40	(34)	47
Comprehensive Income		422	598	320
Less: Net income attributable to noncontrolling interests		1
Comprehensive Income Attributable to Avangrid, Inc.		421	598	320
Avangrid, Inc [Member]
Net Income		381	632	273
Other Comprehensive Income, Amounts arising during the year:
Other Comprehensive Income (Loss)		40	(34)	47
Comprehensive Income		$ 421	$ 598	$ 320
[1]	Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Consolidated Statements of Com4

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	$ 15.2	$ (15.8)	$ 20.9
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	9.3	(11)	4.9
Qualified Pension Plan [Member]
Gain on defined benefit plans, income tax expense (benefit)		4.3	2.2
Non-Qualified Pension Plans [Member]
Gain on defined benefit plans, income tax expense (benefit)	$ 0.2	$ 0.4	$ 1.7

Consolidated Balance Sheets

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Current Assets
Cash and cash equivalents	$ 41	$ 91
Accounts receivable and unbilled revenues, net	1,040	1,119
Accounts receivable from affiliates	10	25
Derivative assets	18	99
Fuel and gas in storage	99	246
Materials and supplies	115	132
Prepayments and other current assets	273	255
Assets held for sale	357
Regulatory assets	307	285
Total Current Assets	2,260	2,252
Total Property, Plant and Equipment ($1,303 and $1,144 related to VIEs, respectively)	22,669	21,548
Equity method investments	352	387
Other investments	63	55
Regulatory assets	2,738	3,091
Other Assets
Goodwill	3,127	3,124
Intangible assets	328	538
Derivative assets	63	73
Other	71	241
Total Other Assets	3,589	3,976
Total Assets	31,671	31,309
Current Liabilities
Current portion of debt	183	349
Tax equity financing arrangements - VIEs	38	96
Notes payable	757	151
Notes payable to affiliate	29	10
Interest accrued	57	60
Accounts payable and accrued liabilities	1,071	1,096
Accounts payable to affiliates	89	218
Dividends payable	134	134
Taxes accrued	89	52
Derivative liabilities	22	75
Liabilities held for sale	137
Other current liabilities	330	279
Regulatory liabilities	178	192
Total Current Liabilities	3,114	2,712
Regulatory liabilities	3,239	1,753
Deferred income taxes regulatory	13	565
Other Non-current Liabilities
Deferred income taxes	1,452	2,890
Deferred income	1,446	1,483
Pension and other postretirement	1,049	1,106
Tax equity financing arrangements - VIEs	60	103
Derivative liabilities	92	78
Asset retirement obligations	196	161
Environmental remediation costs	358	398
Other	360	342
Total Other Non-current Liabilities	5,013	6,561
Non-current Debt	5,196	4,510
Total Non-current Liabilities	13,461	13,389
Total Liabilities	16,575	16,101
Commitments and Contingencies
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	13,653	13,653
Treasury Stock	(8)	(5)
Retained earnings	1,475	1,630
Accumulated other comprehensive loss	(46)	(86)
Total Stockholders’ Equity	15,077	15,195
Noncontrolling interests	19	13
Total Equity	15,096	15,208
Total Liabilities and Equity	31,671	31,309
Avangrid, Inc [Member]
Current Assets
Cash and cash equivalents	8	67
Notes receivable from subsidiaries	1,129	1,908
Accounts receivable from affiliates	55	66
Prepayments and other current assets		11
Total Current Assets	1,192	2,052
Other investments	15,531	14,183
Other Assets
Deferred income taxes	285	220
Other	9	3
Total other assets	294	223
Total Assets	17,017	16,458
Current Liabilities
Current portion of debt	7	8
Notes payable	507	150
Notes payable to subsidiaries	208	454
Interest accrued	8	6
Accounts payable and accrued liabilities	6	4
Accounts payable to subsidiaries	1	3
Interest accrued subsidiaries	4	29
Dividends payable	134	134
Taxes accrued	8	2
Other current liabilities		3
Total Current Liabilities	883	793
Other Non-current Liabilities
Non-current Debt	1,057	470
Total Non-current Liabilities	1,057	470
Total Liabilities	1,940	1,263
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	13,653	13,653
Treasury Stock	(8)	(5)
Retained earnings	1,475	1,630
Accumulated other comprehensive loss	(46)	(86)
Total Stockholders’ Equity	15,077	15,195
Total Liabilities and Equity	$ 17,017	$ 16,458

Consolidated Balance Sheets (Pa

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property, Plant and Equipment, VIEs	$ 22,669	$ 21,548
Common stock, par value	$ 0.01	$ 0.01
Common stock, authorized	500,000,000	500,000,000
Common stock, issued	309,670,932	309,600,439
Common stock, outstanding	309,005,272	308,993,149
Variable Interest Entity, Primary Beneficiary [Member]
Property, Plant and Equipment, VIEs	$ 1,303	$ 1,144

Consolidated Statements of Cash

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Flow from Operating Activities
Net Income	$ 382	$ 632	$ 273
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Depreciation and amortization	824	804	695
Impairment	642		12
Accretion expenses	10	10	14
Regulatory assets/liabilities amortization	47	49	101
Regulatory assets/liabilities carrying cost	15	13	41
Pension cost	112	110	115
Stock-based compensation	1	1	6
Earnings from equity method investments	40	(7)
Amortization of debt (premium) cost	(5)	(28)	3
Gain on disposal of property and equity method investment	(2)	(33)
Unrealized losses (gains) on marked to market derivative contracts	17	(4)	10
Deferred taxes	(251)	375	82
Other non-cash items	(69)	(23)	(5)
Changes in operating assets and liabilities:
Accounts receivable and unbilled revenues	(48)	(158)	160
Inventories	12	46	4
Other assets	(3)	107	(39)
Cash distribution from equity method investments	16	14
Accounts payable and accrued liabilities	81	184	(10)
Other liabilities	(52)	(447)	(194)
Taxes accrued	41	(3)	21
Regulatory assets/liabilities	(47)	(81)	74
Net Cash Provided by Operating Activities	1,763	1,561	1,363
Cash Flow from Investing Activities
Capital expenditures	(2,416)	(1,707)	(1,082)
Contributions in aid of construction	57	69	38
Government grants			17
Acquisition of business, net of $48 million cash acquired			(547)
Proceeds from sale of equity method and other investment		57	3
Proceeds from sale of property, plant and equipment	12	50
Receipts from (payments to) affiliates		6	(6)
Cash distribution from equity method investments	4	6	12
Other investments and equity method investments, net	2	(8)	47
Net Cash Used in Investing Activities	(2,341)	(1,527)	(1,518)
Cash Flow from Financing Activities
Non-current note issuances	888	493	350
Repayments of non-current debt	(305)	(355)	(141)
Proceeds (repayments) of other short-term debt, net	625	(2)	10
Repayments of capital leases	(33)	(12)	(12)
Payments on tax equity financing arrangements	(113)	(88)	(102)
Dividends to noncontrolling interests			(3)
Repurchase of common stock	(3)	(5)
Issuance of common stock	(1)	(2)
Transaction with noncontrolling interest	5
Dividends paid	(535)	(401)
Net Cash Provided by (Used in) Financing Activities	528	(372)	102
Net Cash Provided by (Used in) Financing Activities	528	(372)	102
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(50)	(338)	(53)
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	96	434	487
Cash, Cash Equivalents and Restricted Cash, End of Year	46	96	434
Cash and Cash Equivalents, Beginning of Year	91
Cash and Cash Equivalents, End of Year	41	91
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	202	229	132
Cash paid (refund) for income taxes	13	9	7
Avangrid, Inc [Member]
Cash Flow from Operating Activities
Net Income	381	632	273
Adjustments to reconcile net income (loss) to net cash provided by (used in) operating activities:
Earnings from equity method investments	(312)	(567)	(50)
Changes in operating assets and liabilities:
Net Cash Provided by Operating Activities	(1)	324	(380)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	(532)	(627)	317
Acquisition of subsidiary			(595)
Investments in subsidiaries		(533)
Return of capital from investments in subsidiaries	308	420	1,111
Net Cash Used in Investing Activities	(224)	(740)	833
Cash Flow from Financing Activities
Proceeds (repayments) of short-term notes payable from subsidiaries, net	(246)	133	(331)
Proceeds from short-term notes payable	357	150
Non-current note issuances	594	483
Repurchase of common stock	(3)	(5)
Issuance of common stock	(1)	(2)
Dividends paid	(535)	(401)
Net Cash Provided by (Used in) Financing Activities	166	358	(331)
Net Cash Provided by (Used in) Financing Activities	166	358	(331)
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(59)	(58)	122
Cash and Cash Equivalents, Beginning of Year	67	125	3
Cash and Cash Equivalents, End of Year	8	67	125
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	52	4	$ 20
Cash paid (refund) for income taxes	$ (8)	$ 71

Consolidated Statements of Cas8

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

Consolidated Statements of Chan

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Common stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Stockholders' Equity	Non controlling Interests
Balance at Dec. 31, 2014		$ 12,555	$ 3		$ 11,375		$ 1,260	$ (99)	$ 12,539	$ 16
Balance, shares at Dec. 31, 2014	[1]		252,235,232
Net Income		273					273		273
Other comprehensive income, net of tax		47						47	47
Comprehensive Income		320
Issuance of common stock		2,278			2,278				2,278
Issuance of common stock, shares	[1]		57,255,850
Common stock held in trust		0
Common stock held in trust, shares	[1]		(626,473)
Dividends to noncontrolling interests		(3)								(3)
Balance at Dec. 31, 2015		15,150	$ 3		13,653		1,533	(52)	15,137	13
Balance, shares at Dec. 31, 2015	[1]		308,864,609
Net Income		632					632		632
Other comprehensive income, net of tax		(34)						(34)	(34)
Comprehensive Income		598
Dividends declared		$ (535)					(535)		(535)
Release of common stock held in trust		135,014	135,014	[1]
Issuance of common stock, issuance costs		$ (2)			(2)				(2)
Issuance of common stock, shares		109,357	109,357	[1]
Repurchase of common stock		$ (5)				$ (5)			(5)
Repurchase of common stock, shares		(115,831)	(115,831)	[1]
Stock-based compensation		$ 2			2				2
Balance at Dec. 31, 2016		$ 15,208	$ 3		13,653	(5)	1,630	(86)	15,195	13
Balance, shares at Dec. 31, 2016		308,993,149	308,993,149	[1]
Net Income		$ 382					381		381	1
Other comprehensive income, net of tax		40						40	40
Comprehensive Income		422
Dividends declared		$ (535)					(535)		(535)
Release of common stock held in trust		5,649	5,649	[1]
Issuance of common stock, issuance costs		$ (1)			(1)				(1)
Issuance of common stock, shares		70,493	70,493	[1]
Repurchase of common stock		$ (3)				(3)			(3)
Repurchase of common stock, shares	[1]		(64,019)
Stock-based compensation		1			1				1
Transaction withnoncontrolling interests		4					(1)		(1)	5
Balance at Dec. 31, 2017		$ 15,096	$ 3		$ 13,653	$ (8)	$ 1,475	$ (46)	$ 15,077	$ 19
Balance, shares at Dec. 31, 2017		309,005,272	309,005,272	[1]
[1]	Par value of share amounts is $.01

Consolidated Statements of Ch10

Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Statement Of Stockholders Equity [Abstract]
Common Stock, Par or Value Per Share	$ 0.01	$ 0.01
Other Comprehensive Income (Loss) Taxes	$ 24.7	$ (22.1)	$ 29.7

Background and Nature of Operat

Background and Nature of Operations	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Background and Nature of Operations	Note 1. Background and Nature of Operations Avangrid, Inc., formerly Iberdrola USA, Inc. (AVANGRID, we or the Company), is an energy services holding company engaged in the regulated energy distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks) and in the renewable energy generation and gas storage and trading businesses through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables) and Enstor Gas, LLC (Gas). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% of the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was organized in 1997 as NGE Resources, Inc. under the laws of New York as the holding company for its principal operating utility companies. In December 2017, management committed to a plan to sell the gas storage and trading businesses because they represent non-core businesses that are not aligned with our strategic objectives. As a result, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. The gas trading and storage businesses are being marketed for sale, and it is the Company’s intention to complete the sales of these assets and liabilities within twelve months following their initial classification as held for sale. On March 1, 2018, the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI). On February 16, 2018, the Company entered into a definitive agreement to sell Enstor Gas, LLC, which operates the AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC. The agreement includes, among other things, a transition services agreement which obligates ARHI to provide certain transition services for up to one year after the closing date and includes a guarantee the Company will release certain obligations to Amphora Gas Storage USA, LLC. The transaction, which is subject to the satisfaction of customary closing conditions, is expected to be completed during the second quarter of 2018. Additional details on held for sale classification are provided in Note 25 to our consolidated financial statements. 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. The regulated utility businesses of UIL consist of the electric distribution and transmission operations of UI and the natural gas transportation, distribution and sales operations of The Southern Connecticut Gas Company (SCG), Connecticut Natural Gas Corporation (CNG) and The Berkshire Gas Company (BGC). UI is also a party to a joint venture with NRG Yield Operating LLC, a subsidiary of NRG Yield, Inc. (NYLD, and collectively with NRG Yield Operating LLC, NRG affiliates), which is an affiliate of NRG Energy, Inc. (NRG), 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). In February 2018, NRG announced that it has agreed to sell its ownership stake in NYLD. This sale is expected to close during the second half of 2018 and is not expected to have an impact on GenConn.

Basis of Presentation

Basis of Presentation	12 Months Ended
	Dec. 31, 2017
Basis of Presentation	Note 2. Basis of Presentation The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. Consolidated accounts of UIL have been included in the consolidated financial statements of AVANGRID since December 16, 2015, the date of acquisition of UIL. All intercompany transactions and accounts have been eliminated in all periods presented. All share and per share information included in the consolidated financial statements has been retroactively adjusted to reflect the impact of the stock dividend. Immaterial Corrections to Prior Periods During the year ended December 31, 2017, we identified immaterial corrections to prior periods related to our deferred income tax liabilities associated with our tax equity financing arrangements in our Renewables reportable segment. We evaluated the effects of these corrections on our previously-issued 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 As a result of the correction to our deferred tax liabilities, the revisions resulted in a decrease in income tax expense of $2.4 million and $5.0 million and an increase in other income of $0.2 million and $0.4 million for the years ended December 31, 2016 and 2015, respectively. The cumulative effect of the changes to retained earnings at the beginning of 2015, the earliest date presented in these consolidated financial statements for the year ended December 31, 2017, was an increase of $77.2 million. The revision also resulted in a decrease in deferred taxes of $2.4 million and $5.0 million and a decrease in amortization of debt (premium) cost of $0.2 million and $0.4 million in the consolidated statements of cash flow for the years ended December 31, 2016 and 2015, respectively, with no net impact on our net cash provided by operating activities for the years ended December 31, 2016 and 2015. The information provided in Note 14 - Income Taxes, Note 21 – Other Financial Statement Items and the segment information related to our Renewables reportable segment provided in Note 22 for the years ended December 31, 2016 and 2015 has also been revised to reflect these corrections. A summary of the effect of the correction on the consolidated balance sheet as of December 31, 2016 is as follows: As of December 31, 2016 As Reported Correction As Revised (Millions) Deferred income taxes $ 2,976 $ (86 ) $ 2,890 Total Other Non-current Liabilities 6,647 (86 ) 6,561 Total Non-current Liabilities 13,475 (86 ) 13,389 Total Liabilities 16,187 (86 ) 16,101 Retained earnings 1,544 86 1,630 Total Stockholders' Equity 15,109 86 15,195 Total Equity 15,122 86 15,208 Total Liabilities and Equity $ 31,309 $ — $ 31,309 A summary of the effect of the correction on the consolidated statements of income for the years ended December 31, 2016 and 2015 is as follows: Year Ended December 31, 2016 As Reported Correction As Revised (Millions, except per share data) Other income $ 76 $ — $ 76 Income Before Income Tax 1,009 — 1,009 Income tax expense 379 (2 ) 377 Net Income 630 2 632 Net Income Per Common Share, Basic and Diluted: $ 2.04 $ — $ 2.04 Year Ended December 31, 2015 As Reported Correction As Revised (Millions, except per share data) Other income $ 55 $ 1 $ 56 Income Before Income Tax 301 1 302 Income tax expense 34 (5 ) 29 Net Income 267 6 273 Net Income Per Common Share, Basic and Diluted: $ 1.05 $ 0.02 $ 1.07
Avangrid, Inc [Member]
Basis of Presentation	Note 1. Basis of Presentation Avangrid, Inc. (AVANGRID), formerly Iberdrola USA, Inc., is a holding company and conducts substantially all of its business through its subsidiaries. Substantially all of its consolidated assets are held by such subsidiaries. Accordingly, its cash flow and its ability to meet its obligations are largely dependent upon the earnings of these subsidiaries and the distribution of other payment of such earnings to in the form of dividends, loans or advances or repayment of loans and advances from it. These condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. These statements should be read in conjunction with the consolidated financial statements and notes thereto of AVANGRID and subsidiaries (AVANGRID Group). AVANGRID indirectly or directly owns all of the ownership interests of its significant subsidiaries. AVANGRID relies on dividends or loans from its subsidiaries to fund dividends to its primary shareholder. AVANGRID’s significant accounting policies are consistent with those of the AVANGRID Group. For the purposes of these condensed financial statements, AVANGRID’s wholly owned and majority owned subsidiaries are recorded based upon its proportionate share of the subsidiaries net assets. AVANGRID will file a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries for the 2017 tax period. Each subsidiary company is treated as a member of the consolidated group and determines its current and deferred taxes separately and settles its current tax liability or benefit each year directly with AVANGRID pursuant to a tax sharing agreement between AVANGRID and its members. Immaterial Corrections to Prior Periods During the year ended December 31, 2017, a correction necessary to certain subsidiary’s deferred income tax liabilities associated with tax equity financing arrangements 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 statements of income for the years ended December 31, 2016 and 2015 and the balance sheet as of December 31, 2016 have been revised. The correction resulted in a $2 million and $6 million increase in equity earnings and net income in the statements of income for the years ended December 31, 2016 and 2015, respectively, and an $86 million increase in retained earnings and investments in subsidiaries in the balance sheet as of December 31, 2016. The revision had no net impact on the net cash provided by operating activities for the years ended December 31, 2016 and 2015.

Summary of Significant Accounti

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates	Note 3. Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates Significant Accounting Policies We consider the following policies to be the most critical in understanding the judgments that are involved in preparing our consolidated financial statements: (a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Investments in common stock where we have the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting. (b) Revenue recognition Revenue from the sale of energy by our regulated utilities is recognized in the period during which the sale occurs. The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. Revenues on sales of wholesale energy and energy related products and natural gas are recognized either when the service is provided or the product is delivered. We also provide natural gas storage services to customers. The natural gas remains the property of these customers at all times. Customers pay a two part rate that includes (i) a fixed fee reserving the right to store natural gas in our facilities and, (ii) a per unit rate for volumes actually injected into or withdrawn from storage. The fixed fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are injected into or withdrawn from our storage facilities. (c) Regulatory accounting We account for our regulated utilities operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing regulated services or products, and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the consolidated statements of income consistent with the recovery or refund included in customer rates. We believe that it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates. (d) Business combinations and assets acquisitions We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred by the acquirer to former owners of acquiree and the equity interests issued by the acquirer. Acquisition related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is recorded as goodwill. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In contrast to a business combination, we classify a transaction as an asset acquisition when substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. (e) Equity method investments We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as “Earnings (losses) from equity method investments.” We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that is determined to be other than temporary (OTTI). (f) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment at least annually or more frequently if events occur or circumstances change that will more likely than not reduce the fair value of the reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which goodwill is tested for impairment. In assessing goodwill for impairment we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary (step zero). If it is determined, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass step zero or perform the qualitative assessment, but determine that it is more likely than not that its fair value is less than its carrying amount, a quantitative two step fair value based test is performed. Step one compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an allocation of fair value to the individual assets and liabilities using business combination accounting guidance to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than its carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in the consolidated statements of income as the expense category that is consistent with the function of the intangible assets. (g) Property, plant and equipment Property, plant and equipment are accounted for at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, the estimated cost of removal or reconditioning is recorded as an asset retirement obligation (ARO) and an equal amount is added to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities. Once certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs are capitalized. Development projects in construction are reviewed periodically for any indications of impairment. Assets are transferred from “Construction work in progress” to “Property, plant and equipment” when they are available for service. Wind turbine and related equipment costs, other project construction costs, and interest costs related to the project are capitalized during the construction period through substantial completion. AROs are recorded at the date projects achieve commercial operation. The cost of plant, and equipment in use is depreciated on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 35-90 Plant Wind power stations 20-40 Transport facilities 33-70 Distribution facilities 15-82 Equipment Conventional meters and measuring devices 15-41 Computer software 4-10 Other Buildings 30-82 Operations offices 5-75 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. Allowance for funds used during construction (AFUDC) is a noncash item which represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of interest expense and the remainder is recorded as other income. (h) Impairment of long lived assets We evaluate property, plant, and equipment and other long lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow model. (i) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: ● Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. ● Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. ● Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e. (j) Available for sale securities Securities that do not qualify as either securities held-to-maturity or trading securities, and which have a readily available fair value, are classified as securities available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported, net of taxes, in other comprehensive income or loss. (k) Derivatives and hedge accounting Derivatives are recognized on the balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Changes in the fair value of a derivative contract are recognized in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Other Comprehensive Income (OCI) and later reclassified into earnings when the underlying transaction occurs. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, hedge gains and losses previously recorded in OCI are immediately recognized in earnings. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. Changes in the fair value of electric and natural gas hedge contracts are recorded to derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities for our regulated operations. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. (l) Cash and cash equivalents Cash and cash equivalents comprises cash, bank accounts, and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on the consolidated balance sheets. Book overdrafts representing outstanding checks in excess of funds on deposit are classified as “Accounts payable and accrued liabilities” on the consolidated balance sheets. Changes in book overdrafts are reported in the operating activities section of the consolidated statements of cash flows. (m) Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances, which are settled on a net basis. Receivables and payables subject to such agreements are presented in our consolidated balance sheets on a net basis. Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as short term. The allowance for bad debts account is established by using both historical average loss percentages to project future losses, and a specific allowance is established for known credit issues. Amounts are written off when we believe that a receivable will not be recovered. (n) Variable interest entities We evaluate whether an entity is a variable interest entity (VIE) whenever reconsideration events as defined by the accounting guidance occur (See Note 18). An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. 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. Bonds, debentures and bank borrowings are presented net of unamortized discount, premium and debt issuance costs on the consolidated balance sheets. (p) Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas trading operations, we own natural gas that is stored in both self-owned and third-party owned underground storage facilities. This gas is recorded as inventory. Injections of inventory into storage are priced at the market purchase cost at the time of injection, and withdrawals of working gas from storage are priced at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable 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 the lower of cost and net realizable value and reported on the balance sheets within “Materials and supplies.” Inventory items are combined for the statement of cash flow presentation purposes. (q) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings consistent with the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, amounts receivable are recognized as an offset to expenses in the consolidated statements of income in the period in which the expenses are incurred. (r) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting obligations arising from the transaction. It is our policy to defer such revenues on the consolidated balance sheets and amortize them to earnings consistent with the obligations. (s) Asset retirement obligations The fair value of the liability for an ARO and a conditional ARO is recorded in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long lived asset. The ARO is associated with our long lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains, and electricity generation facilities. The liability is adjusted periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation will be either settled at its recorded amount or a gain or a loss will be incurred. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. These are classified as accrued removal obligations. (t) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. Our environmental liabilities are recorded on an undiscounted basis. Our environmental liability accruals are expected to be paid through the year 2054. (u) Post-employment and other employee benefits We sponsor defined benefit pension plans that cover the majority of our employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. For NYSEG, RG&E and UIL, we amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. For our other companies we use the standard amortization methodology under which amounts in excess of ten percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five year period. (v) Income tax AVANGRID will file a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries for the 2017 tax period, which is consistent with the 2016 tax period. For the 2015 tax year, AVANGRID filed a consolidated federal income tax return, which included the UIL taxable income or loss for the period from December 17, 2015 to December 31, 2015. UIL filed a separate consolidated federal income tax return for the period from January 1, 2015 to December 16, 2015. AVANGRID filed a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries (excluding UIL), including ARHI, which are 80% or more owned for the 2014 tax period. UIL filed separate consolidated federal income tax returns including the income or loss of its subsidiaries for all tax years including the filed 2014 return. AVANGRID (excluding ARHI and UIL), and ARHI each filed separate consolidated federal income tax returns that included the taxable income or loss of all their respective subsidiaries, which are 80% or more owned, for all tax periods prior to 2013. We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with generally accepted accounting principles for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. The investment tax credits are deferred when used and amortized over the estimated lives of the related assets. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. Deferred tax assets and liabilities are classified as non-current in the consolidated balance sheets. The excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital is recorded in “Taxes other than income taxes” and “Taxes accrued” in the accompanying consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” of the consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income. Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements. On December 22, 2017, the President of the United States signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the Tax Act). The Tax Act includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities, and includes specific provisions related to regulated public utilities. The most significant change that impacted the Company was the permanent reduction in the corporate federal income tax rate from 35% to 21%, which required us to measure existing net deferred tax liabilities using the lower rate in the period of enactment, resulting in an income tax benefit. The specific provisions in the Tax Act related to reg

Industry Regulation

Industry Regulation	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Industry Regulation	Note 4. Industry Regulation Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts The Maine distribution rate stipulation, the Federal Energy Regulatory Commission (FERC) Transmission Return on Equity (ROE) case, the New York and Connecticut rate plans, Reforming Energy Vision (REV), the New York Transmission Company (New York TransCo) filings, the Storm proceedings in NY and ME and the Tax Act are some of the most important specific regulatory processes that currently 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. 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. 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 July 1, 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. NYSEG and RG&E Rate Plans On September 16, 2010, the New York Public Service Commission (NYPSC) approved a new rate plan for electric and natural gas service provided by NYSEG and RG&E effective from August 26, 2010 through December 31, 2013. The rate plans contain continuation provisions beyond 2013 if NYSEG and RG&E do not request new rates to go into effect and the current base rates will stay in place. The rates stayed effective until May 1, 2016, at which time a newly approved rate plan became effective. The 2010 revenue requirements were based on a 10% allowed ROE applied to an equity ratio of 48%. If annual earnings exceed the allowed return, a tiered Earnings Sharing Mechanism (ESM) will capture a portion of the excess for the ratepayers’ benefit. The ESM is subject to specified downward adjustments if NYSEG and RG&E fail to meet certain reliability and customer service measures. Key components of the rate plan include electric reliability performance mechanisms, natural gas safety performance measures, customer service quality metrics and targets, and electric distribution vegetation management programs that establish threshold performance targets. There will be downward revenue adjustments if NYSEG and RG&E fail to meet the targets. The 2010 rate plans established revenue decoupling mechanism (RDM), intended to remove company disincentives to promote increased energy efficiency. Under RDM, electric revenues are based on revenue per customer class rather than billed revenue, while natural gas revenues are based on revenue per customer. Any shortfalls or excesses between billed revenues and allowed revenues will be accrued for future recovery or refund. In August 2010, NYSEG began amortizing $15.2 million per year of its $303.9 million theoretical excess depreciation reserve. On September 1, 2012, RG&E began amortizing $5.3 million per year of its $105 million theoretical excess depreciation reserve. Both amortization amounts reflect a twenty year amortization period. Theoretical excess depreciation is the difference between actual accumulated depreciation taken to date and a theoretical reserve. The actual accumulated depreciation is the result of depreciation rates allowed in prior rate orders based on estimates of useful lives and net salvage values as determined in those cases. The theoretical reserve is the amount that would have accumulated if the depreciation rates in the new rate plan had been in place for the entire useful lives of the affected assets. Differences between the actual reserve and the theoretical reserve are normal aspects of utility ratemaking. The usual treatment is to flow any excess or deficiency back as an adjustment to depreciation expense over the remaining life of the property. However, in accordance with the new rate plan, NYSEG and RG&E moderate electric rates by recording the theoretical reserve amortization as a debit to accumulated depreciation and a credit to other revenues, and normalize a portion of the amortization from a tax perspective. On May 20, 2015, NYSEG and RG&E filed electric and gas rate cases with the NYPSC. The companies requested rate increases for NYSEG electric, NYSEG gas and RG&E gas. RG&E electric proposed a rate decrease. On February 19, 2016, NYSEG, RG&E and other signatory parties filed a Joint Proposal with the NYPSC for a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2016. The Joint Proposal, which was approved by the NYPSC on June 15, 2016, balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The Joint Proposal reflects many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increase in the Joint Proposal can be summarized as follows: May 1, 2016 May 1, 2017 May 1, 2018 Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Rate Increase Delivery Rate Increase Utility (Millions) % (Millions) % (Millions) % NYSEG Electric $ 29.6 4.10 % $ 29.9 4.10 % $ 30.3 4.10 % NYSEG Gas 13.1 7.30 % 13.9 7.30 % 14.8 7.30 % RG&E Electric 3.0 0.70 % 21.6 5.00 % 25.9 5.70 % RG&E Gas 8.8 5.20 % 7.7 4.40 % 9.5 5.20 % The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas is 9.00%. The equity ratio for each company is 48%; however, the equity ratio is set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% ROE, respectively, in the first rate year covering the period May 1, 2016 – April 30, 2017. The earnings sharing levels increase in rate year two (May 1, 2017 – April 30, 2018) to 9.65%, 10.15% and 10.65% ROE, respectively. The earnings sharing levels further increase in rate year three (May 1, 2018 – April 30, 2019) to 9.75%, 10.25% and 10.75% ROE, respectively. The rate plans also include the implementation of a rate adjustment mechanism designed to return or collect certain defined reconciled revenues and costs, new depreciation rates, and continuation of the existing RDM for each business. The Joint Proposal reflects the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($21.4 million annually for NYSEG Electric and $2.5 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds. The Joint Proposal maintains NYSEG’s and RG&E’s current electric reliability performance measures (and associated potential negative revenue adjustments for failing to meet established performance levels) which include the system average interruption frequency index (SAIFI) and the customer average interruption duration index (CAIDI). The Joint Proposal also modifies certain gas safety performance measures at the companies, including those relating to the replacement of leak prone main, leak backlog management, emergency response, and damage prevention. The proposal establishes threshold performance levels for designated aspects of customer service quality and continues and expands NYSEG’s and RG&E’s bill reduction and arrears forgiveness Low Income Programs with increased funding levels included in the proposal. The Joint Proposal provides for the implementation of NYSEG’s Energy Smart Community (ESC) Project in the Ithaca region which will serve as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project will be supported by NYSEG’s planned Distribution Automation upgrades and Advanced Metering Infrastructure (AMI) implementation for customers on circuits in the Ithaca region. The companies will also pursue Non-Wires Alternative projects as described in the proposal. Other REV-related incremental costs and fees will be included in the Rate Adjustment Mechanism (RAM) to the extent cost recovery is not provided for elsewhere. Under the proposal, each company will implement the RAM, which will be applicable to all customers, to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG Electric Pole Attachment revenues. The Joint 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 Joint Proposal also includes a downward-only Net Plant reconciliation. In addition, the Joint Proposal includes downward-only reconciliations for the costs of: electric distribution and gas vegetation management; pipeline integrity; and incremental maintenance. The Joint Proposal provides that NYSEG and RG&E continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis. UI, CNG, SCG and BGC Rate Plans 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 Generation Service Charge, or GSC, charge on their bills. UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2018, 70% of its standard service load for the second half of 2018 and 20% of its standard service load for the first half of 2019. Supplier of last resort service is procured on a quarterly basis, however, from time to time there are no bidders in the procurement process for supplier of last resort service and in such cases UI manages the load directly. In December 2016, the PURA approved new distribution rate schedules for UI for three years, which became effective January 1, 2017, and which, among other things, provides for annual tariff increases and an ROE of 9.10% based on a 50% equity ratio, continued UI’s existing ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism, and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist. The allowed ROEs established by PURA for CNG and SCG for 2017, were 9.18% and 9.36%, respectively. SCG and CNG each have purchased gas adjustment clauses that enable them to pass their reasonably incurred cost of gas purchases through to customers. These clauses allow utilities to recover costs associated with changes in the market price of purchased natural gas, substantially eliminating exposure to natural gas price risk. 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 ESM 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. On June 30, 2017, SCG filed an application with PURA for new tariffs to become effective January 1, 2018. SCG requested a three-year rate plan for calendar years 2018, 2019 and 2020 and a proposed ROE of 9.95%. SCG also requested to implement a RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for CNG. On October 16, 2017, SCG, Prosecutorial Staff from PURA, and the Connecticut Office of Consumer Counsel (OCC) filed an amended settlement agreement with PURA for approval, which included, among other items, the implementation of an RDM, ESM and the DIMP as proposed by SCG, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on an ROE of 9.25% and approximately 52% equity level. PURA approved the amended rate case settlement agreement on December 13, 2017, and BGC’s rates are established by the DPU. BGC’s 10-year rate plan, which was approved by the DPU and included an approved ROE of 10.5%, expired on January 31, 2012. BGC continues to charge the rates that were in effect at the end of the rate plan. In accordance with the approval by the DPU of the acquisition, BGC agreed not to initiate a rate case for new rates effective before at least June 1, 2018. Transmission - FERC ROE Proceeding See Note 12, Commitments and Contingent Liabilities, for a further discussion. CMP’s and UI’s transmission rates are determined by a tariff regulated by the FERC and administered by ISO New England, Inc. (ISO-NE). Transmission rates are set annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses, and for a return of and on investment in assets. On December 28, 2015, the FERC issued an order instituting section 206 proceedings and establishing hearing and settlement judge procedures. Pursuant to section 206 of the FPA, the FERC instituted proceedings because it found that ISO-NE Transmission, Markets, and Services Tariff is unjust, unreasonable, and unduly discriminatory or preferential. The FERC stated that ISO-NE’s Tariff lacks adequate transparency and challenge procedures with regard to the formula rates for ISO-NE Participating Transmission Owners, including UI, Maine Electric Power Corporation (MEPCO) and CMP. The FERC also found that the current Regional Network Service, or RNS and Local Network Service, or LNS, formula rates appear to be unjust, unreasonable, unduly discriminatory or preferential, or otherwise unlawful as the formula rates appear to lack sufficient detail in order to determine how certain costs are derived and recovered in the formula rates. A settlement judge has been appointed and a settlement conference has convened. We are unable to predict the outcome of this proceeding at this time. REV In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide ranging initiative to reform New York State’s energy industry and regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources, such as micro grids, on-site power supplies and storage. REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this initiative involves a collaborative process to examine the role of distribution utilities in enabling market based deployment of distributed energy resources to promote load management and greater system efficiency, including peak load reductions. NYSEG and RG&E are participating in the initiative with other New York utilities and are providing their unique perspective. The NYPSC issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform (DSP) provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016. The companies filed the DSIP, which also included information regarding the potential deployment of Automated Metering Infrastructure (AMI) across its entire service territory. The companies, in December 2016, filed a petition to the NYPSC requesting approval for cost recovery associated with the full deployment of AMI, and a collaborative associated with this petition began in in the first quarter of 2017, was suspended in the second quarter of 2017 and resumed in the first quarter of 2018. Other various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include the Clean Energy Standard, Value of DER and Net Energy Metering, Demand Response Tariffs, and Community Choice Aggregation. As part of the Clean Energy Standard proceeding, all electric utilities were ordered to begin payments to New York State Energy Research and Development Authority (NYSERDA) for Renewable Energy Credits and Zero Emissions Credits beginning in 2017. Track 2 of the REV initiative is also underway, and through a NYPSC Staff Whitepaper review process, is examining potential changes in current regulatory, tariff, market design and incentive structures which could better align utility interests with achieving New York state and NYPSC’s policy objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in May 2016, and includes guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs, and data utilization and security. The companies, in December 2016, filed a proposal for the implementation of EAMs in the areas of System Efficiency, Energy Efficiency, Interconnections, and Clean Air. A collaborative process to review the companies’ petition is on going. In March, 2017, the NYPSC issued three separate REV-related orders. These orders created a series of filing requirements for NYSEG and RG&E beginning in March 2017 and extending through the end of 2018. The three orders involve: 1) modifications to the electric utilities’ proposed interconnection earnings adjustment mechanism framework; 2) further DSIP requirements, including filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at each company by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of the Value of DER. In September 2017, the NYPSC issued another order related to the Value of DER, requiring tariff filings, changes to Standard Interconnection Requirements, and planning for the implementation of automated consolidated billing. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm On March 11, 2017, the New York State Department of Public Service (the Department) commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which On November 16, 2017, the NYPSC announced that the Department Staff had completed their investigation into the March 2017 Windstorm and the NYPSC issued an Order Instituting Proceeding and to Show Cause. The Staff’s investigation found that RG&E and NYSEG violated certain parts of their emergency response plans, which makes them subject to possible financial penalties. NYSEG and RG&E responded to the order in a timely manner and have entered into settlement discussions with the Department Staff. The unprecedented weather that resulted in the March 2017 windstorm posed great challenges to the NYSEG’s and RG&E’s communities, employees, contractors, assisting utilities, and municipal partners who all worked tirelessly to safely restore power to all customers. NYSEG’s and RG&E’s priorities during any storm are the restoration of service to their respective customers and the safety of their communities, customers, employees and contractors. We cannot predict the outcome of this regulatory action . MPUC Investigation into the Response by Public Utilities to the October 2017 Storm On December 19, 2017, the Commission issued a Notice of Investigation regarding utility response to the October 2017 Storm. The wind storm of October 2017 was unprecedented in the number of customers impacted and the magnitude of the damage across the entire Central Maine Power service territory. During the event, thousands of trees were broken or uprooted and many caused damage to the electrical delivery system. The vast majority of tree related damage was from trees that were located outside of the maintenance clearance zone. Damage occurred on nearly every CMP distribution circuit, resulting in more than 1,400 broken poles. CMP currently estimates that the total incremental costs are approximately $70.2 million, of which approximately $32.4 million are capital costs associated with the replacement of damaged infrastructure, including poles, cross arms, transformers and related equipment. Additionally, approximately $744,000 of the incremental amount is operations and maintenance expense for repairs to CMP transmission facilities. Accordingly, the net incremental operations and maintenance expense for restoration of the distribution system are approximately $37 million. With regard to the recovery of incremental storm restoration costs in CMP distribution rates, CMP expects that recovery will be addressed in the Company’s 2018 Annual Compliance Filing proceeding pursuant to the applicable provisions of the stipulation approved by the Commission in Docket No. 2013-00168. Tax Cuts and Jobs Act On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Tax Act) was signed into law. The Tax Act contains significant changes to the federal tax structure, including among other things, a corporate tax rate decrease from 35% to 21% effective for tax years beginning after December 31, 2017 Ginna Reliability Support Service Agreement Ginna Nuclear Power Plant, LLC (GNPP), which is a subsidiary of Constellation Energy Nuclear Group, LLC (CENG), owns and operates the R.E. Ginna Nuclear Power Plant (Ginna Facility and together with GNPP, Ginna), a 581 MW single-unit pressurized water reactor located in Ontario, New York. In May 2014, the New York Independent System Operator (NYISO) produced a Reliability Study, confirming that the Ginna Facility needs to remain in operation to avoid bulk transmission and non-bulk local distribution system reliability violations in 2015 and 2018. In July, 2014, GNPP filed a petition requesting that the NYPSC initiate a proceeding to examine a proposal for the continued operation of the Ginna Facility. In November 2014, the NYPSC ruled that GNPP had demonstrated that the Ginna Facility is required to maintain system reliability and that its actions with respect to meeting the relevant retirement notice requirements were satisfactory. The NYPSC also accepted the findings of the 2014 Reliability Study and stated that it established “the reliability need for continued operation of the Ginna Facility that is the essential prerequisite to negotiating a Reliability Support Services Agreement (RSSA).” As such, the NYPSC ordered RG&E and GNPP to negotiate an RSSA. On February 13, 2015, RG&E submitted to the NYPSC an executed RSSA between RG&E and GNPP. RG&E requested that the NYPSC accept the RSSA and approve cost recovery by RG&E from its customers of all amounts payable to GNPP under the RSSA utilizing the cost recovery surcharge mechanism. On October 21, 2015, RG&E, GNPP, New York Department of Public Service, Utility Intervention Unit and Multiple Intervenors filed a Joint Proposal with the NYPSC for approval of the RSSA, as modified. On February 23, 2016, the NYPSC unanimously adopted the joint proposal, which provides for a term of the RSSA from April 1, 2015 through March 31, 2017 and RG&E monthly payments to Ginna in the amount of $15.4 million. In addition, RG&E is entitled to 70% of revenues from Ginna’s sales into the NYISO energy and capacity markets, while Ginna is entitled to 30% of such revenues. The NYPSC also authorized RG&E to implement a rate surcharge effective January 1, 2016, to recover amounts paid to Ginna pursuant to the RSSA. The FERC issued an order authorizing the FERC Settlement agreement in the Settlement Docket on March 1, 2016, at which point the rate surcharge went into effect. RG&E used 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. The available credits were insufficient to satisfy the final payment amount from RG&E to Ginna, and consistent with the agreement with the NYPSC, the RSSA surcharge continues past March 31, 2017, to recover up to $2.3 million per month until the final payment has been recovered by RG&E from customers. New York TransCo Networks holds an approximate 20% ownership interest in the New York TransCo, LLC (New York TransCo). New York TransCo was established by the New York transmission utilities to develop, own, and operate electric transmission in New York. In December 2014, New York TransCo filed for regulatory approval of its rates, terms, and conditions with the FERC. The filing requests a formula base ROE of 10.6%, one-hundred fifty basis points ROE incentives, construction work in progress, a formula rate mechanism, and a proposed cost allocation. Various parties, including the NYPSC, have protested the filing with the FERC, including the base ROE, the ROE incentives, and the cost allocation. New York TransCo will not make final decisions on transmission project development until a FERC decision. On April 2, 2015, the FERC issued an order granting, inter alia, New York TransCo’s owners’ request for a 50 basis point adder for New York TransCo’s membership in the NYISO regional transmission organization (RTO), subject to the adder being capped within the zone of reasonableness after a determination of where within that zone its base level ROE should be set. The FERC also set the formula rate and base ROE issue for hearing and settlement judge procedures. In addition, the FERC rejected New York TransCo’s owners’ cost allocation method for the Transmission Owner Transmission Solutions (TOTS) Projects because it would allocate costs to Power Supply Long Island (LIPA) and New York Power Authority (NYPA) that they did not voluntarily agree to pay. On November 5, 2015, the New York TransCo’s owners, filed the Settlement with the FERC to resolve all outstanding issues associated with the TOTS Projects, including issues related to the TOTS Projects that were set for

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Note 5. Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in the rate base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses, debt premium, environmental remediation costs, which is primarily the offset of accrued liabilities for future spending, unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded , The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. On June 15, 2016, the NYPSC approved the Joint Proposal in connection with a three five ten 16.5 126 fifty Current and non-current regulatory assets as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 24 $ 22 Pension and other post-retirement benefits 7 7 Storm costs 46 40 Temporary supplemental assessment surcharge — 4 Reliability support services 27 27 Revenue decoupling mechanism 21 15 Transmission revenue reconciliation mechanism 8 12 Electric supply reconciliation — 13 Hedges losses 3 10 Contracts for differences 9 14 Hardship programs 14 16 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 31 14 Deferred transmission expense 37 13 Environmental remediation costs 13 14 Other 51 48 Total Current Regulatory Assets 307 285 Non-current Pension and other post-retirement benefits cost deferrals 110 134 Pension and other post-retirement benefits 1,162 1,320 Storm costs 254 187 Deferred meter replacement costs 29 32 Unamortized losses on reacquired debt 17 20 Environmental remediation costs 283 287 Unfunded future income taxes 376 542 Asset retirement obligations 18 18 Deferred property tax 14 33 Federal tax depreciation normalization adjustment 155 161 Merger capital expense target customer credit 2 11 Debt premium 131 151 Reliability support services 10 29 Plant decommissioning 9 14 Contracts for differences 84 61 Hardship programs 13 18 Other 71 73 Total Non-current Regulatory Assets $ 2,738 $ 3,091 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG, and RG&E are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. Storm costs in the amount of $123 million at NYSEG are being recovered over ten-year period and the remaining portion is being amortized over five years following the approval of the Joint Proposal by the NYPSC. UI is allowed to defer costs associated with any storm totaling $1 million or greater for future recovery. UI’s storm regulatory asset balance was $0 as of December 31, 2017. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. Following the approval of the Joint Proposal by the NYPSC, these amounts will be collected over a period of fifty years and the NYPSC Staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Asset retirement obligations” (ARO) represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amount for NYSEG and RG&E is being amortized over a five “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rates years covering 2011 forward. The recovery period in NY is from 27 to 39 years and for CMP this will be determined in future Maine Public Utility Commission (MPUC) rate proceedings. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Other” includes post term amortization and various items subject to reconciliation including rate change levelization, loss on re-acquired debt and power tax deferral. Current and non-current regulatory liabilities as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Current Reliability support services (Cayuga) $ — $ 3 Non by-passable charges 5 22 Energy efficiency portfolio standard 37 45 Gas supply charge and deferred natural gas cost 4 6 Transmission revenue reconciliation mechanism 14 5 Pension and other post-retirement benefits 1 3 Pension and other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 21 15 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE refund 4 24 Merger-related rate credits 1 3 Revenue decoupling mechanism 4 9 Stranded costs 17 — Other 51 38 Total Current Regulatory Liabilities 178 192 Non-current Accrued removal obligations 1,132 1,117 Tax Act - remeasurement 1,515 — Asset sale gain account 10 9 Carrying costs on deferred income tax bonus depreciation 72 95 Economic development 32 35 Merger capital expense target customer credit account 6 15 Pension and other post-retirement benefits 74 76 Positive benefit adjustment 39 42 New York state tax rate change 6 9 Post term amortization — 3 Theoretical reserve flow thru impact 19 24 Deferred property tax 19 19 Net plant reconciliation 10 10 Variable rate debt 33 28 Carrying costs on deferred income tax - Mixed Services 263(a) 20 25 Rate refund – FERC ROE proceeding 27 22 Transmission congestion contracts 19 18 Merger-related rate credits 20 21 Accumulated deferred investment tax credits 13 15 Asset retirement obligation 13 13 Earning sharing provisions 22 12 Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge 2 — Low income programs 42 46 Non-firm margin sharing credits 8 7 Deferred income taxes regulatory 13 565 Other 67 73 Total Non-current Regulatory Liabilities $ 3,252 $ 2,318 “Reliability support services (Cayuga)” represents the difference between actual expenses for reliability support services and the amount provided for in rates. This will be refunded to customers within the next year. “Non by-passable charges” represent the non by-passable charge paid by all customers. An asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered. This liability will be refunded to customers within the next year. “Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station located in Oswego, New York. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is five “Economic development” represents the economic development program which enables NYSEG and RG&E to foster economic development through attraction, expansion, and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is five “Merger capital expense target customer credit” account was created as a result of NYSEG and RG&E not meeting certain capital expenditure requirements established in the order approving the purchase of AVANGRID (formerly Energy East Corporation) by Iberdrola. The amortization period is five “Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this a regulatory liability is not reflected within rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. The amortization period is five “New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from 7.1% to 6.5%. The amortization period is five “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is five “Tax Act - remeasurement” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts to review and address the implications associated with the Tax Act on the utilities providing service in those states. We expect the regulators in each jurisdiction, including the FERC, to issue requirements in 2018 regarding how all tax benefits associated with the Tax Act will be returned to customers. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. 20 “Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “Low Income Programs” represent various hardship and payment plan programs approved for recovery. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.

Goodwill and Intangible Assets

Goodwill and Intangible Assets	12 Months Ended
	Dec. 31, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Goodwill and Intangible Assets	Note 6. Goodwill and Intangible assets Goodwill by reportable segment as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Networks $ 2,747 $ 2,744 Renewables 380 380 Total $ 3,127 $ 3,124 As of December 31, 2017 and 2016, there were no changes in gross amounts and accumulated losses of goodwill for the Networks and Renewables reportable segments, except for various immaterial adjustments in 2017 related to the gross amount of goodwill for the Networks reportable segment. Goodwill Impairment Assessment For impairment testing purposes our reporting units are the same as operating segments, except for Networks, which contained three reporting units, Maine, New York and UIL. The goodwill for the Maine reporting unit resulted from the purchase of CMP by Energy East Corporation in 2000 and amounted to $325 million. Separately, the goodwill for the New York reporting unit resulted primarily from the purchase of RG&E by Energy East in 2002 and amounted to $654 million. The goodwill for the UIL reporting unit was generated from the acquisition of UIL on December 16, 2015 and amounted to $1,765 million. 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. We had no impairment of goodwill in 2017 and 2016 as a result of our impairment testing. 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, 2017 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 583 $ (264 ) $ 319 Other 21 (12 ) 9 Total Intangible Assets $ 604 $ (276 ) $ 328 As of December 31, 2016 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 319 $ (120 ) $ 199 Wind development 587 (254 ) 333 Other 17 (11 ) 6 Total Intangible Assets $ 923 $ (385 ) $ 538 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, 2017, 2016 and 2015 amounted to $22 million, $25 million and $54 million, respectively. We believe our future cash flows will support the recoverability of our intangible assets. We expect amortization expense for the five years subsequent to December 31, 2017, to be as follows: Year ending December 31, (Millions) 2018 $ 16 2019 19 2020 18 2021 21 2022 22 As a result of writing off fully amortized intangible assets relating to Gas Storage rights, $4.1 million and $6.5 million were removed from both cost and accumulated amortization during the years ended December 31, 2016 and 2015, respectively. As of December 31, 2017, we reclassified $193 million from intangible assets related to gas storage rights to assets held for sale in the consolidated balance sheet (see Note 25 - Assets Held for Sale). There was no amount classified as assets held for sale as of December 31, 2016.

Property, Plant and Equipment

Property, Plant and Equipment	12 Months Ended
	Dec. 31, 2017
Property Plant And Equipment [Abstract]
Property, Plant and Equipment	Note 7. Property, Plant and Equipment Property, plant and equipment as of December 31, 2017, consisted of: As of December 31, 2017 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 13,108 $ 11,517 $ 24,625 Natural gas transportation, distribution and other 3,728 13 3,741 Other common operating property — 375 375 Total Property, Plant and Equipment in Service (a) 16,836 11,905 28,741 Total accumulated depreciation (b) (4,172 ) (3,325 ) (7,497 ) Total Net Property, Plant and Equipment in Service 12,664 8,580 21,244 Construction work in progress 987 438 1,425 Total Property, Plant and Equipment $ 13,651 $ 9,018 $ 22,669 ( a ) Includes capitalized leases of $204 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $68 million. Property, plant and equipment as of December 31, 2016, consisted of: As of December 31, 2016 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 12,259 $ 10,375 $ 22,634 Natural gas transportation, distribution and other 3,433 661 4,094 Other common operating property — 335 335 Total Property, Plant and Equipment in Service (a) 15,692 11,371 27,063 Total accumulated depreciation (b) (3,839 ) (3,147 ) (6,986 ) Total Net Property, Plant and Equipment in Service 11,853 8,224 20,077 Construction work in progress 966 505 1,471 Total Property, Plant and Equipment $ 12,819 $ 8,729 $ 21,548 ( a ) Includes capitalized leases of $208 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $60 million. As of December 31, 2017, we reclassified $489 million from non-regulated property, plant and equipment to assets held for sale in the consolidated balance sheet (see Note 25 - Assets Held for Sale). There was no amount classified as assets held for sale as of December 31, 2016. In addition, certain amounts in the regulated and non-regulated property, plant and equipment of the table above have been reclassified to conform to the 2017 presentation. Capitalized interest costs were $28 million, $20 million, and $13 million for the years ended December 31, 2017, 2016 and 2015, respectively. Accrued liabilities for property, plant and equipment additions were $209 million, $338 million and $148 million as of December 31, 2017, 2016 and 2015, respectively. We impaired or wrote off amounts of $5 million, $0 and $12 million for the years ended December 31, 2017, 2016 and 2015, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects in construction. Depreciation expense for the years ended December 31, 2017, 2016 and 2015, amounted to $802 million, $779 million and $641 million, respectively. In September 2017, we acquired all of the membership interest in Solar Star Oregon II, that is constructing a 56MW solar project in Prineville, Oregon called Gala (Gala transaction), which had a PPA in place. The total purchase price for the Gala transaction is $121 million, $105 million of which was paid at the date of acquisition, with the remaining to be paid upon a substantial completion of construction of the Gala solar farm. According to the revised guidance on assessing whether a transaction is an acquisition of assets or a business we performed a screening test to determine whether substantially all of the fair value of the gross assets acquired is concentrated in a single asset or group of similar assets in the Gala transaction. T workforce that is capable to develop or convert inputs into outputs.

Asset Retirement Obligations

Asset Retirement Obligations	12 Months Ended
	Dec. 31, 2017
Asset Retirement Obligation Disclosure [Abstract]
Asset Retirement Obligations	Note 8. 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, 2017 and 2016 consisted of: (Millions) As of December 31, 2015 $ 184 Liabilities settled during the year (7 ) Liabilities incurred during the year 3 Accretion expense 10 Revisions in estimated cash flows (29 ) As of December 31, 2016 $ 161 Liabilities settled during the year (1 ) Liabilities incurred during the year 13 Accretion expense 10 Revisions in estimated cash flows 13 As of December 31, 2017 $ 196 Several of the wind generation facilities have restricted cash for purposes of settling AROs. Restricted cash related to AROs was $2.0 million as of both December 31, 2017 and 2016. These amounts have been included as other non-current assets in the consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in the consolidated statements of income. We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains. In 2017, the addition of new wind and solar facilities, revision of the estimated useful lives of wind and solar facilities, and the subsequent measure of the amount of the original ARO estimate of undiscounted cash flows resulted in higher discounted AROs. We estimate that the revisions will result in approximately $2 million annual increase in expense going forward.

Debt

Debt	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Debt	Note 9. Debt Long- term debt as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2018-2045 $ 2,054 3.07%-10.60% $ 1,752 3.07%-10.60% Unsecured pollution control notes - fixed 2020 200 2.00%-2.375% 200 2.00%-2.375% Unsecured pollution control notes – variable 2032 62 1.94% 62 1.32% Other various non-current debt - fixed 2018-2045 3,027 2.89%-10.48% 2,772 2.89%-10.48% Obligations under capital leases 2018-2030 74 4%-4.44% 104 4%-4.44% Unamortized debt issuance costs and discount (38 ) (31 ) Total Debt 5,379 4,859 Less: debt due within one year, included in current liabilities 183 349 Total Non-current Debt $ 5,196 $ 4,510 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $6,365 million. On May 24, 2017, RG&E issued $300 million in aggregate principal amount of 3.10% First Mortgage Bonds Proceeds of the offering were used to reduce short-term debt, to fund capital expenditures and for general corporate purposes. On November 21, 2017, Avangrid, Inc. issued $600 million aggregate principal amount of its 3.150% notes maturing in 2024. Proceeds of the offering were used to reduce short-term debt incurred to fund capital expenditures associated with development of renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $594 million. Non-current debt, including sinking fund obligations and capital lease payments, due over the next five years consists of: (Millions) 2018 2019 2020 2021 2022 Total $ 183 $ 357 $ 722 $ 307 $ 369 $ 1,938 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, 2017 and 2016. Fair Value of Debt The estimated fair value of debt amounted to $5,799 million and $5,204 million as of December 31, 2017 and 2016, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy pertaining to the fair value of debt is considered as Level 2, except for unsecured pollution control notes-variable with a fair value of $61 million as of both December 31, 2017 and 2016, which are considered Level 3. The fair value of these unsecured pollution control notes-variable are determined using unobservable interest rates as the market for these notes is inactive. Short-term Debt Outstanding Notes Payable AVANGRID had $786 million and $161 million of notes payable as of December 31, 2017 and 2016, respectively. As of December 31, 2017, the balance consisted of $507 million of commercial paper, $250 million of drawn credit facility and $29 million in notes payable to an affiliate. As of December 31, 2016, the balance consisted of $150 million of commercial paper, $10 million in notes payable to an affiliate and $1 million in other notes payable. AVANGRID’s commercial paper program was established on May 13, 2016, has a limit of $1 billion and is backstopped by the AVANGRID credit facility described below. AVANGRID Credit Facility On April 5, 2016, AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC entered into a revolving credit facility with a syndicate of banks, or the AVANGRID credit facility, that provides for maximum borrowings of up to $1.5 billion in the aggregate. Under the terms of the AVANGRID credit facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit established by the banks. AVANGRID’s maximum sublimit is $1 billion, NYSEG, RG&E, CMP and UI have maximum sublimits of $250 million, CNG, and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $25 million. Under the AVANGRID credit facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. The facility fees will range from 10.0 to 17.5 basis points. The maturity date for the AVANGRID credit facility is April 5, 2021. As of December 31, 2017 and 2016, there was $250 million and $0 drawn under the AVANGRID credit facility, and the capacity to borrow under the facility is reduced by the amount of outstanding commercial paper, leaving available credit of, respectively, $743 million and $1,350 million.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Note 10. Fair Value of Financial Instruments and Fair Value Measurements We determine the fair value of our derivative assets and liabilities and available for sale non-current investments associated with Networks’ activities utilizing market approach valuation techniques: ● We measure the fair value of our noncurrent investments using quoted market prices in active markets for identical assets and include the measurements in Level 1. The available for sale investments which are Rabbi Trusts for deferred compensation plans primarily consist of money market funds and are included in Level 1 fair value measurement. ● NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the New York Independent System Operator (NYISO). NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. ● NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). Because we use prices quoted in an active market we include the fair value measurements in Level 1. ● NYSEG, RG&E and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used but because an unobservable basis adjustment is added to the forward prices we include the fair value measurement for these contracts in Level 3. ● 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 11 for further discussion on CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables and Gas activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical product with no adjustment are included in the Level 1 fair value. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in Level 2 fair value. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in Level 3 fair value. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable and interest accrued approximate their estimated fair values and are considered as Level 1. Restricted cash was $5 million as of both December 31, 2017 and 2016, which is included in “Other Assets” on the balance sheet. The financial instruments measured at fair value as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 14 30 74 (49 ) 69 Derivative financial instruments - gas 89 18 64 (146 ) 25 Contracts for differences — — 12 — 12 Total 103 48 150 (195 ) 106 Derivative liabilities Derivative financial instruments - power (14 ) (17 ) (15 ) 37 (9 ) Derivative financial instruments - gas (80 ) (20 ) (25 ) 110 (15 ) Contracts for differences — — (104 ) — (104 ) Total $ (94 ) $ (37 ) $ (144 ) $ 147 $ (128 ) As of December 31, 2016 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 40 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 11 48 58 (42 ) 75 Derivative financial instruments - gas 180 32 104 (239 ) 77 Contracts for differences — — 20 — 20 Total 191 80 182 (281 ) 172 Derivative liabilities Derivative financial instruments - power (24 ) (27 ) (3 ) 39 (15 ) Derivative financial instruments - gas (213 ) (34 ) (53 ) 257 (43 ) Contracts for differences — — (95 ) — (95 ) Total $ (237 ) $ (61 ) $ (151 ) $ 296 $ (153 ) Included in the derivative financial instruments – gas are derivative assets and liabilities of Gas segment classified as held for sale as of December 31, 2017. See Note 25 – Assets Held For Sale for further discussion. The reconciliations of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2017, 2016 and 2015 consisted of: (Millions) 2017 2016 2015 Fair value as of January 1, $ 31 $ (19 ) $ 57 Gains for the year recognized in operating revenues 18 67 33 Losses for the year recognized in operating revenues (1 ) — (8 ) Total gains or losses for the period recognized in operating revenues 17 67 25 Gains recognized in OCI 2 1 2 Losses recognized in OCI (1 ) — (3 ) Total gains or losses recognized in OCI 1 1 (1 ) Net change recognized in regulatory assets and liabilities (17 ) (8 ) — Purchases (5 ) 3 (73 ) Settlements (17 ) (9 ) (14 ) Transfers out of Level 3 (a) (4 ) (4 ) (13 ) Fair value as of December 31, $ 6 $ 31 $ (19 ) 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 $ 17 $ 67 $ 25 (a) Transfers out of Level 3 were the result of increased observability of market data. For assets and liabilities that are recognized in the consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the years reported. Level 3 Fair Value Measurement The tables below illustrate the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives, and the variability in prices for those transactions classified as Level 3 derivatives. As of December 31, 2017 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) $ 3.07 $ 3.93 $ 2.35 with delivery exceeding two on a corroborated by Indiana hub ($/MWh) $ 31.77 $ 65.55 $ 18.53 period > two years discounted market data for Mid C ($/MWh) $ 24.59 $ 46.50 $ (0.50 ) years basis identical or Minn hub ($/MWh) $ 26.40 $ 62.33 $ 9.56 similar products Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of gas storage inventory and merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products. Transactions are valued in part on the basis of forward price, correlation, and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction. The determination of fair value of the CfDs (see Note 11 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input December 31, 2017 Risk of non-performance 0.11% - 0.49% Discount rate 1.89% - 2.40% Forward pricing ($ per MW) $5.30 - $9.55

Derivative Instruments and Hedg

Derivative Instruments and Hedging	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Note 11. Derivative Instruments and Hedging Our Networks, Renewables and Gas activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on the consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities NYSEG and RG&E have an electric commodity charge that passes through rates costs for the market price of electricity. They use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. The amount recognized in regulatory assets and liabilities for electricity derivatives was a loss of $0.2 million and $12.3 million as of December 31, 2017 and 2016, respectively. The loss reclassified from regulatory assets into income, which is included in electricity purchased, was $36.9 million, $66.7 million, and $46.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. NYSEG and RG&E have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and or liabilities with an offset to regulatory assets and or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amount recognized in regulatory assets for natural gas hedges was a loss of $2.5 million as of December 31, 2017 and the amount recognized in regulatory liabilities was a gain of $3.5 million as of December 31, 2016. The loss reclassified from regulatory assets into income, which is included in natural gas purchased, was $0.2 million, $1.9 million, and $6.3 million for the years ended December 31, 2017, 2016 and 2015, respectively. Pursuant to PURA directive, UI and Connecticut’s other electric utility, CL&P, each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of December 31, 2017, UI has recorded a gross derivative asset of $12 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $93 million, a gross derivative liability of $104 million ($90 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2016, UI has recorded a gross derivative asset of $19 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $75 million, a gross derivative liability of $95 million ($70 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the years ended December 31, 2017 and 2016, and for the period from December 17, 2015 to December 31, 2015, respectively, were as follows: Year Ended December 31, 2017 Year Ended December 31, 2016 Period from December 17, 2015 to December 31, 2015 (Millions) Derivative Assets $ (8 ) $ (7 ) $ (1 ) Derivative Liabilities $ (9 ) $ (1 ) $ — The net notional volumes of the outstanding derivative instruments associated with Networks activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (Millions) Wholesale electricity purchase contracts (MWh) 3.9 5.6 Natural gas purchase contracts (Dth) 6.1 5.8 Fleet fuel purchase contracts (Gallons) 2.1 2.3 The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Networks activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 20 $ 5 $ 13 $ — Derivative liabilities (13 ) — (32 ) (88 ) 7 5 (19 ) (88 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 7 5 (19 ) (88 ) Cash collateral receivable — — 3 — Total derivatives as presented in the balance sheet $ 7 $ 5 $ (16 ) $ (88 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 16 $ 7 $ 5 Derivative liabilities (7 ) (5 ) (40 ) (79 ) 12 11 (33 ) (74 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 12 11 (33 ) (74 ) Cash collateral receivable — — 10 2 Total derivatives as presented in the balance sheet $ 12 $ 11 $ (23 ) $ (72 ) The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2017, 2016 and 2015, respectively, consisted of: Year Ended December 31, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2017 Interest rate contracts $ — Interest expense $ 8 Commodity contracts (1 ) Operating expenses 1 Total $ (1 ) $ 9 2016 Interest rate contracts $ — Interest expense $ 8 Commodity contracts — Operating expenses 2 Total $ — $ 10 2015 Interest rate contracts $ — Interest expense $ 9 Commodity contracts (3 ) Operating expenses 3 Total $ (3 ) $ 12 (a) Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the consolidated statements of income. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $68.8 million and $76.7 million, as of December 31, 2017 and 2016, respectively. We recorded $8.0 million, $8.0 million, and $8.6 million in net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2017, 2016 and 2015, respectively. We will amortize approximately $8.0 million of discontinued cash flow hedges in 2018. During the years ended December 31, 2017, 2016 and 2015, there was no ineffective portion for cash flow hedges. The unrealized loss of $0.1 million on hedge derivatives is reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2017. We expect that $0.1 million of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve (b) Renewables and Gas activities We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities. Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also enter into basis swaps to hedge the value of our contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and delivery point of the contracted transport in future periods. Both Renewables and Gas have proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future power sales and gas purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. Gas also periodically designates NYMEX fixed price derivative contracts as cash flow hedges related to its firm storage trading activities. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future gas sales and purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. Derivative contracts entered into to hedge the gas transport trading activities are not designated as cash flow hedges, with all changes in fair value of such derivative contracts recorded in current period earnings. The below presented information includes derivative financial instruments associated with Gas activities, which were classified as held for sale in the consolidated balance sheet (see Note 25 - Assets Held for Sale). There were no derivative financial instruments classified as assets held for sale as of December 31, 2016. The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (MWh/Dth in Millions) Wholesale electricity purchase contracts 4 3 Wholesale electricity sales contracts 6 7 Natural gas and other fuel purchase contracts 285 329 Financial power contracts 12 8 Basis swaps - purchases 68 49 Basis swaps - sales 62 45 The fair values of derivative contracts associated with Renewables and Gas activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (Millions) Wholesale electricity purchase contracts $ (3 ) $ (2 ) Wholesale electricity sales contracts 8 6 Natural gas and other fuel purchase contracts 19 30 Financial power contracts 55 56 Basis swaps- purchases (13 ) 3 Basis swaps- sales 4 (2 ) Total $ 70 $ 91 The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 111 $ 99 $ 31 $ 4 Derivative liabilities (82 ) (5 ) (51 ) (10 ) 29 94 (20 ) (6 ) Designated as hedging instruments Derivative assets 24 4 — 2 Derivative liabilities — (1 ) (3 ) (3 ) 24 3 (3 ) (1 ) Total derivatives before offset of cash collateral 53 97 (23 ) (7 ) Cash collateral receivable (payable) (17 ) (39 ) 3 3 Total derivatives as presented in the balance sheet, including assets and liabilities held for sale $ 36 $ 58 $ (20 ) $ (4 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 198 $ 108 $ 78 $ 7 Derivative liabilities (118 ) (4 ) (132 ) (16 ) 80 104 (54 ) (9 ) Designated as hedging instruments Derivative assets 25 4 — — Derivative liabilities (1 ) — (39 ) (21 ) 24 4 (39 ) (21 ) Total derivatives before offset of cash collateral 104 108 (93 ) (30 ) Cash collateral receivable (payable) (17 ) (46 ) 41 24 Total derivatives as presented in the balance sheet $ 87 $ 62 $ (52 ) $ (6 ) The effect of trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Wholesale electricity purchase contracts $ (3 ) $ 3 $ 6 Wholesale electricity sales contracts 4 (7 ) (5 ) Financial power contracts (1 ) 4 — Financial and natural gas contracts (8 ) (22 ) (26 ) Total Loss $ (8 ) $ (22 ) $ (25 ) The effect of non-trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Wholesale electricity purchase contracts $ 1 $ 9 $ (8 ) Wholesale electricity sales contracts (3 ) (20 ) (5 ) Financial power contracts (5 ) (10 ) 24 Natural gas and other fuel purchase contracts (8 ) 34 18 Total Gain $ (15 ) $ 13 $ 29 Such gains and losses are included in “Operating revenues” and in “Purchased power, natural gas and fuel used” operating expenses in the consolidated statements of income, depending upon the nature of the transaction. The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2017, 2016 and 2015 consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2017 Commodity contracts $ 41 Revenues $ 14 $ 41 $ 14 2016 Commodity contracts $ (42 ) Revenues $ (43 ) $ (42 ) $ (43 ) 2015 Commodity contracts $ 57 Revenues $ (2 ) Total $ 57 $ (2 ) (a) Changes in OCI are reported on a pre-tax basis. Amounts are reclassified from accumulated OCI into income in the period during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $20.9 million of gain included in accumulated OCI at December 31, 2017 is expected to be reclassified into earnings within the next 12 months. During the years ended December 31, 2017, 2016 and 2015, we recorded a net gain of $2.6 million, a net loss of $6.8 million, and a net gain $4.8 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges. We recorded $0.5 million in net derivative loss and $0.4 million and $2.3 million in net derivative gain related to discontinued cash flow hedge for the years ended December 31, 2017, 2016 and 2015, respectively. The net loss in accumulated OCI of $0.2 million as of December 31, 2017 related to a discontinued cash flow hedge will amortize through 2018. (c) Counterparty credit risk management NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are dependent on the counterparty’s or the counterparty’s guarantor’s applicable credit rating, normally Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold. The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of December 31, 2017, UI would have had to post an aggregate of approximately $15.8 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amounts of cash collateral under master netting arrangements that have not been offset against net derivative positions were $30 million and $20 million as of December 31, 2017 and 2016, respectively. Derivative instruments settlements and collateral payments are included in “Other assets” and “Other liabilities” of operating activities in the consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of December 31, 2017 is $3 million, for which we have posted collateral.

Commitments and Contingent Liab

Commitments and Contingent Liabilities	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Commitments and Contingent Liabilities	Note 12. 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. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a complaint (Complaint I) with the FERC pursuant to sections 206 and 306 of the Federal Power Act. The filing parties seek an order from the FERC reducing the 11.14% base return on equity used in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) to 9.2%. CMP, MEPCO and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint. On June 19, 2014, the FERC issued its decision in Complaint I, establishing a methodology and setting an issue for a paper hearing. On October 16, 2014, FERC issued its final decision in the Complaint I setting the base ROE at 10.57%, and a maximum total ROE of 11.74% (base plus incentive ROE) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014 and ordered the NETOs to file a refund report. On November 17, 2014 the NETOs filed a refund report. On March 3, 2015, the FERC issued an order on requests for rehearing of its October 16, 2014 decision. The March order upheld the FERC’s June 19, 2014 decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. In June 2015 the NETOs and complainants both filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. On April 14, 2017, the Court of Appeals (the Court) vacated FERC’s decision on Complaint I and remanded it to FERC. The Court held that FERC, as directed by statute, did not determine first that the existing ROE was unjust and unreasonable before determining a new ROE. The Court ruled that FERC should have first determined that the then existing 11.14% base ROE was unjust and unreasonable before selecting the 10.57% as the new base ROE. The Court also found that FERC did not provide reasoned judgment as to why 10.57%, the point ROE at the midpoint of the upper end of the zone of reasonableness, is a just and reasonable ROE. Instead, FERC had only explained in its order that the midpoint of 9.39% was not just and reasonable and a higher base ROE was warranted. On June 5, 2017, the NETOs made a filing with FERC seeking to reinstate transmission rates to the status quo ante (effect of the Court vacating order is to return the parties to the rates in effect prior to FERC Final decision) as of June 8, 2017, the date the Court decision became effective. In that filing, the NETOs stated that they will not begin billing at the higher rates until 60 days after FERC has a quorum of commissioners. On October 6, 2017, FERC issued an order rejecting the NETOs request to collect transmission revenue requirements at the higher ROE of 11.14%, pending FERC order on remand. In reaching this decision, FERC stated that it has broad remedial authority to make whatever ROE it eventually determines to be just and reasonable effective for the Complaint I refund period and prospectively from October 2014, the effective date of the Complaint I Order. Therefore FERC reasoned that the NETOs will not be harmed financially by not immediately returning to their pre-Complaint I ROE. We anticipate FERC to address the Court decision during 2018. We cannot predict the outcome of action by FERC . On December 26, 2012, a second, ROE complaint (Complaint II) for a subsequent rate period was filed requesting the then effective ROE of 11.14% be reduced to 8.7%. On June 19, 2014, FERC accepted Complaint II, established a 15-month refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in the Complaint I. On July 31, 2014, a third, ROE complaint (Complaint III) was filed for a subsequent rate period requesting the then effective ROE of 11.14% be reduced to 8.84%. On November 24, 2014, FERC accepted the Complaint III, established a 15-month refund effective date of July 31, 2014, and set this matter consolidated with Complaint II for hearing in June 2015. Hearings relating to the refund periods and going forward period were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the NETOs filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The FERC Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that: (1) for the 15-month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the 15 month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The Initial Decision is the Administrative Law Judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in 2018. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $22.5 million and $4.4 million, respectively, as of December 31, 2017, which has not changed since December 31, 2016, except for the accrual of carrying costs. If adopted as final, the impact of the initial decision would be an additional aggregate reserve for Complaints II and III of $17.1 million, which is based upon currently available information for these proceedings. We cannot predict the outcome of the Complaint II and III proceedings. On April 29, 2016, a fourth ROE complaint (Complaint IV) was filed for a rate period subsequent to prior complaints requesting the then existing base ROE of 10.57% be reduced to 8.61 11.24 On October 5, 2017, the NETOs filed a Motion for Dismissal of Pancaked Return on Equity Complaints in light of the decision by the Court in April 2017 that became effective on June 8, 2017. The NETOs assert that all four complaints should be dismissed because the complainants have not shown that the existing ROE of 11.14% is unjust and unreasonable as the Court decision requires. In addition, the NETOs assert that Complaints II, III and IV should also be dismissed because the Court decision implicitly found that FERC’s acceptance of Pancaked FPA Section 206 complaints was statutorily improper as Congress intended that the 15-month refund period under Section 206 applies whenever FERC does not complete its review of a complaint within the 15-month period. In the event FERC chooses not to dismiss the complaints, the NETOs request that FERC consolidate the complaints for decision as the evidentiary records are either closed or advanced enough for FERC to address the requirements of the Court decision and expeditiously issue a final order. FERC has not yet ruled on this Motion. We cannot predict the outcome of action by FERC. California Energy Crisis Litigation Two California agencies brought a complaint in 2001 against a long-term PPA entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the PPA were unjust and unreasonable. FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed FERC's dismissal of Renewables. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014 FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC Trial Staff recommended that the complaint against Renewables be dismissed. A hearing was held before an administrative law judge of FERC in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market contract that would justify finding the Renewables PPAs unjust and unreasonable. However, the proposed ruling did conclude that price of the PPAs imposed an excessive burden on customers in the amount of $ 259 New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm On March 11, 2017, the New York State Department of Public Service (the Department) commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which On November 16, 2017, the NYPSC announced that the Department Staff had completed their investigation into the March 2017 Windstorm and the NYPSC issued an Order Instituting Proceeding and to Show Cause. The Staff’s investigation found that RG&E and NYSEG violated certain parts of their emergency response plans, which makes them subject to possible financial penalties. NYSEG and RG&E responded to the order in a timely manner and have entered into settlement discussions with the Department Staff. The unprecedented weather that resulted in the March 2017 windstorm posed great challenges to the NYSEG’s and RG&E’s communities, employees, contractors, assisting utilities, and municipal partners who all worked tirelessly to safely restore power to all customers. NYSEG’s and RG&E’s priorities during any storm are the restoration of service to their respective customers and the safety of their communities, customers, employees and contractors. We cannot predict the outcome of this regulatory action. Class Action Regarding LDC Gas Transportation Service on Algonquin Gas Transmission On November 16, 2017, a class action lawsuit was filed in the U.S. District Court in Massachusetts on behalf of customers in New England against the Company and Eversource alleging that certain of their respective subsidiaries that take gas transportation service over the Algonquin Gas Transmission, AGT, which for AVANGRID would be its indirect subsidiaries SCG and CNG, engaged in pipeline capacity scheduling practices on AGT that resulted in artificially increased electricity prices in New England. These allegations were based on the conclusions of a White Paper issued by the Environmental Defense Fund (EDF), an environmental advocacy organization, on October 10, 2017, purporting to analyze the relationship between the New England electricity market and the New England local gas distribution companies. The plaintiffs assert claims under federal antitrust law, state antitrust, unfair competition and consumer protection laws, and under the common law of unjust enrichment. They seek damages, disgorgement, restitution, injunctive relief, and attorney fees and costs. The Company filed a Motion to Dismiss all of the claims on January 29, 2018. On February 27, 2018, the FERC released the results of a FERC staff inquiry into the pipeline capacity scheduling practices on the AGT. The inquiry arose out of the allegations made by the EDF in its White Paper. FERC announced that, based on an extensive review of public and non-public data, it had determined that the EDF study was flawed and led to incorrect conclusions. FERC also stated that the staff inquiry revealed no evidence of anticompetitive withholding of natural gas pipeline capacity on the AGT and that it would take no further action on the matter. Nevertheless, we cannot predict the outcome of this class action lawsuit. Leases Operating lease expense relating to operational facilities, office building leases, and vehicle and equipment leases was $71.5 million, $70.6 million and $47.7 million for the years ended December 31, 2017, 2016 and 2015, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities were $18.6 million, $22.2 million and $22.2 million for the years ended December 31, 2017, 2016 and 2015, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses. On January 16, 2014, as required by the NYPSC, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga operates and maintains the RSS units and manages and complies with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and capacity providers and complies with dispatch instructions. NYSEG pays Cayuga a monthly fixed price and also pays for capital expenditures for specified capital projects. NYSEG is 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 $17.6 million, $37.8 million and $25.5 million for the years ended December 31, 2017, 2016 and 2015, respectively. On October 21, 2015, RG&E, GNPP and multiple intervenors filed a joint proposal with the regulator for approval of the modified RSS Agreement for the continued operation of the Ginna Facility. On February 23, 2016, the NYPSC unanimously adopted the joint proposal, which provides for a term of the RSSA from April 1, 2015, through March 31, 2017 and RG&E monthly payments to GNPP in the amount of $15.4 million. RG&E is entitled to 70% of revenues from GNPP’s sales into the energy and capacity markets, while GNPP is entitled to 30% of such revenues. We account for this arrangement as an operating lease. The net expense incurred under this operating lease was $5.6 million, $114.9 million and $79.9 million for the years ended December 31, 2017, 2016 and 2015, respectively. Total future minimum lease payments as of December 31, 2017 consisted of: Year Operating Leases Capital Leases Total (Millions) 2018 $ 36 $ 7 $ 43 2019 35 8 43 2020 36 8 44 2021 36 5 41 2022 31 2 33 Thereafter 757 47 804 Total $ 931 $ 77 $ 1,008 Power, Gas, and Other Arrangements Power and Gas Supply Arrangements – Networks NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and NYPA are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation. NYSEG, RG&E, SCG, CNG and BGC (collectively, the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review. The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the US Gulf of Mexico region, in the Appalachia region and in Canada. The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system. The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months. Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system. Other arrangements include UI’s long-term contracts to purchase RECs and contractual obligations for property, plant and equipment, material and services on order but not yet delivered at December 31, 2017. Power, Gas, and Other Arrangements – Renewables and Gas Gas purchase commitments include multi-year contracted storage and transport capacity contracts that allow the Gas business to participate in seasonal and locational gas price differentials. The agreements contain fixed payment obligations for the use of both storage and transport capacity throughout the U.S. Power purchase commitments include the following: (i) a 55MW Biomass PPA for 12 years (four 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 (one year remaining) Forward purchases and sales commitments under power, gas, and other arrangements as of December 31, 2017 consisted of: Purchases Sales Year Gas Power Other Total Gas Power Other Total (Millions) 2018 $ 280 $ 171 $ 528 $ 979 $ 26 $ 127 $ 4 $ 157 2019 239 123 201 563 9 104 1 114 2020 186 102 39 327 7 71 — 78 2021 149 89 20 258 4 51 — 55 2022 120 63 12 195 — 23 — 23 Thereafter 638 443 100 1,181 — 42 — 42 Totals $ 1,612 $ 991 $ 900 $ 3,503 $ 46 $ 418 $ 5 $ 469 Guarantee Commitments to Third Parties As of December 31, 2017, 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 AVANGRID and its subsidiaries in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of December 31, 2017, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liabilities

Environmental Liabilities	12 Months Ended
	Dec. 31, 2017
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Note 13. Environmental Liabilities Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. Waste sites The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-five waste sites, which do not include sites where gas was manufactured in the past. Fifteen of the twenty-five sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six sites are included in Maine’s Uncontrolled Sites Program and one site is included on the Massachusetts Non- Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, nine of the twenty-five sites are also included on the National Priorities list. Any liability may be joint and severable for certain sites. We have recorded an estimated liability of $5 million related to ten of the twenty-five sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another ten sites where we believe it is probable that we will incur remediation costs and or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Our estimate for costs to remediate these sites ranges from $12 million to $21 million as of December 31, 2017. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the portion of remediation attributed to us. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Eight sites are included in the New York State Registry; twelve sites are included in the New York Voluntary Cleanup Program; three sites are part of Maine’s Voluntary Response Action Program and with two of such sites being part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and where necessary remediate forty-nine of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $213 million to $442 million as of December 31, 2017. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives, and changes to current laws and regulations. Certain other Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; no liability was recorded in respect of these sites as of December 31, 2017 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of December 31, 2017 and 2016, the liability associated with MGP sites in Connecticut, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $100 million and $97 million, respectively. The liability to investigate and perform remediation at the known inactive MGP sites and other sites was $389 million and $388 million as of December 31, 2017 and 2016, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2054. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former manufactured gas sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor. Based on past and future clean-up costs at the sixteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the decision were upheld on appeal. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-judgment interest of $3 million. FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million, excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean up expenses at nine MPG sites. Based on current projections, FirstEnergy’s share is estimated at approximately $22 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG ratepayers. Century Indemnity and OneBeacon On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share is approximately $89 million, excluding pre-judgment interest, although this amount may change substantially depending upon the determination of various factual matters and legal issues during the case. Century Indemnity and OneBeacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. On March 31, 2017, the District Court granted motions filed by Century Indemnity and One Beacon dismissing all of NYSEG’s claims against both defendants on the grounds of late notice. NYSEG filed a motion with the District Court on April 14, 2017 seeking reconsideration of the Court’s decision and is researching grounds for further appeal if the reconsideration motion is denied. We cannot predict the outcome of this matter, however, any recovery will be flowed through to NYSEG ratepayers. English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. This proceeding had been stayed in 2014 pending resolutions of other proceedings before the DEEP concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the English Station site; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages. This lawsuit had been stayed in May 2014 pending mediation. Due to lack of activity in the case, the court terminated the stay and scheduled a status conference for July 6, 2017. On July 5, 2017, Asnat filed a pretrial memorandum claiming damages of $10 million for “environmental remediation activities” and lost use of the property. In December 2017 Plaintiffs filed a Request for Leave to Amend Complaint and Motion to Cite-In Additional Parties, including former UIL officers and employees and other UI officers, which motion was approved in February 2018. We cannot predict the outcome of this matter. On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April 2015. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with the DEEP. On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the consent order, to the extent that the cost of this investigation and remediation is less than $ 30 As of December 31, 2017 we reserved $25 million for this matter. .

Income Taxes

Income Taxes	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Income Taxes	Note 14. Income Taxes The Tax Act changes significantly the federal taxation of business entities, including among other things, a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. We have made a reasonable estimate of the effects of the Tax Act and recorded provisional amounts for the income tax effects related to the remeasurement of our deferred tax assets and liabilities and the associated regulatory liabilities established by our regulated utility companies in our consolidated financial statements as of December 31, 2017. As we complete our analysis of the Tax Act, collect and prepare necessary data, and interpret any additional guidance issued by the U.S. Treasury Department, the IRS, and other standard-setting bodies, we may make adjustments to the provisional amounts. Those adjustments may materially impact our provision for income taxes in the period in which the adjustments are made. Current and deferred taxes charged to (benefit) expense for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Current Federal $ (20 ) $ (6 ) $ (20 ) State 12 8 (33 ) Current taxes charged to (benefit) expense (8 ) 2 (53 ) Deferred Federal (124 ) 412 131 State (73 ) 2 (6 ) Deferred taxes charged to (benefit) expense (197 ) 414 125 Production tax credits (53 ) (38 ) (42 ) Investment tax credits (1 ) (1 ) (1 ) Total Income Tax (Benefit) Expense $ (259 ) $ 377 $ 29 The differences between tax expense per the statements of income and tax expense at the 35% statutory federal tax rate for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Tax expense at federal statutory rate $ 43 $ 353 $ 106 Depreciation and amortization not normalized 9 61 15 Investment tax credit amortization (1 ) (1 ) (1 ) Tax return related adjustments 7 (2 ) 6 Production tax credits (53 ) (38 ) (42 ) Tax equity financing arrangements (10 ) (27 ) (42 ) Federal tax rate impact on held for sale classification 82 — — State tax (benefit) expense, net of federal benefit (40 ) 7 (25 ) Tax Act - remeasurement (328 ) — — Non-deductible acquisition costs — — 9 Other, net 32 24 3 Total Income Tax (Benefit) Expense $ (259 ) $ 377 $ 29 Deferred tax assets and liabilities as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Non-current Deferred Income Tax Liabilities (Assets) Property related $ 3,543 $ 5,195 Unfunded future income taxes 75 216 Federal and state tax credits (574 ) (417 ) Accumulated deferred investment tax credits 14 14 Federal and state NOL’s (975 ) (1,397 ) Joint ventures/partnerships 302 565 Nontaxable grant revenue (449 ) (581 ) Pension and other post-retirement benefits (33 ) 52 Tax Act - tax on regulatory remeasurement (401 ) — Other (58 ) (223 ) Non-current Deferred Income Tax Liabilities 1,444 3,424 Add: Valuation allowance 21 31 Total Non-current Deferred Income Tax Liabilities 1,465 3,455 Less amounts classified as regulatory liabilities Non-current deferred income taxes 13 565 Non-current Deferred Income Tax Liabilities $ 1,452 $ 2,890 Deferred tax assets $ 2,490 $ 2,617 Deferred tax liabilities 3,955 6,072 Net Accumulated Deferred Income Tax Liabilities $ 1,465 $ 3,455 Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. The valuation allowance for deferred tax assets as of December 31, 2017 and 2016 was $21 million and $31 million, respectively. Valuation allowances have been established on various state net operating losses and tax credit carryforwards. The Company has not recorded a valuation allowance on its federal net operating losses or tax credit carryforwards. The $10 million decrease (net of federal benefit) in valuation allowance was primarily driven by a reduction of $15.9 million for Connecticut general business credits resulting from a change in state tax law, an increase of $8.5 million for additional valuation on state net operating losses, a release of $5.3 million in Maine super credits, offset by an increase of $3.0 million resulting from the change in corporate tax rate from 35% to 21%, reducing the federal benefit of state taxes. The reconciliation of unrecognized income tax benefits for the years ended December 31, 2017, 2016 and 2015 consisted of: Years ended December 31, 2017 2016 2015 (Millions) Beginning Balance $ 40 $ 36 $ 38 Increases for tax positions related to prior years 23 8 1 Decreases for tax positions related to prior years (16 ) (4 ) — Reduction for tax position related to settlements with taxing authorities (2 ) — (3 ) Ending Balance $ 45 $ 40 $ 36 Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information. Accruals for interest and penalties on tax reserves were $0.4 million, $2 million, and $2 million for the years ended December 31, 2017, 2016 and 2015, respectively. If recognized, $14 million of the total gross unrecognized tax benefits would affect the effective tax rate. It is estimated that no unrecognized tax benefits are anticipated to result in a net increase or decrease within 12 months of December 31, 2017. AVANGRID and its subsidiaries, without ARHI, have been audited for the federal tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. Tax years 2010 and forward are open for potential federal adjustments. All New York state returns, which were filed without ARHI, are closed through 2011 and Maine state returns are closed through 2015. All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period. As of December 31, 2017, 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, 2017, we had federal tax net operating losses of $3.6 billion, federal renewable energy and investment tax credits, federal R&D tax credits and other federal credits of $404 million, state tax net operating losses of $231 million in several jurisdictions and miscellaneous state tax credits of $37 million available to carry forward and reduce future income tax liabilities. For state purposes, we recognized a valuation allowance of $21 million. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2023. The more significant state net operating losses begin to expire in 2021.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	12 Months Ended
	Dec. 31, 2017
Compensation And Retirement Disclosure [Abstract]
Post-retirement and Similar Obligations	Note 15. Post-retirement and Similar Obligations Networks has funded noncontributory defined benefit pension plans that cover the majority of Networks employees. The plans provide defined benefits based on years of service and final average salary for employees hired before 2002. Most employees hired in 2002, or later based upon the plan, are covered under a cash balance plan or formula where their benefit accumulates based on a percentage of annual salary and credited interest. During 2013, Networks announced that they would discontinue, effective December 31, 2013, the cash balance accruals for all non-union employees covered under the cash balance plans or formula. At the same time, the plans were closed to newly-hired non-union employees. The plans had been closed to newly-hired union employees in prior years. Networks has other postretirement health care benefit plans covering the majority of Networks employees. The plans were closed to newly-hired non-union employees at the end of 2010. The plans had been closed to union employees in prior years. The pre-Medicare-eligible healthcare plans are contributory and participants’ contributions are adjusted annually. Networks average contribution to these plans is limited at a level determined in prior periods. Except for a small group of “grandfathered” retirees, all Medicare eligible retirees that choose to participate are provided with a subsidy through a Health Reimbursement Account (HRA) to purchase coverage on the individual market. With the acquisition of UIL, Networks also includes pension and other postretirement plans of UIL operating utility companies. The UI pension plans cover about one half of employees of UIL. The plan was closed to newly-hired employees in 2005. The Regulated Gas Companies in Connecticut and Massachusetts have multiple qualified pension plans covering a majority of their union and management employees. The union plans are all closed to new hires, and the nonunion plans were closed as of December 31, 2017. These entities also have non‑qualified supplemental pension plans for certain employees and retires. The qualified pension plans are traditional defined benefit plans or cash balance plans for those hired on or after specified dates. In some cases, neither of these plans is offered to new employees and have been replaced with enhanced 401(k) plans for those hired on or after specified dates. In addition to providing pension benefits, UI also provides other postretirement benefits, consisting principally of health care and life insurance benefits, for retired employees and their dependents. The healthcare plans are contributory and participants’ contributions are adjusted annually. SCG and CNG also have plans providing other postretirement benefits for a majority of their employees. These benefits consist primarily of health care, prescription drug and life insurance benefits, for retired employees and their dependents. For Medicare eligible non-union retirees, SCG and CNG provide a subsidy through a HRA for retirees to purchase coverage on the individual market. Medicare eligible union retirees have the option of receiving a subsidy through an HRA or paying contributions and participating in company-sponsored retiree health plans. ARHI has funded defined benefit pension plans for eligible employees hired prior to January 1, 2008. The benefit is based on participant’s age, service, and five years average pay at the time of the freeze date of April 30, 2011. ARHI has other postretirement health care benefit plans covering eligible retirees and employees hired prior to January 1, 2008. Health and life insurance rates are based on age and service points at the time of retirement. Obligations and funded status of Networks and ARHI as of December 31, 2017 and 2016 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2017 2016 2017 2016 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 3,448 $ 3,509 $ 495 $ 525 Service cost 42 44 4 5 Interest cost 139 142 22 21 Plan participants’ contributions — — 7 7 Actuarial loss (gain) 188 (43 ) 3 (24 ) Special termination benefits — — — — Benefits paid (219 ) (204 ) (39 ) (39 ) Reclassified to held for sale (5 ) — (1 ) — Benefit Obligation as of December 31, 3,593 3,448 491 495 Change in plan assets Fair value of plan assets as of January 1, 2,672 2,664 160 162 Actual return on plan assets 382 169 17 11 Employer contributions 33 43 20 30 Plan participants’ contributions — — 7 7 Benefits paid (219 ) (204 ) (39 ) (39 ) Reclassified to held for sale (3 ) — — — Withdrawals from VEBA — — — (11 ) Fair Value of Plan Assets as of December 31, 2,865 2,672 165 160 Funded Status as of December 31, $ (728 ) $ (776 ) $ (326 ) $ (335 ) Amounts recognized as of December 31, 2017 and 2016 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2017 2016 2017 2016 (Millions) Current liabilities $ — $ — $ (5 ) $ (5 ) Non-current liabilities (728 ) (776 ) (321 ) (330 ) Total $ (728 ) $ (776 ) $ (326 ) $ (335 ) Amounts recognized in OCI for ARHI for the years ended December 31, 2017, 2016 and 2015, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2017 2016 2015 2017 2016 2015 (Millions) Net (gain) loss $ 25 $ 23 $ 25 $ (4 ) $ (3 ) $ (1 ) 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, 2017, 2016 and 2015 for Networks consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2017 2016 2015 2017 2016 2015 (Millions) Net loss $ 737 $ 860 $ 994 $ 35 $ 44 $ 76 Prior service cost (credit) 6 7 9 (31 ) (40 ) (49 ) Our accumulated benefit obligation for all defined benefit pension plans of Networks and ARHI was $3,363 million and $3,214 million as of December 31, 2017 and 2016, respectively. CMP’s and NYSEG’s postretirement benefits were partially funded as of December 31, 2017 and 2016. The projected benefit obligation (PBO) and the accumulated benefit obligation (ABO) exceeded the fair value of pension plan assets for all plans of Networks and ARHI as of December 31, 2017 and 2016. The aggregate PBO and ABO and the fair value of plan assets for underfunded plans of Networks and ARHI as of December 31, 2017 and 2016 consisted of: PBO in excess of plan assets As of December 31, 2017 2016 (Millions) Projected benefit obligation $ 3,593 $ 3,448 Fair value of plan assets 2,865 2,672 ABO in excess of plan assets As of December 31, 2017 2016 (Millions) Accumulated benefit obligation $ 3,363 $ 3,214 Fair value of plan assets 2,865 2,672 Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2017, 2016 and 2015 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2017 2016 2015 2017 2016 2015 Net Periodic Benefit Cost: Service cost $ 42 $ 44 $ 36 $ 5 $ 5 $ 4 Interest cost 137 140 97 21 20 15 Expected return on plan assets (195 ) (199 ) (156 ) (8 ) (8 ) (7 ) Amortization of prior service cost (benefit) 2 2 3 (9 ) (9 ) (9 ) Amortization of net loss 126 123 130 5 8 7 Special termination benefit charge — — 2 — — — Settlement charge — — 2 — — — Net Periodic Benefit Cost 112 110 114 14 16 10 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Settlements — — (2 ) — — — Net loss (gain) 3 (11 ) 69 (5 ) (24 ) (12 ) Amortization of net loss (126 ) (123 ) (130 ) (5 ) (8 ) (7 ) Current year prior service cost — — — — — (1 ) Amortization of prior service (cost) benefit (2 ) (2 ) (3 ) 9 9 9 Total Other Changes (125 ) (136 ) (66 ) (1 ) (23 ) (11 ) Total Recognized $ (13 ) $ (26 ) $ 48 $ 13 $ (7 ) $ (1 ) Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2017, 2016 and 2015 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2017 2016 2015 2017 2016 2015 Net Periodic Benefit Cost: Service cost $ — $ — $ — $ — $ — $ 1 Interest cost 2 2 2 1 1 1 Expected return on plan assets (2 ) (2 ) (2 ) — — — Amortization of net loss 1 1 1 — — — Settlement charge — 1 — — — — Net Periodic Benefit Cost (income) 1 2 1 1 1 2 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) 2 — 4 (1 ) (2 ) (8 ) Amortization of net loss (1 ) (1 ) (1 ) — — — Total Other Changes 1 (1 ) 3 (1 ) (2 ) (8 ) Total Recognized $ 2 $ 1 $ 4 $ — $ (1 ) $ (6 ) 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, 2018 consists of: Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 150 $ 5 Estimated prior service cost (benefit) 1 (9 ) Amounts expected to be amortized from OCI into net periodic benefit cost for the year ending December 31, 2018 consists of: 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, 2018. The weighted-average assumptions used to determine benefit obligations for Networks and ARHI as of December 31, 2017 and 2016 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2017 2016 2017 2016 Discount rate - Networks 3.63% / 3.80% 4.12% / 4.24% 3.63% / 3.80% 4.12% / 4.24% Discount rate - ARHI 3.80% 3.81% 3.80 % 3.81% Rate of compensation increase - Networks 3.50% - 4.20% 3.50% - 4.20% — — 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, 2017, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2017 2016 2015 2017 2016 2015 Discount rate - Networks 4.12% / 4.24% 4.12% / 4.24% 3.80% / 4.24% 4.12% / 4.24% 4.12% / 4.24% 3.80% / 4.24% Discount rate - ARHI 3.81% 3.90% 3.90% 3.81% 3.90% 3.90% Expected long-term return on plan assets - Networks 7.00% / 7.50% 7.40% / 7.75% 7.50% 6.13% 7.16% — Expected long-term return on plan assets - ARHI 5.50% 5.50% 5.50% 5.50% 5.50% 5.75% Expected long-term return on plan assets - nontaxable trust - Networks — — — 6.50% 7.00% 7.50% Expected long-term return on plan assets - taxable trust - Networks — — — 4.25% 4.50% 5.00% Rate of compensation increase - Networks 3.50% - 4.20% 3.50% - 4.20% 4.10% — — — We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 Health care cost trend rate assumed for next year - Networks 6.75%/8.50% 7.00%/9.00% Health care cost trend rate assumed for next year - ARHI 7.50%/8.50% 6.75%/8.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.50% 4.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.50% 4.50% Year that the rate reaches the ultimate trend rate - Networks 2026 / 2028 2026 / 2028 Year that the rate reaches the ultimate trend rate - ARHI 2028 / 2030 2026 / 2028 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 $ 15 $ (12 ) Contributions We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. Networks expect to contribute $48 million to the pension benefit plans during 2018. 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, 2017 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2018 $ 234 $ 33 $ — 2019 215 33 — 2020 218 33 — 2021 221 33 — 2022 225 33 — 2023 - 2027 1,122 165 4 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 current and Other Non-current Liabilities, was $55 million and $57 million at December 31, 2017 and 2016, respectively. Plan Assets Our pension benefits plan assets for Networks and ARHI are held in three master trusts. This provides for a uniform investment manager lineup and an efficient, cost effective means of allocating expenses and investment performance to each plan. Our primary investment objective is to ensure that current and future benefit obligations are adequately funded and with volatility commensurate with our risk tolerance. Preservation of capital and achievement of sufficient total return to fund accrued and future benefits obligations are of highest concern. Our primary means for achieving capital preservation is through diversification of the trusts’ investments while avoiding significant concentrations of risk in any one area of the securities markets. Further diversification is achieved within each asset group through utilizing multiple asset managers and systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income, and alternative investment markets. Networks’ asset allocation policy is the most important consideration in achieving our objective of superior investment returns while minimizing risk. We have established a target asset allocation policy within allowable ranges for our pension benefits plan assets within broad categories of asset classes made up of Return-Seeking and Liability-Hedging investments. Within the Return-Seeking category, we have targets of 35%-54% in equity securities and 3%-20% in equity alternative investments. The Liability-Hedging asset class has a target allocation percentage of 43%-45%. Return-Seeking investments generally consist of domestic, international, global, and emerging market equities invested in companies across all market capitalization ranges. Return-Seeking assets also include investments in real estate, absolute return, and strategic markets. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS, and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. ARHI’s investment portfolio contains a diversified blend of equity, fixed income, and other investments. In ARHI’s asset allocation policy we have established targets of 33% for equity investments, 50% for fixed income investments and 17% for other assets classes. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. Other asset classes, including real estate, absolute return, and real return, are used to enhance long-term returns while improving portfolio diversification. We primarily minimize the risk of large losses through diversification but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews, annual liability measurements, and periodic asset and liability studies. The fair values of pension benefits plan assets, by asset category, as of December 31, 2017, consisted of: As of December 31, 2017 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 18 $ — $ 18 $ — U.S. government securities 13 13 — — Common stocks 129 129 — — Registered investment companies 134 134 — — Corporate bonds 447 — 447 — Preferred stocks 4 — 4 — Equity commingled funds 436 186 250 — Other, principally annuity, fixed income 553 — 553 — $ 1,734 $ 462 $ 1,272 $ — Other investments measured at net asset value 1,131 Total $ 2,865 The fair values of pension benefits plan assets, by asset category, as of December 31, 2016, consisted of: As of December 31, 2016 * Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 49 $ — $ 49 $ — U.S. government securities 172 172 — — Common stocks 120 120 — — Registered investment companies 122 122 — — Corporate bonds 358 — 358 — Preferred stocks 4 — 4 — Equity commingled funds 371 — 371 — Other, principally annuity, fixed income 386 — 386 — $ 1,582 $ 414 $ 1,168 $ — Other investments measured at net asset value 1,090 Total $ 2,672 *Certain amounts in this table have been reclassified to conform to 2017 presentation. 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. ● Preferred stocks - at the closing price reported in the active market in which the individual investment is traded. ● Equity commingled funds – the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market . ● 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. ● Other investments measured at net asset value (NAV) – alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient. Our postretirement benefits plan assets are held with trustees in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements and are invested among and within various asset classes to achieve sufficient diversification in accordance with our risk tolerance. This is achieved for our postretirement benefits plan assets through the utilization of multiple institutional mutual and money market funds, providing exposure to different segments of the fixed income, equity and short-term cash markets. Approximately 37% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes. Networks has established a target asset allocation policy within allowable ranges for postretirement benefits plan assets of 46%-66% for equity securities, 30%-31% for fixed income, and 3%-23% for all other investment types. In ARHI’s asset allocation policy we have established targets of 48% in equity securities, 49% in fixed income and 3% in all other investment types. The target allocations within allowable ranges are further diversified into 27%-66% large cap domestic equities, 5% small cap domestic equities, 8% international developed market, and 6% emerging market equity securities. Fixed income investment targets and ranges are segregated into core fixed income at 24%-31%, global high yield fixed income at 4%, and international developed market debt at 3%. Other alternative investment targets are 6% for real estate, 6% for tangible assets, and 3%-11% for other funds. Systematic rebalancing within target ranges increases the probability that the annualized return on investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges. The fair value of other postretirement benefits plan assets, by asset category, as of December 31, 2017 consisted of: As of December 31, 2017 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 4 $ 4 $ — $ — Mutual funds, fixed 35 35 — — Government and corporate bonds 2 — 2 — Mutual funds, equity 77 50 27 — Common stocks 20 20 — — Mutual funds, other 27 19 8 — Total $ 165 $ 128 $ 37 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2016 consisted of: As of December 31, 2016 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 6 $ 4 $ 2 $ — Mutual funds, fixed 41 39 2 — Government and corporate bonds 2 — 2 — Mutual funds, equity 72 43 29 — Common stocks 23 23 — — Mutual funds, other 16 9 7 — Total $ 160 $ 118 $ 42 $ — 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. ● Government bonds, and common stocks - at the closing price reported in the active market in which the security is traded. ● Corporate bonds - based on yields currently available on comparable securities of issuers with similar credit ratings. Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2017 and 2016. 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 $36 million, $34 million and $17 million for 2017, 2016, and 2015 respectively.

Equity

Equity	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Equity	Note 16. Equity As of December 31, 2017, our share capital consisted of 500,000,000 shares of common stock authorized, 309,670,932 shares issued and 309,005,272 shares outstanding, 81.5% of which is owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $3 million and additional paid in capital of $13,653 million. As of December 31, 2016, our share capital consisted of 500,000,000 shares of common stock authorized, 309,600,439 shares issued and 308,993,149 shares outstanding, 81.5% of which was owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in of $13,653 million. We had 485,810 and 491,459 shares of common stock held in trust and no convertible preferred shares outstanding as of December 31, 2017 and December 31, 2016, respectively. During the year ended December 31, 2017, we issued 70,493 shares of common stock and released 5,649 shares of common stock held in trust each having a par value of $0.01. During the year ended December 31, 2016, we issued 109,357 shares of common stock and released 135,014 shares of common stock held in trust each having a par value of $0.01. On April 28, 2016, we entered into a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage of Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. The total cost of repurchases, including commissions, was $8 million as of December 31, 2017. On December 15, 2015, the board of directors approved our common stock dividend, accounted for as a stock split. The stock split, effected through a stock dividend, resulted in the issuance of 252,234,989 shares, which in addition to the 243 previously existing shares increased the total shares outstanding to 252,235,232. The stock dividend was effective upon the board of directors’ approval. All share and per share information included in the consolidated financial statements has been retroactively adjusted to reflect the impact of the stock dividend. Accumulated OCI (Loss) Accumulated OCI for the years ended December 31, 2017, 2016 and 2015 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2014 2015 Change As of December 31, 2015 2016 Change As of December 31, 2016 2017 Change As of December 31, 2017 (Millions) (Loss) gain on revaluation of defined benefit plans, net of income tax expense of $2.2 for 2015, and $4.3 for 2016 $ (25 ) $ 4 $ (21 ) $ 7 $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans, net of income tax expense (benefit) of $1.7 for 2015, $0.4 for 2016 and $0.2 for 2017 (11 ) 3 (8 ) 1 (7 ) 1 (6 ) 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 $20.9 for 2015, $(15.8) for 2016 and $15.2 for 2017 (2 ) 33 31 (26 ) 5 25 30 Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $4.9 for 2015, $(11.0) for 2016 and $9.3 for 2017 (a) (61 ) 7 (54 ) (16 ) (70 ) 14 (56 ) Gain (loss) on derivatives qualifying as cash flow hedges (63 ) 40 (23 ) (42 ) (65 ) 39 (26 ) Accumulated Other Comprehensive (Loss) Income $ (99 ) $ 47 $ (52 ) $ (34 ) $ (86 ) $ 40 $ (46 ) (a) Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Earnings Per Share

Earnings Per Share	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Net Income Per Share	Note 17. Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. In 2017, 2016 and 2015, while we did have securities that were dilutive, these securities did not result in a change to our earnings per share calculations for the years ended December 31, 2017, 2016 and 2015. In accordance with Accounting Standards Codification (ASC) Topic 260, Earnings per Share, we retroactively applied the stock split to prior periods presented. The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2017, 2016 and 2015, consisted of: Years Ended December 31, 2017 2016 2015 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 381 $ 632 $ 273 Denominator: Weighted average number of shares outstanding - basic 309,502,861 309,512,553 254,588,212 Weighted average number of shares outstanding - diluted 309,661,883 309,817,322 254,605,111 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 1.23 $ 2.04 $ 1.07 Earnings Per Common Share, Diluted $ 1.23 $ 2.04 $ 1.07

Variable Interest Entities

Variable Interest Entities	12 Months Ended
	Dec. 31, 2017
Variable Interest Entities [Abstract]
Variable Interest Entities	Note 18. Variable Interest Entities We participate in certain partnership arrangement that qualify as variable interest entities (VIEs). These arrangements consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and the investor does not have substantive kick-out or participating rights. The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered in substance real estate. Under existing guidance for real estate financings, the membership interests in the TEFs we sold to the third-party investors are reflected as a financing obligation in the consolidated balance sheets. We continue to fully consolidate the TEFs’ assets and liabilities in the consolidated balance sheets and to report the results of the TEFs’ operations in the consolidated statements of income. The presentation reflects revenues and expenses from the TEFs’ operations on a fully consolidated basis. We consolidate the TEFs based on being the primary beneficiary for these VIEs. The liabilities are increased for cash contributed by the third-party investors, interest accrued, and the federal income tax impact to the third-party investors of the allocation of taxable income. Interest is accrued on the balance using the effective interest method and the third-party investors’ targeted rate of return. The balance accrued interest at an average rate of 8.4% and 5.4% as of December 31, 2017 and 2016, respectively. The liabilities are reduced by cash distributions to the third-party investors, the allocation of production tax credits to the third-party investors, and the federal income tax impact to the third-party investors of the allocation of taxable losses. The assets and liabilities of the VIEs totaled approximately $1,441 million and $185 million, respectively, at December 31, 2017. As of December 31, 2016 the assets and liabilities of VIEs totaled approximately $1,343 million and $244 million, respectively. At December 31, 2017 and 2016, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment, equity method investments and other liabilities. At December 31, 2017 and 2016, equity method investments of VIEs were approximately $107 million and $161 million, respectively. At December 31, 2017, we consider Aeolus Wind Power II LLC and Aeolus Wind Power IV LLC, (collectively, Aeolus) to be TEFs. In February and November 2017, we acquired the tax equity investor’s interest in other TEFs, Locust Ridge Wind Farm, LLC and Aeolus Wind Power III LLC, for $5 million and $15 million, respectively. These acquisitions converted the partnerships to single member limited liability companies and they no longer qualify as VIEs. Lastly, at December 31, 2017, we consider El Cabo Wind, LLC to be a VIE. We retain a class of membership interest and day-to-day operational and management control of Aeolus, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any Aeolus assets and have no recourse against us for their upfront cash payments. Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits generated by Aeolus, we have entered into the Aeolus structured institutional partnership investment transactions related to certain wind farms. Under the Aeolus structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the Aeolus limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and issuance of fixed and contingent notes. The third party investors receive a disproportionate amount of the profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the Company taking a disproportionate share of such amounts thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met. Our Aeolus interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests.

Grants, Government Incentives a

Grants, Government Incentives and Deferred Income	12 Months Ended
	Dec. 31, 2017
Deferred Revenue Disclosure [Abstract]
Grants, Government Incentives and Deferred Income	Note 19. Grants, Government Incentives and Deferred Income The changes in deferred income as of December 31, 2017 and 2016 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2015 $ 1,529 $ 24 $ 1,553 Additions — — — Recognized in income (68 ) (2 ) (70 ) As of December 31, 2016 $ 1,461 $ 22 $ 1,483 Additions 33 2 35 Reclassified to held for sale — (2 ) (2 ) Recognized in income (67 ) (3 ) (70 ) As of December 31, 2017 $ 1,427 $ 19 $ 1,446 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 within the nontaxable grant revenue deferred income tax liabilities (see Note 14 – Income Taxes) 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, 2017 and 2016. Other deferred income relates predominantly to gas storage transactions where revenues are recognized as services are provided. As of December 31, 2017, we reclassified $2 million of other deferred income to liabilities held for sale in the consolidated balance sheet (see Note 25 - Assets Held for Sale). There was no amount classified as liabilities held for sale as of December 31, 2016.

Equity Method Investments

Equity Method Investments	12 Months Ended
	Dec. 31, 2017
Equity Method Investments And Joint Ventures [Abstract]
Equity Method Investments	Note 20. Equity method investments We have a 50-50 joint venture with Shell Wind Energy, Inc., which owns and operates a 162- megawatt (MW) wind farm located in southeast Colorado (Colorado Wind Ventures LLC), which commenced operations in January 2004. We account for this venture under the equity method of accounting. The carrying amount of this investment was $18 million and $45 million as of December 31, 2017 and 2016, respectively. During the year ended December 31, 2017 we recorded an OTTI of $49 million on this investment. The We have two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC and the Flat Rock Wind Power II LLC wind farms located in upstate New York. Flat Rock Wind Power LLC, which commenced operations in January 2006, has a 231-MW capacity. Flat Rock Wind Power II LLC commenced operations in September 2007 and has a 91-MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. The carrying amount of these investments was $120 million and $128 million for Flat Rock Wind Power LLC, and $57 million and $64 million for Flat Rock Wind Power II LLC, as of December 31, 2017 and 2016, respectively. In 2017 we also acquired a 50% ownership in Vineyard Wind, LLC joint venture from Copenhagen Infrastructure Partners to build and operate the offshore wind facility to be developed off of Martha’s Vineyard with a nameplate capacity of approximately 1,600 MW . 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 $124 million and $128 million as of December 31, 2017 and 2016, respectively. Networks holds an approximate 20% ownership interest in New York TransCo. New York TransCo was established by the New York transmission utilities to develop, own, and operate electric transmission in New York. The investment in New York TransCo is being accounted for as an equity investment, the carrying value of which was $23 million and $22 million as of December 31, 2017 and 2016, respectively (See also Note 23). None of our joint ventures have any contingent liabilities or capital commitments. Distributions received from equity method investments amounted to $20 million, $20 million, and $12 million for the years ended December 31, 2017, 2016, and 2015 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. In addition, during the year ended December 31, 2017, we received $3.5 million of distributions in RECs from our equity method investments. As of December 31, 2017, there was an immaterial amount of undistributed earnings from our equity method investments. During the year ended December 31, 2016, we completed the sale of our interest in Iroquois Gas Transmission System L.P. (Iroquois) to an unaffiliated third party for proceeds of $ 53.8 19.0

Other Financial Statements Item

Other Financial Statements Items	12 Months Ended
	Dec. 31, 2017
Receivables [Abstract]
Other Financial Statements Items	Note 21. Other Financial Statements Items Other income Other income for the years ended December 31, 2017, 2016 and 2015 consisted of: Years ended December 31, 2017 2016 2015 (Millions) Allowance for funds used during construction $ 36 $ 26 $ 21 Carrying costs on regulatory assets 11 14 28 Other 11 36 7 Total Other Income $ 58 $ 76 $ 56 In 2016 included in “Other” is a gain of $33 million resulted from the sale of our interest in Iroquois in 2016 (See Note 20). Accounts Receivable Accounts receivable as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Trade receivables $ 1,104 $ 1,183 Allowance for bad debts (64 ) (64 ) Total Accounts Receivable $ 1,040 $ 1,119 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, 2017 and 2016 consisted of: (Millions) As of December 31, 2014 $ 49 Current period provision 46 Write-off as uncollectible (33 ) As of December 31, 2015 $ 62 Current period provision 48 Write-off as uncollectible (46 ) As of December 31, 2016 $ 64 Current period provision 69 Write-off as uncollectible (69 ) As of December 31, 2017 $ 64 DPA receivable balances were $55 million and $54 million as of December 31, 2017 and 2016, respectively. Prepayments and Other Current Assets Prepayments and other current assets as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Prepaid other taxes $ 194 $ 153 Broker margin and collateral accounts 32 32 Loans to third parties 2 3 Fixed-term deposits — 3 Other pledged deposits 9 8 Prepaid expenses 33 53 Other 3 3 Total $ 273 $ 255 Other Non-current Assets Included in “Other non-current assets” as of December 31, 2016, are $186 million of safe harbor turbine payments made for production tax credit qualification purposes. Other current liabilities Other current liabilities as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Advances received $ 113 $ 107 Accrued salaries 87 84 Short-term environmental provisions 69 34 Collateral deposits received 43 45 Pension and other postretirement 5 5 Other 13 4 Total $ 330 $ 279

Segment Information

Segment Information	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Segment Information	Note 22. Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following three reportable segments: ● Networks: including all the energy transmission and distribution activities, and any other regulated activity originating in New York and Maine, and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. ● Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. ● Gas: including gas trading and storage businesses carried on by the AVANGRID Group Products and services are sold between reportable segments and affiliate companies at cost. The chief operating decision maker evaluates segment performance based on segment adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) defined as net income adding back net income attributable to other non-controlling interests, Segment information as of and for the year ended December 31, 2017 consisted of: For the year ended December 31, 2017 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 4,950 $ 1,038 $ (26 ) $ 1 $ 5,963 Revenue - intersegment 11 9 41 (61 ) — Impairment — — 642 — 642 Depreciation and amortization 474 325 25 — 824 Operating income (loss) 994 92 (701 ) — 385 Adjusted EBITDA 1,468 417 (34 ) — 1,851 Earnings (loss) from equity method investments 15 (55 ) — — (40 ) Interest expense, net of capitalization 244 28 24 (16 ) 280 Income tax expense (benefit) 316 (320 ) (212 ) (43 ) (259 ) Capital expenditures 1,305 1,097 7 7 2,416 As of December 31, 2017 Property, plant and equipment 13,876 8,786 — 7 22,669 Equity method investments 147 205 — — 352 Total assets $ 21,411 $ 11,308 $ 383 $ (1,431 ) $ 31,671 (a) Does not represent a segment. I Included in revenue-external for the year ended December 31, 2017 are: $3,585 million from regulated electric operations, $1,375 million from regulated gas operations and $(10) million from other operations of Networks; $1,038 million from renewable energy generation of Renewables; $(25) million from gas storage services and $1 million from gas trading operations of Gas. AVANGRID made a net non-cash capital contribution of $921 million in Renewables in 2017, which was used by Renewables to settle outstanding intercompany debt payables of Gas segment accumulated prior to August 2017. The elimination of this activity between Renewables and Gas is included in Other at December 31, 2017. Segment information as of and for the year ended December 31, 2016 consisted of: For the year ended December 31, 2016 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 5,027 $ 1,000 $ (7 ) $ (2 ) $ 6,018 Revenue - intersegment 3 15 39 (57 ) — Depreciation and amortization 466 313 25 — 804 Operating income (loss) 1,086 149 (41 ) — 1,194 Adjusted EBITDA 1,552 462 (16 ) — 1,998 Earnings (loss) from equity method investments 15 (8 ) — — 7 Interest expense, net of capitalization 252 50 25 (59 ) 268 Income tax expense (benefit) 415 7 (22 ) (23 ) 377 Capital expenditures 1,140 561 6 — 1,707 As of December 31, 2016 Property, plant and equipment 13,032 8,015 501 — 21,548 Equity method investments 151 236 — — 387 Total assets $ 20,753 $ 9,884 $ 1,124 $ (452 ) $ 31,309 (a) Does not represent a segment. I Included in revenue-external for the year ended December 31, 2016 are: $3,686 million from regulated electric operations, $1,306 million from regulated gas operations and $35 million from other operations of Networks; $1,000 million from renewable energy generation of Renewables; $7 million from gas storage services and $(14) million from gas trading operations of Gas. Segment information as of and for the year ended December 31, 2015 consisted of: For the year ended December 31, 2015 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,386 $ 1,051 $ (71 ) $ 1 $ 4,367 Revenue - intersegment — 16 52 (68 ) — Impairment — 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 — Interest expense, net of capitalization 227 54 31 (45 ) 267 Income tax expense (benefit) 146 8 (44 ) (81 ) 29 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. Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the years ended December 31, 2017, 2016 and 2015, respectively, is as follows: Years Ended December 31, 2017 2016 2015 (Millions) Consolidated Adjusted EBITDA $ 1,851 $ 1,998 $ 1,220 Less: Impairment 642 — 12 Depreciation and amortization 824 804 695 Interest expense, net of capitalization 280 268 267 Income tax expense (259 ) 377 29 Add: Other income 58 76 56 Earnings from equity method investments (40 ) 7 — Consolidated Net Income $ 382 $ 632 $ 273

Related Party Transactions

Related Party Transactions	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Related Party Transactions	Note 23. Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the years ended December 31, 2017, 2016 and 2015, respectively, consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Financiación, S.A. $ — $ (2 ) $ — $ (2 ) $ — $ (1 ) Iberdrola Renovables Energia, S.L. — (9 ) — (8 ) — (9 ) Iberdrola Canada Energy Services, Ltd — (33 ) — (37 ) — (55 ) Iberdrola, S.A. 1 (36 ) — (31 ) — (35 ) Iberdrola Energia Monterrey, S.A. de C.V. 46 — 18 — — — Other 1 (1 ) 3 (1 ) 3 (2 ) In addition to the statements of income items above we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola has an 8.1% ownership. The amounts capitalized for these transactions were $266 million and $269 million for the years ended December 31, 2017 and 2016, respectively. In addition, included in “Other non-current assets” were $92 million of safe harbor turbine payments we made to Siemens-Gamesa as of December 31, 2016 (see Note 21). Related party balances as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd $ — $ (31 ) $ — $ (14 ) Siemens-Gamesa 2 (51 ) 1 (181 ) Iberdrola, S.A. 1 (32 ) — (30 ) Iberdrola Renovables Energía, S.L. — — 2 — Iberdrola Energia Monterrey, S.A. de C.V. 1 — 11 — Other 6 (4 ) 11 (3 ) Transactions with our parent company, Iberdrola, relate predominantly to the provision and allocation of corporate services and management fees. Also included within the Purchases From category are charges for credit support relating to guarantees Iberdrola has provided to third parties guaranteeing our performance. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID any costs remaining after direct charge are allocated using agreed upon cost allocation methods designed to allocate those costs. We believe that the allocation method used is reasonable. Transactions with Iberdrola Canada Energy Services (ICES) predominantly relate to the purchase of gas for ARHI’s gas-fired generation facility at Klamath, Oregon. Included in the amounts owed to ICES is the balance of notes payable of $29 million and $10 million as of December 31, 2017 and December 31, 2016, respectively. Transactions with Iberdrola Energia Monterrey predominantly relate to the sale of gas by Gas for the power generation plant in Monterrey, Mexico. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances, other than a $10 million write-off related to an arrangement to purchase turbines from Siemens-Gamesa, which was recorded in impairment in the consolidated statements of income for the year ended December 31, 2015. Networks holds an approximate 20 21 22 67 43 22 2 99 AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both December 31, 2017 and 2016, was zero.

Stock-Based Compensation

Stock-Based Compensation	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Stock-Based Compensation	Note 24. Stock-Based Compensation Under the Avangrid, Inc. Omnibus Incentive Plan 1,298,683 performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in July 2016. In March and October 2017 an additional 85,759 PSUs were granted to officers and employees of AVANGRID under this plan. The PSUs will vest upon achievement of certain performance and market-based metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020, 2021 and 2022. As of December 31, 2017, the total number of shares authorized for stock-based compensation plans was 2,500,000. The fair value of the PSUs on the grant date was $31.80 per share, which is expensed on a straight-line basis over the requisite service period of approximately seven years based on expected achievement. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recent quarterly dividend payment and the stock price as of the grant date. In connection with the acquisition of UIL, certain PSUs granted under the UIL 2008 Stock and Incentive Compensation Plan are outstanding, which are payable in our shares in 2018 and vest based upon the achievement of certain pre-determined performance objectives. The total stock-based compensation expense, which is included in operations and maintenance of the consolidated statements of income for the years ended December 31, 2017, 2016 and 2015 was $1.2 million, $0.6 million and $6.0, respectively. The total income tax benefit recognized for stock-based compensation arrangements for the years ended December 31, 2017, 2016 and 2015, was $0.5 million, $0.2 million and $2.4 million, respectively. Before 2016, AVANGRID’s historical stock-based compensation expense and liabilities were based on shares of Iberdrola and not on shares of AVANGRID. These Iberdrola shares-based awards were early terminated at the end of 2015, and the remaining liability will be settled in March 30, 2018. The total liability relating to those awards, which is included in other current and non-current liabilities, was $5.5 million and $9.5 million as of December 31, 2017 and 2016, respectively. A summary of the status of the AVANGRID's nonvested PSUs as of December 31 , 2017 December 31, 2017 Number of PSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2016 1,523,981 $ 33.01 Granted 94,509 $ 32.89 Forfeited (113,256 ) $ 31.91 Vested (120,975 ) $ 40.07 Nonvested Balance – December 31, 2017 1,384,259 $ 32.57 As of December 31, 2017, total unrecognized costs for non-vested PSUs were $5.1 million. The weighted-average period over which the PSU costs will be recognized is approximately 4 years. The weighted-average grant date fair value of PSUs granted during the year was $32.89 per share for the year ended December 31, 2017.

Assets Held for Sale

Assets Held for Sale	12 Months Ended
	Dec. 31, 2017
Assets Held For Sale Not Part Of Disposal Group [Abstract]
Assets Held for Sale	Note 25. Assets Held For Sale In December 2017, our management committed to a plan to sell the gas trading and storage businesses because they represent non-core businesses that are not aligned with our strategic objectives. As a result, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. The gas trading and storage businesses are being marketed for sale, and it is the Company’s intention to complete the sales of these assets and liabilities within twelve months following their initial classification as held for sale. On March 1, 2018, the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI) for $64.5 million, subject to working capital, cash, and other adjustments. The transaction price does not differ materially from the estimated fair value of our gas trading business at December 31, 2017, subject to adjustment based on closing and other contract provisions, including certain transition services. On February 16, 2018, the Company entered into a definitive agreement to sell Enstor Gas, LLC, which operates AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC for $75 million, subject to working capital, cash, and other adjustments. The agreement to sell Enstor Gas, LLC contains, among other things, a transition services agreement which obligates ARHI to provide certain transition services for up to one year after the closing date and includes a guarantee that the Company will release certain obligations to Amphora Gas Storage USA, LLC, along with representations, warranties, and covenants customary for a transaction of this nature. The transaction, which is subject to the satisfaction of customary closing conditions, is expected to be completed during the second quarter of 2018. The transaction price differs from the estimated fair value of our gas storage business at December 31, 2017 by approximately $11 million, in which we expect to recognize an additional after-tax loss of $8.1 million in 2018, subject to additional adjustment based on closing and other contract provisions . As of December 31, 2017 (Millions) Accounts receivable, net $ 137 Derivative assets 25 Fuel and gas in storage 77 Prepayments and other current assets 19 Property, plant and equipment 71 Intangible assets 28 Assets held for sale $ 357 Accounts payable and accrued liabilities 107 Derivative liabilities 14 Other liabilities 16 Liabilities held for sale $ 137 The fair values of the assets held for sale were determined using Level 3 inputs and were estimated based on recent market analysis studies, recent offers, and management has performed its own fair valuation modeling using discounted cash flows updated for market participant assumptions as completed by third party valuation firms. Unobservable inputs obtained from third parties were adjusted as necessary for the condition and attributes of the specific assets.

Restructuring and Severance Rel

Restructuring and Severance Related Expenses	12 Months Ended
	Dec. 31, 2017
Restructuring And Related Activities [Abstract]
Restructuring and Severance Related Expenses	Note 26. Restructuring and Severance Related Expenses In the second and third quarters of 2017, we announced targeted voluntary workforce reductions, predominantly within the Networks segment. Those actions primarily include: reducing our workforce through voluntary programs in various other areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology (IT) workforce to make increasing use of external services for operations, support, and development of systems. Year Ended December 31, 2017 (Millions) Beginning Balance $ — Restructuring and severance related expenses 19 Payments (14 ) Ending Balance $ 5

Quarterly Financial Data (unaud

Quarterly Financial Data (unaudited)	12 Months Ended
	Dec. 31, 2017
Selected Quarterly Financial Information [Abstract]
Quarterly Financial Data (unaudited)	Note 27. Quarterly financial data (unaudited) Selected quarterly financial data for 2017 and 2016 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 2017 Operating revenues $ 1,758 $ 1,331 $ 1,341 $ 1,533 Operating Income $ 398 $ 223 $ 189 $ (425 ) Net Income $ 239 $ 120 $ 100 $ (77 ) Net Income attributable to Avangrid, Inc. $ 239 $ 120 $ 99 $ (77 ) Earnings Per Common Share, Basic and Diluted: (1) $ 0.77 $ 0.39 $ 0.32 $ (0.25 ) 2016 Operating revenues $ 1,670 $ 1,439 $ 1,418 $ 1,491 Operating Income $ 349 $ 322 $ 217 $ 306 Net Income $ 213 $ 101 $ 109 $ 209 Net Income attributable to Avangrid, Inc. $ 213 $ 101 $ 109 $ 209 Earnings Per Common Share, Basic and Diluted: (1) $ 0.69 $ 0.33 $ 0.35 $ 0.67 (1) Based on weighted average number of 309.5 million and 309.8 million shares outstanding each quarter in 2017 and 2016 for basic and diluted earnings per share, respectively. The first quarter of 2017 includes an adjustment of $14 million to unfunded future income tax to reflect the change from a flow through to normalization method, which was recorded as an increase to income tax expense and an offsetting increase to revenue. The third and fourth quarters of 2017 include severance and lease restructuring charges of, respectively, $2.1 million and $17.1 million. Additionally the fourth quarter includes a loss of $642 million associated with measurement of held for sale assets of gas trading and storage business, $463 million after income taxes, and an impact of $328 million from measurement of deferred income tax balances as a result of the Tax Act enacted on December 22, 2017 by the U.S. federal government. The first quarter of 2016 includes a $19.0 million impact to net income from the sale of our interest in Iroquois to an unaffiliated third party for proceeds of $53.8 million. The second quarter of 2016 includes an adjustment of $126 million to unfunded future income tax to reflect the change from a flow through to normalization method following the approval of the Joint Proposal by the NYPSC, which was recorded as an increase to income tax expense and an offsetting increase to revenue.

Subsequent Events

Subsequent Events	12 Months Ended
	Dec. 31, 2017
Subsequent Events [Abstract]
Subsequent Events	Note 28. Subsequent events On February 15, 2018, the board of directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable on April 2, 2018 to shareholders of record at the close of business on March 9, 2018. On March 7, 2018, we issued 81,208 shares of common stock, each having a par value of $0.01, which was approved by the board of directors of AVANGRID on February 15, 2018.

Acquisition of UIL and Issuance

Acquisition of UIL and Issuance of Common Stock	12 Months Ended
	Dec. 31, 2017
Avangrid, Inc [Member]
Acquisition of UIL and Issuance of Common Stock	Note 2. Acquisition of UIL and Issuance of Common Stock On December 16, 2015 (acquisition date), UIL Holdings Corporation, a Connecticut corporation (UIL), became a wholly-owned subsidiary of AVANGRID as a result of the merger of Green Merger Sub, Inc., a Connecticut corporation and a wholly-owned subsidiary of AVANGRID (Merger Sub), with UIL, with Merger Sub surviving as a wholly-owned subsidiary of AVANGRID (the acquisition). The acquisition was effected pursuant to the Agreement and Plan of Merger, dated as of February 25, 2015, by and among AVANGRID, Merger Sub, and UIL. Following the completion of the acquisition, Merger Sub was renamed “UIL Holdings Corporation.” In connection with the acquisition, AVANGRID issued 309,490,839 shares of its common stock, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per each share of the common stock of UIL issued and outstanding at the acquisition date. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID and Iberdrola owned the remaining shares. AVANGRID had 485,810 and 491,459 shares of common stock held in trust and no convertible preferred shares outstanding as of December 31, 2017 and December 31, 2016, respectively. During the year ended December 31, 2017, AVANGRID issued 70,493 shares of common stock and released 5,649 shares of common stock held in trust each having a par value of $0.01. During the year ended December 31, 2016, AVANGRID issued 109,357 shares of common stock and released 135,014 shares of common stock held in trust each having a par value of $0.01. On April 28, 2016, AVANGRID entered into a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage of Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. 179,850 The total cost of repurchase, including commissions, was $8 million as of December 31, 2017. On February 15, 2018, the board of directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable on April 2, 2018 to shareholders of record at the close of business on March 9, 2018.

Non-current Debt

Non-current Debt	12 Months Ended
	Dec. 31, 2017
Avangrid, Inc [Member]
Non-current Debt	Note 3. Non-current Debt Supplemental Indenture On December 19, 2016, AVANGRID, its subsidiary, UIL, and The Bank of New York Mellon, entered into a supplemental indenture, pursuant to which AVANGRID assumed from UIL all the obligations under the indenture dated as of October 7, 2010 between UIL and The Bank of New York Mellon and all obligations relating to $450 million in aggregate principal amount of 4.625% notes due 2020 issued by the predecessor company to UIL in 2010. For the purpose of the supplemental indenture a capital contribution of $483 million was made by AVANGRID to UIL in December 2016. On November 21, 2017, AVANGRID issued $600 million aggregate principal amount of its 3.150% notes maturing in 2024. Proceeds of the offering were used to reduce short-term debt incurred to fund capital expenditures associated with development of renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $594 million.

Cash Dividends Paid by Subsidia

Cash Dividends Paid by Subsidiaries	12 Months Ended
	Dec. 31, 2017
Avangrid, Inc [Member]
Cash Dividends Paid by Subsidiaries	Note 4. Cash Dividends Paid by Subsidiaries Cash dividends paid by subsidiaries are as follows: Years ended December 31, 2017 2016 2015 (In millions) AVANGRID Networks $ 308 $ 220 $ 59 AVANGRID Renewables — 200 750 Other AVANGRID subsidiaries — — 302 $ 308 $ 420 $ 1,111 In December 2016, AVANGRID made a capital contribution of $50 million to its subsidiary, CMP. During 2017 and 2016, AVANGRID recorded a net non-cash contribution and dividend of $1,318 million and $(827) million, respectively, to and from its subsidiaries to zero out their account balances of notes receivables and payables.

Summary of Significant Accoun42

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Policies)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Principles of Consolidation	(a) Principles of consolidation We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. Investments in common stock where we have the ability to exercise significant influence, but not control, are accounted for using the equity method of accounting.
Revenue Recognition	(b) Revenue recognition Revenue from the sale of energy by our regulated utilities is recognized in the period during which the sale occurs. The calculation of revenue earned but not yet billed is based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are usually immaterial. Revenues on sales of wholesale energy and energy related products and natural gas are recognized either when the service is provided or the product is delivered. We also provide natural gas storage services to customers. The natural gas remains the property of these customers at all times. Customers pay a two part rate that includes (i) a fixed fee reserving the right to store natural gas in our facilities and, (ii) a per unit rate for volumes actually injected into or withdrawn from storage. The fixed fee component of the overall rate is recognized as revenue in the period the service is provided. The per-unit charge is recognized as revenue when the volumes are injected into or withdrawn from our storage facilities.
Regulatory Accounting	(c) Regulatory accounting We account for our regulated utilities operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by a third-party regulator; (ii) rates are designed to recover the entity’s cost of providing regulated services or products, and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs. Regulatory assets and liabilities are amortized and the related expense or revenue is recognized in the consolidated statements of income consistent with the recovery or refund included in customer rates. We believe that it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.
Business Combinations and Assets Acquisitions	(d) Business combinations and assets acquisitions We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred by the acquirer to former owners of acquiree and the equity interests issued by the acquirer. Acquisition related costs are expensed as incurred. Identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination are measured initially at their fair values at the acquisition date. The excess of the consideration transferred over the fair value of the identifiable net assets acquired is recorded as goodwill. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. In contrast to a business combination, we classify a transaction as an asset acquisition when substantially all of the fair value of the gross assets acquired is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business.
Equity Method Investments	(e) Equity method investments We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as “Earnings (losses) from equity method investments.” We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that is determined to be other than temporary (OTTI).
Goodwill and Other Intangible Assets	(f) Goodwill and other intangible assets Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed. Goodwill is not amortized, but is subject to an assessment for impairment at least annually or more frequently if events occur or circumstances change that will more likely than not reduce the fair value of the reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which goodwill is tested for impairment. In assessing goodwill for impairment we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary (step zero). If it is determined, on the basis of qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass step zero or perform the qualitative assessment, but determine that it is more likely than not that its fair value is less than its carrying amount, a quantitative two step fair value based test is performed. Step one compares the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, step two is performed. Step two requires an allocation of fair value to the individual assets and liabilities using business combination accounting guidance to determine the implied fair value of goodwill. If the implied fair value of goodwill is less than its carrying amount, an impairment loss is recorded as a reduction to goodwill and a charge to operating expense. Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite. Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in the consolidated statements of income as the expense category that is consistent with the function of the intangible assets.
Property, Plant and Equipment	(g) Property, plant and equipment Property, plant and equipment are accounted for at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, the estimated cost of removal or reconditioning is recorded as an asset retirement obligation (ARO) and an equal amount is added to the carrying amount of the asset. Development and construction of our various facilities are carried out in stages. Project costs are expensed during early stage development activities. Once certain development milestones are achieved and it is probable that we can obtain future economic benefits from a project, salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs are capitalized. Development projects in construction are reviewed periodically for any indications of impairment. Assets are transferred from “Construction work in progress” to “Property, plant and equipment” when they are available for service. Wind turbine and related equipment costs, other project construction costs, and interest costs related to the project are capitalized during the construction period through substantial completion. AROs are recorded at the date projects achieve commercial operation. The cost of plant, and equipment in use is depreciated on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 35-90 Plant Wind power stations 20-40 Transport facilities 33-70 Distribution facilities 15-82 Equipment Conventional meters and measuring devices 15-41 Computer software 4-10 Other Buildings 30-82 Operations offices 5-75 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. Allowance for funds used during construction (AFUDC) is a noncash item which represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of interest expense and the remainder is recorded as other income.
Impairment of Long-lived Assets	(h) Impairment of long lived assets We evaluate property, plant, and equipment and other long lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying amount of the long lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow model.
Fair Value Measurement	(i) Fair value measurement Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability. The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use. We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date. The three input levels of the fair value hierarchy are as follows: ● Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets. ● Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract. ● Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data. Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair valu e.
Available for Sale Securities	(j) Available for sale securities Securities that do not qualify as either securities held-to-maturity or trading securities, and which have a readily available fair value, are classified as securities available-for-sale and reported at fair value, with unrealized gains and losses excluded from earnings and reported, net of taxes, in other comprehensive income or loss.
Derivatives and Hedge Accounting	(k) Derivatives and hedge accounting Derivatives are recognized on the balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. Changes in the fair value of a derivative contract are recognized in earnings unless specific hedge accounting criteria are met. Derivatives that qualify and are designated for hedge accounting are classified as cash flow hedges. For cash flow hedges, the portion of the derivative gain or loss that is effective in offsetting the change in the hedged cash flows of the underlying exposure is deferred in Other Comprehensive Income (OCI) and later reclassified into earnings when the underlying transaction occurs. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, hedge accounting will be discontinued prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, hedge gains and losses previously recorded in OCI are immediately recognized in earnings. Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. Gains and losses from the ineffective portion of any hedge are recognized in earnings immediately. Changes in the fair value of electric and natural gas hedge contracts are recorded to derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities for our regulated operations. We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.
Cash and Cash Equivalents	(l) Cash and cash equivalents Cash and cash equivalents comprises cash, bank accounts, and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and those investments are included in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on the consolidated balance sheets. Book overdrafts representing outstanding checks in excess of funds on deposit are classified as “Accounts payable and accrued liabilities” on the consolidated balance sheets. Changes in book overdrafts are reported in the operating activities section of the consolidated statements of cash flows.
Accounts Receivable and Unbilled Revenue, Net	(m) Accounts receivable and unbilled revenue, net We record accounts receivable at amounts billed to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances, which are settled on a net basis. Receivables and payables subject to such agreements are presented in our consolidated balance sheets on a net basis. Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as short term. The allowance for bad debts account is established by using both historical average loss percentages to project future losses, and a specific allowance is established for known credit issues. Amounts are written off when we believe that a receivable will not be recovered.
Variable Interest Entities	(n) Variable interest entities We evaluate whether an entity is a variable interest entity (VIE) whenever reconsideration events as defined by the accounting guidance occur (See Note 18). An entity is considered to be a VIE when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses or the right to receive benefits from the VIE that could potentially be significant to the VIE. 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. Bonds, debentures and bank borrowings are presented net of unamortized discount, premium and debt issuance costs on the consolidated balance sheets.
Inventory	(p) Inventory Inventory comprises fuel and gas in storage and materials and supplies. Through our gas trading operations, we own natural gas that is stored in both self-owned and third-party owned underground storage facilities. This gas is recorded as inventory. Injections of inventory into storage are priced at the market purchase cost at the time of injection, and withdrawals of working gas from storage are priced at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable 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 the lower of cost and net realizable value and reported on the balance sheets within “Materials and supplies.” Inventory items are combined for the statement of cash flow presentation purposes.
Government Grants	(q) Government grants Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings consistent with the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting. In accounting for government grants related to operating and maintenance costs, amounts receivable are recognized as an offset to expenses in the consolidated statements of income in the period in which the expenses are incurred.
Deferred Income	(r) Deferred income Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting obligations arising from the transaction. It is our policy to defer such revenues on the consolidated balance sheets and amortize them to earnings consistent with the obligations.
Asset Retirement Obligations	(s) Asset retirement obligations The fair value of the liability for an ARO and a conditional ARO is recorded in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long lived asset. The ARO is associated with our long lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains, and electricity generation facilities. The liability is adjusted periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, the obligation will be either settled at its recorded amount or a gain or a loss will be incurred. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability. The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred. Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. These are classified as accrued removal obligations.
Environmental Remediation Liability	(t) Environmental remediation liability In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. Our environmental liabilities are recorded on an undiscounted basis. Our environmental liability accruals are expected to be paid through the year 2054.
Post Employment and Other Employee Benefits	(u) Post-employment and other employee benefits We sponsor defined benefit pension plans that cover the majority of our employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees. We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management. We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking process. We use a December 31st measurement date for our benefits plans. We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. For NYSEG, RG&E and UIL, we amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. For our other companies we use the standard amortization methodology under which amounts in excess of ten percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five year period.
Income Tax	(v) Income tax AVANGRID will file a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries for the 2017 tax period, which is consistent with the 2016 tax period. For the 2015 tax year, AVANGRID filed a consolidated federal income tax return, which included the UIL taxable income or loss for the period from December 17, 2015 to December 31, 2015. UIL filed a separate consolidated federal income tax return for the period from January 1, 2015 to December 16, 2015. AVANGRID filed a consolidated federal income tax return that includes the taxable income or loss of all its subsidiaries (excluding UIL), including ARHI, which are 80% or more owned for the 2014 tax period. UIL filed separate consolidated federal income tax returns including the income or loss of its subsidiaries for all tax years including the filed 2014 return. AVANGRID (excluding ARHI and UIL), and ARHI each filed separate consolidated federal income tax returns that included the taxable income or loss of all their respective subsidiaries, which are 80% or more owned, for all tax periods prior to 2013. We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with generally accepted accounting principles for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. The investment tax credits are deferred when used and amortized over the estimated lives of the related assets. Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. Deferred tax assets and liabilities are classified as non-current in the consolidated balance sheets. The excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital is recorded in “Taxes other than income taxes” and “Taxes accrued” in the accompanying consolidated financial statements. Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” of the consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income. Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities. Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements. On December 22, 2017, the President of the United States signed into law legislation referred to as the “Tax Cuts and Jobs Act” (the Tax Act). The Tax Act includes significant changes to the Internal Revenue Code of 1986 (as amended, the Code), including amendments which significantly change the taxation of business entities, and includes specific provisions related to regulated public utilities. The most significant change that impacted the Company was the permanent reduction in the corporate federal income tax rate from 35% to 21%, which required us to measure existing net deferred tax liabilities using the lower rate in the period of enactment, resulting in an income tax benefit. The specific provisions in the Tax Act related to regulated public utilities generally allow for the continued deductibility of interest expense, the elimination of full expensing for tax purposes of certain property acquired after September 27, 2017, and continues certain rate normalization requirements for accelerated depreciation benefits. The staff of the US Securities and Exchange Commission (SEC) has recognized the complexity of reflecting the impacts of the Tax Act, and on December 22, 2017, issued guidance in Staff Accounting Bulletin 118 (SAB 118) which clarifies accounting for income taxes under ASC 740 if information is not yet available or complete and provides for up to a one year period in which to complete the required analyses and accounting (the measurement period). The Company has completed or has made a reasonable estimate for the measurement and accounting of certain effects of the Tax Act which have been reflected in the December 31, 2017 financial statements. The Company has reported provisional amounts for the income tax effects related to the remeasurement of our deferred tax assets and liabilities. The ultimate impact may differ (materially) from the provisional amounts, among other things, as a result of additional analysis, changes in interpretations and assumptions, the release of additional guidance by the Internal Revenue Service, Treasury Department, and other standard-setting bodies. There were no specific impacts that could not be reasonably estimated
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 reflecting forfeitures when they occur. The recognition period for these costs begin at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier.
Assets Held for Sale	(x) Assets held for sale We record assets held for sale at the lower of the carrying value or fair value less costs to sell. The following criteria are used to determine if an entity or a group of components of an entity is held for sale: (i) management has the authority and commits to a plan to sell the entity; (ii) the entity is available for immediate sale in its present condition; (iii) there is an active program to locate a buyer and the plan to sell the entity has been initiated; (iv) the sale of the entity is probable within one year; (v) the entity is being actively marketed at a reasonable price relative to its current fair value; and (vi) it is unlikely that the plan to sell will be withdrawn or that significant changes to the plan will be made. In determining the fair value of the assets less costs to sell, we consider factors including recent market analysis studies, recent offers, and fair value models. If the estimated fair value less costs to sell of an entity is less than its current carrying value, the entity is written down to its estimated fair value less costs to sell. Due to uncertainties in the estimation process, actual results could differ from the estimates used in our historical analysis. We estimate the fair values of assets held for sale based on current market and industry conditions, which include assumptions made by management, which may differ from actual results and may result in additional impairments if market conditions deteriorate. Once assets are classified as held for sale, we do not record depreciation or amortization for our property, plant, and equipment and intangible assets.
New Accounting Standards and Interpretations	New Accounting Standards and Interpretations (a) Revenue from contracts with customers In May 2014, the Financial Accounting Standards Board (FASB) in an amount derived from the commodities delivered to customers. Revenues from our Renewables (b) Classifying and measuring financial instruments In January 2016 the FASB issued final guidance on the classification and measurement of financial instruments. The new guidance requires that all equity investments in unconsolidated entities (other than those accounted for using the equity method of accounting) to be measured at fair value through earnings. There will no longer be an available-for-sale classification (changes in fair value reported in other comprehensive income) for equity securities with readily determinable fair values. For equity investments without readily determinable fair values, the cost method is also eliminated. However, entities (other than those following “specialized” accounting models, such as investment companies and broker-dealers) are able to elect to record equity investments without readily determinable fair values at cost, less impairment, and plus or minus subsequent adjustments for observable price changes. Changes in the basis of these equity investments will be reported in current earnings. That election only applies to equity investments that do not qualify for the NAV practical expedient. When the fair value option has been elected for financial liabilities, changes in fair value due to instrument-specific credit risk will be recognized separately in other comprehensive income. The accumulated gains and losses due to those changes will be reclassified from accumulated other comprehensive income to earnings if the financial liability is settled before maturity. Public entities are required to use the exit price notion when measuring the fair value of financial instruments measured at amortized cost for disclosure purposes. In addition, the new guidance requires financial assets and financial liabilities to be presented separately in the notes to the financial statements, grouped by measurement category (e.g., fair value, amortized cost, lower of cost or market) and form of financial asset (e.g., loans, securities). The classification and measurement guidance is effective for public entities in fiscal years beginning after December 15, 2017, including interim periods within those fiscal years. An entity will record a cumulative-effect adjustment to beginning retained earnings as of the beginning of the first reporting period in which the guidance is adopted, with two exceptions. The amendments related to equity investments without readily determinable fair values (including disclosure requirements) will be effective prospectively. The requirement to use the exit price notion to measure the fair value of financial instruments for disclosure purposes will also be applied prospectively. We expect our adoption of the guidance will not materially affect our consolidated (c) 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 FASB issued an update in January 2018 to clarify the application of the new leases guidance to land easements and provide relief concerning adoption efforts for existing land easements that are not accounted for as leases under current GAAP. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We are currently reviewing our contracts and are in the process of determining the proper application of the standard to these contracts in order to determine the impact that the adoption will have on our consolidated financial statements. We expect our adoption of the new guidance will materially affect our financial position through the recording of operating leases on the balance sheet as right-of-use assets, along with the corresponding liabilities. (d) Measurement of credit losses on financial instruments The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments. The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions, and reasonable and supportable forecasts that affect the collectability of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The amendments are effective for public entities that are SEC filers for fiscal years beginning after December 15, 2019, including interim periods within those fiscal years, with early adoption permitted. Entities are to apply the amendments on a modified retrospective basis for most instruments. We expect our adoption will not materially affect our consolidated (e) Certain classifications in the statement of cash flows The FASB issued amendments in August 2016 to address existing diversity in practice concerning eight cash flows issues. The guidance addresses classification as operating, investing or financing activities in the statement of cash flows for these issues: 1) Debt prepayment or debt extinguishment costs (financing), 2) Settlement of zero-coupon bonds (interest is operating, principal is financing), 3) Contingent consideration payments made after a business combination (investing or financing based on timing, or operating, as specified), 4) Proceeds from the settlement of insurance claims (based on the nature of the loss), 5) Proceeds from the settlement of corporate-owned life insurance policies (COLI) (investing; with cash payments for COLI premiums as investing, operating or a combination of investing/operating), 6) Distributions received from equity method investees (based on an entity’s accounting policy election: either cumulative earnings or nature of distribution), 7) Beneficial interests in securitization transactions (noncash or investing as specified), 8) Separately identifiable cash flows and application of the predominance principle (cash receipts/payments with aspects of more than one classification by applying specific GAAP guidance; or if there is no guidance, based on the nature of the related activity or the activity that is the predominant source or use of the cash flows). The amendments are effective for public entities for fiscal years beginning after December 15, 2017, and interim periods within those fiscal years, with early adoption permitted. The amendments are to be applied retrospectively to each prior period presented, unless impracticable for some issues and then the application would be prospective for those affected issues. We expect our adoption will not materially affect cash flows and disclosures. (f) Clarifying the definition of a business The FASB The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We early adopted the amendments in the third quarter of 2017 and, as required, are applying the amendments prospectively as of the beginning of the period of adoption. Other than with respect to the transaction described in Note 7 of these consolidated financial statements, our adoption of the amendments did not affect our consolidated results of operations, financial position, cash flows, and disclosures. (g) Simplifying the test for goodwill impairment In January 2017 the FASB (h) Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets The FASB The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. An entity must apply the amendments at the same time that it applies the new ASC 606 revenue recognition standard and may elect to apply the amendments retrospectively following either a full retrospective approach or a modified retrospective approach, but does not have to apply the same transition method as for ASC 606. Effective January 1, 2018, we have adopted ASC 610-20 and applied the modified retrospective method, which affected the accounting for our tax equity investments. Based on our assessment, we have recorded a cumulative adjustment that decreased retained earnings and additional paid in capital by an amount less than $100 million rather than retrospectively adjusting prior periods. The cumulative adjustment relates to the requirement that we reclassify our tax equity investments to noncontrolling interests. As a result, our tax equity investments will be recorded based on the Hypothetical Liquidation at Book Value (HLBV) model and changes in the HLBV at each reporting period will be recorded within net income attributable to noncontrolling interests, which will not result in a material difference to net income attributable to the Company for our current tax equity investments. (i) Improving the presentation of net periodic benefit costs In March 2017, the FASB issued amendments to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost in the financial statements. The amendments require an entity to present service cost separately from the other components of net benefit cost, and to report the service cost component in the income statement line item(s) where it reports the corresponding compensation cost. An entity is to present all other components of net benefit cost outside of operating cost. The amendments also allow only the service cost component to be eligible for capitalization when applicable (for example, as a cost of a self-constructed asset). The amendments are effective for public entities for annual and interim periods in fiscal years beginning after December 15, 2017, with early adoption permitted. We do not plan to early adopt. An entity is required to apply the amendments retrospectively for the presentation of the service cost component and the other components of net periodic pension cost and net periodic postretirement benefit cost in the income statement and prospectively, on and after the effective date, for the capitalization of the service cost component of net periodic pension cost and net periodic postretirement benefit in assets. A practical expedient allows an entity to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in the notes to financial statements for pension and postretirement benefit plans for those periods. We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows, and disclosures. (j) Targeted improvements to accounting for hedging activities In August 2017, the FASB issued targeted amendments with the objective to better align hedge accounting with an entity’s risk management activities in the financial statements, and to simplify the application of hedge accounting. The amendments address concerns of financial statement preparers over difficulties with applying hedge accounting and limitations for hedging both nonfinancial and financial risks and concerns of financial statement users over how hedging activities are reported in financial statements. Changes to the hedge accounting guidance to address those concerns will: 1) expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with an entity’s risk management activities; 2) eliminate the separate measurement and reporting of hedge ineffectiveness, to reduce the complexity of preparing and understanding hedge results; 3) enhance disclosures and change the presentation of hedge results to align the effects of the hedging instrument and the hedged item in order to enhance transparency, comparability, and understandability of hedge results; and 4) simplify the way assessments of hedge effectiveness may be performed to reduce the cost and complexity of applying hedge accounting. The amendments are effective for public entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted in any interim period after issuance of the amendments. We do not expect to early adopt. For cash flow and net investment hedges existing at the date of adoption, a company must apply a cumulative-effect adjustment related to the separate measurement of ineffectiveness to accumulated other comprehensive income (AOCI) with a corresponding adjustment to the opening balance of retained earnings as of the beginning of the fiscal year of adoption. The amended presentation and disclosure guidance is required only prospectively. An entity may make certain elections upon adoption to allow for existing hedging relationships to transition to newly allowable alternatives. We expect our adoption of the guidance will not materially affect our consolidated results of operations, financial position, or cash flows, but we expect the amendments will ease the administrative burden of hedge documentation requirements and assessing hedge effectiveness. (k) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018, the FASB issued amendments to address a narrow-scope financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) enacted on December 22, 2017, by the U.S. federal government. Under current guidance, the adjustment of deferred taxes for the effect of a change in tax laws or rates is required to be included in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings for stranded tax effects resulting from the Tax Act. As a result, the amendments eliminate the stranded tax effects resulting from the Tax Act and will improve the usefulness of information reported to financial statement users. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. The amendments are effective for all entities for fiscal years beginning after December 15, 2018, and interim periods within those fiscal years. Early adoption is permitted including, for public entities, adoption in any interim period for which financial statements have not been issued. An entity has the option to apply the amendments either in the period of adoption or retrospectively to each period (or periods) in which it recognizes the effect of the change in the U.S. federal corporate income tax rate in the Tax Act. An entity is required to disclose its accounting policy election, including its policy for reclassifying material stranded tax effects in AOCI to earnings (specific identification or portfolio method). We have not early adopted the amendments as of December 31, 2017. We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows, and disclosures.
Use of Estimates and Assumptions	Use of Estimates and Assumptions The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for doubtful accounts and unbilled revenues; (2) asset impairments, including goodwill; (3) investments in equity instruments; (4) depreciable lives of assets; (5) income tax valuation allowances; (6) uncertain tax positions; (7) reserves for professional, workers’ compensation, and comprehensive general insurance liability risks; (8) contingency and litigation reserves; (9) fair value measurements; (10) earnings sharing mechanisms; (11) environmental remediation liabilities; and (12) AROs. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates used in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates
Union Collective Bargaining Agreements	Union collective bargaining agreements We have approximately 48% of the employees covered by a collective bargaining agreement. Agreements which will expire within the coming year apply to approximately 8% of our employees.

Basis of Presentation (Tables)

Basis of Presentation (Tables)	12 Months Ended
	Dec. 31, 2017
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Effect of Correction on Consolidated Balance Sheet and Consolidated Statements of Income	A summary of the effect of the correction on the consolidated balance sheet as of December 31, 2016 is as follows: As of December 31, 2016 As Reported Correction As Revised (Millions) Deferred income taxes $ 2,976 $ (86 ) $ 2,890 Total Other Non-current Liabilities 6,647 (86 ) 6,561 Total Non-current Liabilities 13,475 (86 ) 13,389 Total Liabilities 16,187 (86 ) 16,101 Retained earnings 1,544 86 1,630 Total Stockholders' Equity 15,109 86 15,195 Total Equity 15,122 86 15,208 Total Liabilities and Equity $ 31,309 $ — $ 31,309 A summary of the effect of the correction on the consolidated statements of income for the years ended December 31, 2016 and 2015 is as follows: Year Ended December 31, 2016 As Reported Correction As Revised (Millions, except per share data) Other income $ 76 $ — $ 76 Income Before Income Tax 1,009 — 1,009 Income tax expense 379 (2 ) 377 Net Income 630 2 632 Net Income Per Common Share, Basic and Diluted: $ 2.04 $ — $ 2.04 Year Ended December 31, 2015 As Reported Correction As Revised (Millions, except per share data) Other income $ 55 $ 1 $ 56 Income Before Income Tax 301 1 302 Income tax expense 34 (5 ) 29 Net Income 267 6 273 Net Income Per Common Share, Basic and Diluted: $ 1.05 $ 0.02 $ 1.07

Summary of Significant Accoun44

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates (Tables)	12 Months Ended
	Dec. 31, 2017
Accounting Policies [Abstract]
Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 35-90 Plant Wind power stations 20-40 Transport facilities 33-70 Distribution facilities 15-82 Equipment Conventional meters and measuring devices 15-41 Computer software 4-10 Other Buildings 30-82 Operations offices 5-75

Industry Regulation (Tables)

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

Regulatory Assets and Liabili46

Regulatory Assets and Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Regulated Operations [Abstract]
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 24 $ 22 Pension and other post-retirement benefits 7 7 Storm costs 46 40 Temporary supplemental assessment surcharge — 4 Reliability support services 27 27 Revenue decoupling mechanism 21 15 Transmission revenue reconciliation mechanism 8 12 Electric supply reconciliation — 13 Hedges losses 3 10 Contracts for differences 9 14 Hardship programs 14 16 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 31 14 Deferred transmission expense 37 13 Environmental remediation costs 13 14 Other 51 48 Total Current Regulatory Assets 307 285 Non-current Pension and other post-retirement benefits cost deferrals 110 134 Pension and other post-retirement benefits 1,162 1,320 Storm costs 254 187 Deferred meter replacement costs 29 32 Unamortized losses on reacquired debt 17 20 Environmental remediation costs 283 287 Unfunded future income taxes 376 542 Asset retirement obligations 18 18 Deferred property tax 14 33 Federal tax depreciation normalization adjustment 155 161 Merger capital expense target customer credit 2 11 Debt premium 131 151 Reliability support services 10 29 Plant decommissioning 9 14 Contracts for differences 84 61 Hardship programs 13 18 Other 71 73 Total Non-current Regulatory Assets $ 2,738 $ 3,091
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Current Reliability support services (Cayuga) $ — $ 3 Non by-passable charges 5 22 Energy efficiency portfolio standard 37 45 Gas supply charge and deferred natural gas cost 4 6 Transmission revenue reconciliation mechanism 14 5 Pension and other post-retirement benefits 1 3 Pension and other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 21 15 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE refund 4 24 Merger-related rate credits 1 3 Revenue decoupling mechanism 4 9 Stranded costs 17 — Other 51 38 Total Current Regulatory Liabilities 178 192 Non-current Accrued removal obligations 1,132 1,117 Tax Act - remeasurement 1,515 — Asset sale gain account 10 9 Carrying costs on deferred income tax bonus depreciation 72 95 Economic development 32 35 Merger capital expense target customer credit account 6 15 Pension and other post-retirement benefits 74 76 Positive benefit adjustment 39 42 New York state tax rate change 6 9 Post term amortization — 3 Theoretical reserve flow thru impact 19 24 Deferred property tax 19 19 Net plant reconciliation 10 10 Variable rate debt 33 28 Carrying costs on deferred income tax - Mixed Services 263(a) 20 25 Rate refund – FERC ROE proceeding 27 22 Transmission congestion contracts 19 18 Merger-related rate credits 20 21 Accumulated deferred investment tax credits 13 15 Asset retirement obligation 13 13 Earning sharing provisions 22 12 Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge 2 — Low income programs 42 46 Non-firm margin sharing credits 8 7 Deferred income taxes regulatory 13 565 Other 67 73 Total Non-current Regulatory Liabilities $ 3,252 $ 2,318

Goodwill and Intangible Assets

Goodwill and Intangible Assets (Tables)	12 Months Ended
	Dec. 31, 2017
Goodwill And Intangible Assets Disclosure [Abstract]
Schedule of Goodwill by Reportable Segment	Goodwill by reportable segment as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Networks $ 2,747 $ 2,744 Renewables 380 380 Total $ 3,127 $ 3,124
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, 2017 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Wind development $ 583 $ (264 ) $ 319 Other 21 (12 ) 9 Total Intangible Assets $ 604 $ (276 ) $ 328 As of December 31, 2016 Gross Carrying Amount Accumulated Amortization Net Carrying Amount (Millions) Gas Storage rights $ 319 $ (120 ) $ 199 Wind development 587 (254 ) 333 Other 17 (11 ) 6 Total Intangible Assets $ 923 $ (385 ) $ 538
Schedule of Expect Amortization Expense	We expect amortization expense for the five years subsequent to December 31, 2017, to be as follows: Year ending December 31, (Millions) 2018 $ 16 2019 19 2020 18 2021 21 2022 22

Property, Plant and Equipment (

Property, Plant and Equipment (Tables)	12 Months Ended
	Dec. 31, 2017
Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives	The main asset categories are depreciated over the following estimated useful lives: Major class Asset Category Estimated Useful Life (years) Combined cycle plants 35-75 Hydroelectric power stations 35-90 Plant Wind power stations 20-40 Transport facilities 33-70 Distribution facilities 15-82 Equipment Conventional meters and measuring devices 15-41 Computer software 4-10 Other Buildings 30-82 Operations offices 5-75
Regulated and Unregulated [Member]
Summary of Main Asset Categories Depreciated Over the Following Estimated Useful Lives	Property, plant and equipment as of December 31, 2017, consisted of: As of December 31, 2017 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 13,108 $ 11,517 $ 24,625 Natural gas transportation, distribution and other 3,728 13 3,741 Other common operating property — 375 375 Total Property, Plant and Equipment in Service (a) 16,836 11,905 28,741 Total accumulated depreciation (b) (4,172 ) (3,325 ) (7,497 ) Total Net Property, Plant and Equipment in Service 12,664 8,580 21,244 Construction work in progress 987 438 1,425 Total Property, Plant and Equipment $ 13,651 $ 9,018 $ 22,669 ( a ) Includes capitalized leases of $204 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $68 million. Property, plant and equipment as of December 31, 2016, consisted of: As of December 31, 2016 Regulated Nonregulated Total (Millions) Electric generation, distribution, transmission and other $ 12,259 $ 10,375 $ 22,634 Natural gas transportation, distribution and other 3,433 661 4,094 Other common operating property — 335 335 Total Property, Plant and Equipment in Service (a) 15,692 11,371 27,063 Total accumulated depreciation (b) (3,839 ) (3,147 ) (6,986 ) Total Net Property, Plant and Equipment in Service 11,853 8,224 20,077 Construction work in progress 966 505 1,471 Total Property, Plant and Equipment $ 12,819 $ 8,729 $ 21,548 ( a ) Includes capitalized leases of $208 million primarily related to electric generation, distribution, transmission and other. ( b ) Includes accumulated amortization of capitalized leases of $60 million.

Asset Retirement Obligations (T

Asset Retirement Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Table Text Block Supplement [Abstract]
Schedule of Asset Retirement Obligations	The reconciliation of ARO carrying amounts for the years ended December 31, 2017 and 2016 consisted of: (Millions) As of December 31, 2015 $ 184 Liabilities settled during the year (7 ) Liabilities incurred during the year 3 Accretion expense 10 Revisions in estimated cash flows (29 ) As of December 31, 2016 $ 161 Liabilities settled during the year (1 ) Liabilities incurred during the year 13 Accretion expense 10 Revisions in estimated cash flows 13 As of December 31, 2017 $ 196

Debt (Tables)

Debt (Tables)	12 Months Ended
	Dec. 31, 2017
Debt Disclosure [Abstract]
Schedule of Long-term Debt	Long- term debt as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Maturity Dates Balances Interest Rates Balances Interest Rates First mortgage bonds - fixed (a) 2018-2045 $ 2,054 3.07%-10.60% $ 1,752 3.07%-10.60% Unsecured pollution control notes - fixed 2020 200 2.00%-2.375% 200 2.00%-2.375% Unsecured pollution control notes – variable 2032 62 1.94% 62 1.32% Other various non-current debt - fixed 2018-2045 3,027 2.89%-10.48% 2,772 2.89%-10.48% Obligations under capital leases 2018-2030 74 4%-4.44% 104 4%-4.44% Unamortized debt issuance costs and discount (38 ) (31 ) Total Debt 5,379 4,859 Less: debt due within one year, included in current liabilities 183 349 Total Non-current Debt $ 5,196 $ 4,510 (a) The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $6,365 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) 2018 2019 2020 2021 2022 Total $ 183 $ 357 $ 722 $ 307 $ 369 $ 1,938

Fair Value of Financial Instr51

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	12 Months Ended
	Dec. 31, 2017
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 14 30 74 (49 ) 69 Derivative financial instruments - gas 89 18 64 (146 ) 25 Contracts for differences — — 12 — 12 Total 103 48 150 (195 ) 106 Derivative liabilities Derivative financial instruments - power (14 ) (17 ) (15 ) 37 (9 ) Derivative financial instruments - gas (80 ) (20 ) (25 ) 110 (15 ) Contracts for differences — — (104 ) — (104 ) Total $ (94 ) $ (37 ) $ (144 ) $ 147 $ (128 ) As of December 31, 2016 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 40 $ — $ — $ — $ 40 Derivative assets Derivative financial instruments - power 11 48 58 (42 ) 75 Derivative financial instruments - gas 180 32 104 (239 ) 77 Contracts for differences — — 20 — 20 Total 191 80 182 (281 ) 172 Derivative liabilities Derivative financial instruments - power (24 ) (27 ) (3 ) 39 (15 ) Derivative financial instruments - gas (213 ) (34 ) (53 ) 257 (43 ) Contracts for differences — — (95 ) — (95 ) Total $ (237 ) $ (61 ) $ (151 ) $ 296 $ (153 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	Included in the derivative financial instruments – gas are derivative assets and liabilities of Gas segment classified as held for sale as of December 31, 2017. See Note 25 – Assets Held For Sale for further discussion. The reconciliations of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2017, 2016 and 2015 consisted of: (Millions) 2017 2016 2015 Fair value as of January 1, $ 31 $ (19 ) $ 57 Gains for the year recognized in operating revenues 18 67 33 Losses for the year recognized in operating revenues (1 ) — (8 ) Total gains or losses for the period recognized in operating revenues 17 67 25 Gains recognized in OCI 2 1 2 Losses recognized in OCI (1 ) — (3 ) Total gains or losses recognized in OCI 1 1 (1 ) Net change recognized in regulatory assets and liabilities (17 ) (8 ) — Purchases (5 ) 3 (73 ) Settlements (17 ) (9 ) (14 ) Transfers out of Level 3 (a) (4 ) (4 ) (13 ) Fair value as of December 31, $ 6 $ 31 $ (19 ) 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 $ 17 $ 67 $ 25 (a) Transfers out of Level 3 were the result of increased observability of market data. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input December 31, 2017 Risk of non-performance 0.11% - 0.49% Discount rate 1.89% - 2.40% Forward pricing ($ per MW) $5.30 - $9.55
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	As of December 31, 2017 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions with delivery periods Transactions are valued against forward market prices Observable and extrapolated forward gas and power prices not all of which can be NYMEX ($/MMBtu) $ 3.07 $ 3.93 $ 2.35 with delivery exceeding two on a corroborated by Indiana hub ($/MWh) $ 31.77 $ 65.55 $ 18.53 period > two years discounted market data for Mid C ($/MWh) $ 24.59 $ 46.50 $ (0.50 ) years basis identical or Minn hub ($/MWh) $ 26.40 $ 62.33 $ 9.56 similar products

Derivative Instruments and He52

Derivative Instruments and Hedging (Tables)	12 Months Ended
	Dec. 31, 2017
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Unrealized Gains and Losses from Fair Value Adjustments	The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the years ended December 31, 2017 and 2016, and for the period from December 17, 2015 to December 31, 2015, respectively, were as follows: Year Ended December 31, 2017 Year Ended December 31, 2016 Period from December 17, 2015 to December 31, 2015 (Millions) Derivative Assets $ (8 ) $ (7 ) $ (1 ) Derivative Liabilities $ (9 ) $ (1 ) $ —
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (Millions) Wholesale electricity purchase contracts (MWh) 3.9 5.6 Natural gas purchase contracts (Dth) 6.1 5.8 Fleet fuel purchase contracts (Gallons) 2.1 2.3 The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (MWh/Dth in Millions) Wholesale electricity purchase contracts 4 3 Wholesale electricity sales contracts 6 7 Natural gas and other fuel purchase contracts 285 329 Financial power contracts 12 8 Basis swaps - purchases 68 49 Basis swaps - sales 62 45
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Consolidated Balance Sheet and Amounts	The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Networks activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 20 $ 5 $ 13 $ — Derivative liabilities (13 ) — (32 ) (88 ) 7 5 (19 ) (88 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 7 5 (19 ) (88 ) Cash collateral receivable — — 3 — Total derivatives as presented in the balance sheet $ 7 $ 5 $ (16 ) $ (88 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 19 $ 16 $ 7 $ 5 Derivative liabilities (7 ) (5 ) (40 ) (79 ) 12 11 (33 ) (74 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 12 11 (33 ) (74 ) Cash collateral receivable — — 10 2 Total derivatives as presented in the balance sheet $ 12 $ 11 $ (23 ) $ (72 ) The offsetting of derivatives, location in the consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 111 $ 99 $ 31 $ 4 Derivative liabilities (82 ) (5 ) (51 ) (10 ) 29 94 (20 ) (6 ) Designated as hedging instruments Derivative assets 24 4 — 2 Derivative liabilities — (1 ) (3 ) (3 ) 24 3 (3 ) (1 ) Total derivatives before offset of cash collateral 53 97 (23 ) (7 ) Cash collateral receivable (payable) (17 ) (39 ) 3 3 Total derivatives as presented in the balance sheet, including assets and liabilities held for sale $ 36 $ 58 $ (20 ) $ (4 ) As of December 31, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 198 $ 108 $ 78 $ 7 Derivative liabilities (118 ) (4 ) (132 ) (16 ) 80 104 (54 ) (9 ) Designated as hedging instruments Derivative assets 25 4 — — Derivative liabilities (1 ) — (39 ) (21 ) 24 4 (39 ) (21 ) Total derivatives before offset of cash collateral 104 108 (93 ) (30 ) Cash collateral receivable (payable) (17 ) (46 ) 41 24 Total derivatives as presented in the balance sheet $ 87 $ 62 $ (52 ) $ (6 )
Schedule of Derivative Instruments, Effect of Cash flow Hedging on Other Comprehensive Income and Income	The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2017, 2016 and 2015, respectively, consisted of: Year Ended December 31, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2017 Interest rate contracts $ — Interest expense $ 8 Commodity contracts (1 ) Operating expenses 1 Total $ (1 ) $ 9 2016 Interest rate contracts $ — Interest expense $ 8 Commodity contracts — Operating expenses 2 Total $ — $ 10 2015 Interest rate contracts $ — Interest expense $ 9 Commodity contracts (3 ) Operating expenses 3 Total $ (3 ) $ 12 (a) Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the consolidated statements of income. The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2017, 2016 and 2015 consisted of: Year Ended December 31, (Loss) Gain Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Loss (Gain) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2017 Commodity contracts $ 41 Revenues $ 14 $ 41 $ 14 2016 Commodity contracts $ (42 ) Revenues $ (43 ) $ (42 ) $ (43 ) 2015 Commodity contracts $ 57 Revenues $ (2 ) Total $ 57 $ (2 ) (a) Changes in OCI are reported on a pre-tax basis.
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables and Gas activities as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (Millions) Wholesale electricity purchase contracts $ (3 ) $ (2 ) Wholesale electricity sales contracts 8 6 Natural gas and other fuel purchase contracts 19 30 Financial power contracts 55 56 Basis swaps- purchases (13 ) 3 Basis swaps- sales 4 (2 ) Total $ 70 $ 91
Effect of Derivatives Associated with Renewables and Gas Activities	The effect of trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Wholesale electricity purchase contracts $ (3 ) $ 3 $ 6 Wholesale electricity sales contracts 4 (7 ) (5 ) Financial power contracts (1 ) 4 — Financial and natural gas contracts (8 ) (22 ) (26 ) Total Loss $ (8 ) $ (22 ) $ (25 ) The effect of non-trading derivatives associated with Renewables and Gas activities for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Wholesale electricity purchase contracts $ 1 $ 9 $ (8 ) Wholesale electricity sales contracts (3 ) (20 ) (5 ) Financial power contracts (5 ) (10 ) 24 Natural gas and other fuel purchase contracts (8 ) 34 18 Total Gain $ (15 ) $ 13 $ 29

Commitments and Contingent Li53

Commitments and Contingent Liabilities (Tables)	12 Months Ended
	Dec. 31, 2017
Commitments And Contingencies Disclosure [Abstract]
Future Minimum Lease Payments	Total future minimum lease payments as of December 31, 2017 consisted of: Year Operating Leases Capital Leases Total (Millions) 2018 $ 36 $ 7 $ 43 2019 35 8 43 2020 36 8 44 2021 36 5 41 2022 31 2 33 Thereafter 757 47 804 Total $ 931 $ 77 $ 1,008
Forward Purchase and Sales Commitment Arrangement	Forward purchases and sales commitments under power, gas, and other arrangements as of December 31, 2017 consisted of: Purchases Sales Year Gas Power Other Total Gas Power Other Total (Millions) 2018 $ 280 $ 171 $ 528 $ 979 $ 26 $ 127 $ 4 $ 157 2019 239 123 201 563 9 104 1 114 2020 186 102 39 327 7 71 — 78 2021 149 89 20 258 4 51 — 55 2022 120 63 12 195 — 23 — 23 Thereafter 638 443 100 1,181 — 42 — 42 Totals $ 1,612 $ 991 $ 900 $ 3,503 $ 46 $ 418 $ 5 $ 469

Income Taxes (Tables)

Income Taxes (Tables)	12 Months Ended
	Dec. 31, 2017
Income Tax Disclosure [Abstract]
Schedule of Current and Deferred Taxes Charged to (Benefit) Expense	The Tax Act changes significantly the federal taxation of business entities, including among other things, a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. We have made a reasonable estimate of the effects of the Tax Act and recorded provisional amounts for the income tax effects related to the remeasurement of our deferred tax assets and liabilities and the associated regulatory liabilities established by our regulated utility companies in our consolidated financial statements as of December 31, 2017. As we complete our analysis of the Tax Act, collect and prepare necessary data, and interpret any additional guidance issued by the U.S. Treasury Department, the IRS, and other standard-setting bodies, we may make adjustments to the provisional amounts. Those adjustments may materially impact our provision for income taxes in the period in which the adjustments are made. Current and deferred taxes charged to (benefit) expense for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Current Federal $ (20 ) $ (6 ) $ (20 ) State 12 8 (33 ) Current taxes charged to (benefit) expense (8 ) 2 (53 ) Deferred Federal (124 ) 412 131 State (73 ) 2 (6 ) Deferred taxes charged to (benefit) expense (197 ) 414 125 Production tax credits (53 ) (38 ) (42 ) Investment tax credits (1 ) (1 ) (1 ) Total Income Tax (Benefit) Expense $ (259 ) $ 377 $ 29
Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate	The differences between tax expense per the statements of income and tax expense at the 35% statutory federal tax rate for the years ended December 31, 2017, 2016 and 2015 consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Tax expense at federal statutory rate $ 43 $ 353 $ 106 Depreciation and amortization not normalized 9 61 15 Investment tax credit amortization (1 ) (1 ) (1 ) Tax return related adjustments 7 (2 ) 6 Production tax credits (53 ) (38 ) (42 ) Tax equity financing arrangements (10 ) (27 ) (42 ) Federal tax rate impact on held for sale classification 82 — — State tax (benefit) expense, net of federal benefit (40 ) 7 (25 ) Tax Act - remeasurement (328 ) — — Non-deductible acquisition costs — — 9 Other, net 32 24 3 Total Income Tax (Benefit) Expense $ (259 ) $ 377 $ 29
Schedule of Deferred Tax Assets and Liabilities	Deferred tax assets and liabilities as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Non-current Deferred Income Tax Liabilities (Assets) Property related $ 3,543 $ 5,195 Unfunded future income taxes 75 216 Federal and state tax credits (574 ) (417 ) Accumulated deferred investment tax credits 14 14 Federal and state NOL’s (975 ) (1,397 ) Joint ventures/partnerships 302 565 Nontaxable grant revenue (449 ) (581 ) Pension and other post-retirement benefits (33 ) 52 Tax Act - tax on regulatory remeasurement (401 ) — Other (58 ) (223 ) Non-current Deferred Income Tax Liabilities 1,444 3,424 Add: Valuation allowance 21 31 Total Non-current Deferred Income Tax Liabilities 1,465 3,455 Less amounts classified as regulatory liabilities Non-current deferred income taxes 13 565 Non-current Deferred Income Tax Liabilities $ 1,452 $ 2,890 Deferred tax assets $ 2,490 $ 2,617 Deferred tax liabilities 3,955 6,072 Net Accumulated Deferred Income Tax Liabilities $ 1,465 $ 3,455
Schedule of Reconciliation of Unrecognized Income Tax Benefits	The reconciliation of unrecognized income tax benefits for the years ended December 31, 2017, 2016 and 2015 consisted of: Years ended December 31, 2017 2016 2015 (Millions) Beginning Balance $ 40 $ 36 $ 38 Increases for tax positions related to prior years 23 8 1 Decreases for tax positions related to prior years (16 ) (4 ) — Reduction for tax position related to settlements with taxing authorities (2 ) — (3 ) Ending Balance $ 45 $ 40 $ 36

Post-retirement and Similar O55

Post-retirement and Similar Obligations (Tables)	12 Months Ended
	Dec. 31, 2017
Schedule of Amounts Recognized in Balance Sheet	Amounts recognized as of December 31, 2017 and 2016 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2017 2016 2017 2016 (Millions) Current liabilities $ — $ — $ (5 ) $ (5 ) Non-current liabilities (728 ) (776 ) (321 ) (330 ) Total $ (728 ) $ (776 ) $ (326 ) $ (335 )
Summary of Amounts Recognized in OCI	Amounts recognized in OCI for ARHI for the years ended December 31, 2017, 2016 and 2015, consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2017 2016 2015 2017 2016 2015 (Millions) Net (gain) loss $ 25 $ 23 $ 25 $ (4 ) $ (3 ) $ (1 )
Regulatory Assets and Liabilities	Note 5. Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in the rate base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses, debt premium, environmental remediation costs, which is primarily the offset of accrued liabilities for future spending, unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded , The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. On June 15, 2016, the NYPSC approved the Joint Proposal in connection with a three five ten 16.5 126 fifty Current and non-current regulatory assets as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 24 $ 22 Pension and other post-retirement benefits 7 7 Storm costs 46 40 Temporary supplemental assessment surcharge — 4 Reliability support services 27 27 Revenue decoupling mechanism 21 15 Transmission revenue reconciliation mechanism 8 12 Electric supply reconciliation — 13 Hedges losses 3 10 Contracts for differences 9 14 Hardship programs 14 16 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 31 14 Deferred transmission expense 37 13 Environmental remediation costs 13 14 Other 51 48 Total Current Regulatory Assets 307 285 Non-current Pension and other post-retirement benefits cost deferrals 110 134 Pension and other post-retirement benefits 1,162 1,320 Storm costs 254 187 Deferred meter replacement costs 29 32 Unamortized losses on reacquired debt 17 20 Environmental remediation costs 283 287 Unfunded future income taxes 376 542 Asset retirement obligations 18 18 Deferred property tax 14 33 Federal tax depreciation normalization adjustment 155 161 Merger capital expense target customer credit 2 11 Debt premium 131 151 Reliability support services 10 29 Plant decommissioning 9 14 Contracts for differences 84 61 Hardship programs 13 18 Other 71 73 Total Non-current Regulatory Assets $ 2,738 $ 3,091 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings. “Storm costs” for CMP, NYSEG, and RG&E are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. Storm costs in the amount of $123 million at NYSEG are being recovered over ten-year period and the remaining portion is being amortized over five years following the approval of the Joint Proposal by the NYPSC. UI is allowed to defer costs associated with any storm totaling $1 million or greater for future recovery. UI’s storm regulatory asset balance was $0 as of December 31, 2017. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. Following the approval of the Joint Proposal by the NYPSC, these amounts will be collected over a period of fifty years and the NYPSC Staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Asset retirement obligations” (ARO) represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amount for NYSEG and RG&E is being amortized over a five “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rates years covering 2011 forward. The recovery period in NY is from 27 to 39 years and for CMP this will be determined in future Maine Public Utility Commission (MPUC) rate proceedings. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Other” includes post term amortization and various items subject to reconciliation including rate change levelization, loss on re-acquired debt and power tax deferral. Current and non-current regulatory liabilities as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Current Reliability support services (Cayuga) $ — $ 3 Non by-passable charges 5 22 Energy efficiency portfolio standard 37 45 Gas supply charge and deferred natural gas cost 4 6 Transmission revenue reconciliation mechanism 14 5 Pension and other post-retirement benefits 1 3 Pension and other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 21 15 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE refund 4 24 Merger-related rate credits 1 3 Revenue decoupling mechanism 4 9 Stranded costs 17 — Other 51 38 Total Current Regulatory Liabilities 178 192 Non-current Accrued removal obligations 1,132 1,117 Tax Act - remeasurement 1,515 — Asset sale gain account 10 9 Carrying costs on deferred income tax bonus depreciation 72 95 Economic development 32 35 Merger capital expense target customer credit account 6 15 Pension and other post-retirement benefits 74 76 Positive benefit adjustment 39 42 New York state tax rate change 6 9 Post term amortization — 3 Theoretical reserve flow thru impact 19 24 Deferred property tax 19 19 Net plant reconciliation 10 10 Variable rate debt 33 28 Carrying costs on deferred income tax - Mixed Services 263(a) 20 25 Rate refund – FERC ROE proceeding 27 22 Transmission congestion contracts 19 18 Merger-related rate credits 20 21 Accumulated deferred investment tax credits 13 15 Asset retirement obligation 13 13 Earning sharing provisions 22 12 Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge 2 — Low income programs 42 46 Non-firm margin sharing credits 8 7 Deferred income taxes regulatory 13 565 Other 67 73 Total Non-current Regulatory Liabilities $ 3,252 $ 2,318 “Reliability support services (Cayuga)” represents the difference between actual expenses for reliability support services and the amount provided for in rates. This will be refunded to customers within the next year. “Non by-passable charges” represent the non by-passable charge paid by all customers. An asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered. This liability will be refunded to customers within the next year. “Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station located in Oswego, New York. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is five “Economic development” represents the economic development program which enables NYSEG and RG&E to foster economic development through attraction, expansion, and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is five “Merger capital expense target customer credit” account was created as a result of NYSEG and RG&E not meeting certain capital expenditure requirements established in the order approving the purchase of AVANGRID (formerly Energy East Corporation) by Iberdrola. The amortization period is five “Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this a regulatory liability is not reflected within rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. The amortization period is five “New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from 7.1% to 6.5%. The amortization period is five “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is five “Tax Act - remeasurement” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts to review and address the implications associated with the Tax Act on the utilities providing service in those states. We expect the regulators in each jurisdiction, including the FERC, to issue requirements in 2018 regarding how all tax benefits associated with the Tax Act will be returned to customers. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. 20 “Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “Low Income Programs” represent various hardship and payment plan programs approved for recovery. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.
Amounts Expected to be Amortized for Net Periodic Benefit Cost	Amounts expected to be amortized from regulatory assets or liabilities into net periodic benefit cost for the year ending December 31, 2018 consists of: Pension Benefits Postretirement Benefits (Millions) Estimated net loss $ 150 $ 5 Estimated prior service cost (benefit) 1 (9 ) Amounts expected to be amortized from OCI into net periodic benefit cost for the year ending December 31, 2018 consists of: 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, 2017 and 2016 consisted of: As of December 31, 2017 2016 Health care cost trend rate assumed for next year - Networks 6.75%/8.50% 7.00%/9.00% Health care cost trend rate assumed for next year - ARHI 7.50%/8.50% 6.75%/8.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - Networks 4.50% 4.50% Rate to which cost trend rate is assumed to decline (ultimate trend rate) - ARHI 4.50% 4.50% Year that the rate reaches the ultimate trend rate - Networks 2026 / 2028 2026 / 2028 Year that the rate reaches the ultimate trend rate - ARHI 2028 / 2030 2026 / 2028
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 $ 15 $ (12 )
Fair Values of Pension Benefits Plan Assets, by Asset Category	The fair values of pension benefits plan assets, by asset category, as of December 31, 2017, consisted of: As of December 31, 2017 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 18 $ — $ 18 $ — U.S. government securities 13 13 — — Common stocks 129 129 — — Registered investment companies 134 134 — — Corporate bonds 447 — 447 — Preferred stocks 4 — 4 — Equity commingled funds 436 186 250 — Other, principally annuity, fixed income 553 — 553 — $ 1,734 $ 462 $ 1,272 $ — Other investments measured at net asset value 1,131 Total $ 2,865 The fair values of pension benefits plan assets, by asset category, as of December 31, 2016, consisted of: As of December 31, 2016 * Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Cash and cash equivalents $ 49 $ — $ 49 $ — U.S. government securities 172 172 — — Common stocks 120 120 — — Registered investment companies 122 122 — — Corporate bonds 358 — 358 — Preferred stocks 4 — 4 — Equity commingled funds 371 — 371 — Other, principally annuity, fixed income 386 — 386 — $ 1,582 $ 414 $ 1,168 $ — Other investments measured at net asset value 1,090 Total $ 2,672 *Certain amounts in this table have been reclassified to conform to 2017 presentation.
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, 2017 consisted of: As of December 31, 2017 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 4 $ 4 $ — $ — Mutual funds, fixed 35 35 — — Government and corporate bonds 2 — 2 — Mutual funds, equity 77 50 27 — Common stocks 20 20 — — Mutual funds, other 27 19 8 — Total $ 165 $ 128 $ 37 $ — The fair values of other postretirement benefits plan assets, by asset category, as of December 31, 2016 consisted of: As of December 31, 2016 Fair Value Measurements (Millions) Total Level 1 Level 2 Level 3 Asset Category Money market funds $ 6 $ 4 $ 2 $ — Mutual funds, fixed 41 39 2 — Government and corporate bonds 2 — 2 — Mutual funds, equity 72 43 29 — Common stocks 23 23 — — Mutual funds, other 16 9 7 — Total $ 160 $ 118 $ 42 $ —
Networks and ARHI [Member]
Obligations and Funded Status	Obligations and funded status of Networks and ARHI as of December 31, 2017 and 2016 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2017 2016 2017 2016 (Millions) Change in benefit obligation Benefit obligation as of January 1, $ 3,448 $ 3,509 $ 495 $ 525 Service cost 42 44 4 5 Interest cost 139 142 22 21 Plan participants’ contributions — — 7 7 Actuarial loss (gain) 188 (43 ) 3 (24 ) Special termination benefits — — — — Benefits paid (219 ) (204 ) (39 ) (39 ) Reclassified to held for sale (5 ) — (1 ) — Benefit Obligation as of December 31, 3,593 3,448 491 495 Change in plan assets Fair value of plan assets as of January 1, 2,672 2,664 160 162 Actual return on plan assets 382 169 17 11 Employer contributions 33 43 20 30 Plan participants’ contributions — — 7 7 Benefits paid (219 ) (204 ) (39 ) (39 ) Reclassified to held for sale (3 ) — — — Withdrawals from VEBA — — — (11 ) Fair Value of Plan Assets as of December 31, 2,865 2,672 165 160 Funded Status as of December 31, $ (728 ) $ (776 ) $ (326 ) $ (335 )
Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans	The aggregate PBO and ABO and the fair value of plan assets for underfunded plans of Networks and ARHI as of December 31, 2017 and 2016 consisted of: PBO in excess of plan assets As of December 31, 2017 2016 (Millions) Projected benefit obligation $ 3,593 $ 3,448 Fair value of plan assets 2,865 2,672 ABO in excess of plan assets As of December 31, 2017 2016 (Millions) Accumulated benefit obligation $ 3,363 $ 3,214 Fair value of plan assets 2,865 2,672
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, 2017 and 2016 consisted of: Pension Benefits Postretirement Benefits As of December 31, 2017 2016 2017 2016 Discount rate - Networks 3.63% / 3.80% 4.12% / 4.24% 3.63% / 3.80% 4.12% / 4.24% Discount rate - ARHI 3.80% 3.81% 3.80 % 3.81% Rate of compensation increase - Networks 3.50% - 4.20% 3.50% - 4.20% — — The weighted-average assumptions used to determine net periodic benefit cost for Networks and ARHI for the years ended December 31, 2017, 2016 and 2015 consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2017 2016 2015 2017 2016 2015 Discount rate - Networks 4.12% / 4.24% 4.12% / 4.24% 3.80% / 4.24% 4.12% / 4.24% 4.12% / 4.24% 3.80% / 4.24% Discount rate - ARHI 3.81% 3.90% 3.90% 3.81% 3.90% 3.90% Expected long-term return on plan assets - Networks 7.00% / 7.50% 7.40% / 7.75% 7.50% 6.13% 7.16% — Expected long-term return on plan assets - ARHI 5.50% 5.50% 5.50% 5.50% 5.50% 5.75% Expected long-term return on plan assets - nontaxable trust - Networks — — — 6.50% 7.00% 7.50% Expected long-term return on plan assets - taxable trust - Networks — — — 4.25% 4.50% 5.00% Rate of compensation increase - Networks 3.50% - 4.20% 3.50% - 4.20% 4.10% — — —
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, 2017 consisted of: (Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts 2018 $ 234 $ 33 $ — 2019 215 33 — 2020 218 33 — 2021 221 33 — 2022 225 33 — 2023 - 2027 1,122 165 4
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, 2017, 2016 and 2015 for Networks consisted of: Pension Benefits Postretirement Benefits Years Ended December 31, 2017 2016 2015 2017 2016 2015 (Millions) Net loss $ 737 $ 860 $ 994 $ 35 $ 44 $ 76 Prior service cost (credit) 6 7 9 (31 ) (40 ) (49 )
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 for the years ended December 31, 2017, 2016 and 2015 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2017 2016 2015 2017 2016 2015 Net Periodic Benefit Cost: Service cost $ 42 $ 44 $ 36 $ 5 $ 5 $ 4 Interest cost 137 140 97 21 20 15 Expected return on plan assets (195 ) (199 ) (156 ) (8 ) (8 ) (7 ) Amortization of prior service cost (benefit) 2 2 3 (9 ) (9 ) (9 ) Amortization of net loss 126 123 130 5 8 7 Special termination benefit charge — — 2 — — — Settlement charge — — 2 — — — Net Periodic Benefit Cost 112 110 114 14 16 10 Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities: Settlements — — (2 ) — — — Net loss (gain) 3 (11 ) 69 (5 ) (24 ) (12 ) Amortization of net loss (126 ) (123 ) (130 ) (5 ) (8 ) (7 ) Current year prior service cost — — — — — (1 ) Amortization of prior service (cost) benefit (2 ) (2 ) (3 ) 9 9 9 Total Other Changes (125 ) (136 ) (66 ) (1 ) (23 ) (11 ) Total Recognized $ (13 ) $ (26 ) $ 48 $ 13 $ (7 ) $ (1 )
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 for the years ended December 31, 2017, 2016 and 2015 consisted of: (Millions) Pension Benefits Postretirement Benefits For the years ended December 31, 2017 2016 2015 2017 2016 2015 Net Periodic Benefit Cost: Service cost $ — $ — $ — $ — $ — $ 1 Interest cost 2 2 2 1 1 1 Expected return on plan assets (2 ) (2 ) (2 ) — — — Amortization of net loss 1 1 1 — — — Settlement charge — 1 — — — — Net Periodic Benefit Cost (income) 1 2 1 1 1 2 Other Changes in plan assets and benefit obligations recognized in OCI: Net loss (gain) 2 — 4 (1 ) (2 ) (8 ) Amortization of net loss (1 ) (1 ) (1 ) — — — Total Other Changes 1 (1 ) 3 (1 ) (2 ) (8 ) Total Recognized $ 2 $ 1 $ 4 $ — $ (1 ) $ (6 )

Equity (Tables)

Equity (Tables)	12 Months Ended
	Dec. 31, 2017
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated OCI (Loss) Accumulated OCI for the years ended December 31, 2017, 2016 and 2015 consisted of: Accumulated Other Comprehensive Income (Loss) As of December 31, 2014 2015 Change As of December 31, 2015 2016 Change As of December 31, 2016 2017 Change As of December 31, 2017 (Millions) (Loss) gain on revaluation of defined benefit plans, net of income tax expense of $2.2 for 2015, and $4.3 for 2016 $ (25 ) $ 4 $ (21 ) $ 7 $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans, net of income tax expense (benefit) of $1.7 for 2015, $0.4 for 2016 and $0.2 for 2017 (11 ) 3 (8 ) 1 (7 ) 1 (6 ) 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 $20.9 for 2015, $(15.8) for 2016 and $15.2 for 2017 (2 ) 33 31 (26 ) 5 25 30 Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $4.9 for 2015, $(11.0) for 2016 and $9.3 for 2017 (a) (61 ) 7 (54 ) (16 ) (70 ) 14 (56 ) Gain (loss) on derivatives qualifying as cash flow hedges (63 ) 40 (23 ) (42 ) (65 ) 39 (26 ) Accumulated Other Comprehensive (Loss) Income $ (99 ) $ 47 $ (52 ) $ (34 ) $ (86 ) $ 40 $ (46 ) (a) Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	12 Months Ended
	Dec. 31, 2017
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2017, 2016 and 2015, consisted of: Years Ended December 31, 2017 2016 2015 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 381 $ 632 $ 273 Denominator: Weighted average number of shares outstanding - basic 309,502,861 309,512,553 254,588,212 Weighted average number of shares outstanding - diluted 309,661,883 309,817,322 254,605,111 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 1.23 $ 2.04 $ 1.07 Earnings Per Common Share, Diluted $ 1.23 $ 2.04 $ 1.07

Grants, Government Incentives58

Grants, Government Incentives and Deferred Income (Tables)	12 Months Ended
	Dec. 31, 2017
Deferred Revenue Disclosure [Abstract]
Schedule of Changes in Deferred Income	The changes in deferred income as of December 31, 2017 and 2016 consisted of: (Millions) Government grants Other deferred income Total As of December 31, 2015 $ 1,529 $ 24 $ 1,553 Additions — — — Recognized in income (68 ) (2 ) (70 ) As of December 31, 2016 $ 1,461 $ 22 $ 1,483 Additions 33 2 35 Reclassified to held for sale — (2 ) (2 ) Recognized in income (67 ) (3 ) (70 ) As of December 31, 2017 $ 1,427 $ 19 $ 1,446

Other Financial Statements It59

Other Financial Statements Items (Tables)	12 Months Ended
	Dec. 31, 2017
Receivables [Abstract]
Schedule of Other Income and (Expense)	Other income for the years ended December 31, 2017, 2016 and 2015 consisted of: Years ended December 31, 2017 2016 2015 (Millions) Allowance for funds used during construction $ 36 $ 26 $ 21 Carrying costs on regulatory assets 11 14 28 Other 11 36 7 Total Other Income $ 58 $ 76 $ 56
Schedule of Accounts Receivable	Accounts receivable as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Trade receivables $ 1,104 $ 1,183 Allowance for bad debts (64 ) (64 ) Total Accounts Receivable $ 1,040 $ 1,119
Schedule of Change in Allowance For Bad Debts	The change in the allowance for bad debts as of December 31, 2017 and 2016 consisted of: (Millions) As of December 31, 2014 $ 49 Current period provision 46 Write-off as uncollectible (33 ) As of December 31, 2015 $ 62 Current period provision 48 Write-off as uncollectible (46 ) As of December 31, 2016 $ 64 Current period provision 69 Write-off as uncollectible (69 ) As of December 31, 2017 $ 64
Schedule of Prepayments and Other Current Assets	Prepayments and other current assets as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Prepaid other taxes $ 194 $ 153 Broker margin and collateral accounts 32 32 Loans to third parties 2 3 Fixed-term deposits — 3 Other pledged deposits 9 8 Prepaid expenses 33 53 Other 3 3 Total $ 273 $ 255
Schedule of Other Current Liabilities	Other current liabilities as of December 31, 2017 and 2016 consisted of: As of December 31, 2017 2016 (Millions) Advances received $ 113 $ 107 Accrued salaries 87 84 Short-term environmental provisions 69 34 Collateral deposits received 43 45 Pension and other postretirement 5 5 Other 13 4 Total $ 330 $ 279

Segment Information (Tables)

Segment Information (Tables)	12 Months Ended
	Dec. 31, 2017
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information as of and for the year ended December 31, 2017 consisted of: For the year ended December 31, 2017 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 4,950 $ 1,038 $ (26 ) $ 1 $ 5,963 Revenue - intersegment 11 9 41 (61 ) — Impairment — — 642 — 642 Depreciation and amortization 474 325 25 — 824 Operating income (loss) 994 92 (701 ) — 385 Adjusted EBITDA 1,468 417 (34 ) — 1,851 Earnings (loss) from equity method investments 15 (55 ) — — (40 ) Interest expense, net of capitalization 244 28 24 (16 ) 280 Income tax expense (benefit) 316 (320 ) (212 ) (43 ) (259 ) Capital expenditures 1,305 1,097 7 7 2,416 As of December 31, 2017 Property, plant and equipment 13,876 8,786 — 7 22,669 Equity method investments 147 205 — — 352 Total assets $ 21,411 $ 11,308 $ 383 $ (1,431 ) $ 31,671 (a) Does not represent a segment. I Segment information as of and for the year ended December 31, 2016 consisted of: For the year ended December 31, 2016 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 5,027 $ 1,000 $ (7 ) $ (2 ) $ 6,018 Revenue - intersegment 3 15 39 (57 ) — Depreciation and amortization 466 313 25 — 804 Operating income (loss) 1,086 149 (41 ) — 1,194 Adjusted EBITDA 1,552 462 (16 ) — 1,998 Earnings (loss) from equity method investments 15 (8 ) — — 7 Interest expense, net of capitalization 252 50 25 (59 ) 268 Income tax expense (benefit) 415 7 (22 ) (23 ) 377 Capital expenditures 1,140 561 6 — 1,707 As of December 31, 2016 Property, plant and equipment 13,032 8,015 501 — 21,548 Equity method investments 151 236 — — 387 Total assets $ 20,753 $ 9,884 $ 1,124 $ (452 ) $ 31,309 (a) Does not represent a segment. I Segment information as of and for the year ended December 31, 2015 consisted of: For the year ended December 31, 2015 (Millions) Networks Renewables Gas Other(a) AVANGRID Consolidated Revenue - external $ 3,386 $ 1,051 $ (71 ) $ 1 $ 4,367 Revenue - intersegment — 16 52 (68 ) — Impairment — 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 — Interest expense, net of capitalization 227 54 31 (45 ) 267 Income tax expense (benefit) 146 8 (44 ) (81 ) 29 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
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income	Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the years ended December 31, 2017, 2016 and 2015, respectively, is as follows: Years Ended December 31, 2017 2016 2015 (Millions) Consolidated Adjusted EBITDA $ 1,851 $ 1,998 $ 1,220 Less: Impairment 642 — 12 Depreciation and amortization 824 804 695 Interest expense, net of capitalization 280 268 267 Income tax expense (259 ) 377 29 Add: Other income 58 76 56 Earnings from equity method investments (40 ) 7 — Consolidated Net Income $ 382 $ 632 $ 273

Related Party Transactions (Tab

Related Party Transactions (Tables)	12 Months Ended
	Dec. 31, 2017
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the years ended December 31, 2017, 2016 and 2015, respectively, consisted of: Years Ended December 31, 2017 2016 2015 (Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From Iberdrola Financiación, S.A. $ — $ (2 ) $ — $ (2 ) $ — $ (1 ) Iberdrola Renovables Energia, S.L. — (9 ) — (8 ) — (9 ) Iberdrola Canada Energy Services, Ltd — (33 ) — (37 ) — (55 ) Iberdrola, S.A. 1 (36 ) — (31 ) — (35 ) Iberdrola Energia Monterrey, S.A. de C.V. 46 — 18 — — — Other 1 (1 ) 3 (1 ) 3 (2 )
Schedule of Related Party Balances	Related party balances as of December 31, 2017 and 2016, respectively, consisted of: As of December 31, 2017 2016 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd $ — $ (31 ) $ — $ (14 ) Siemens-Gamesa 2 (51 ) 1 (181 ) Iberdrola, S.A. 1 (32 ) — (30 ) Iberdrola Renovables Energía, S.L. — — 2 — Iberdrola Energia Monterrey, S.A. de C.V. 1 — 11 — Other 6 (4 ) 11 (3 )

Stock-Based Compensation (Table

Stock-Based Compensation (Tables)	12 Months Ended
	Dec. 31, 2017
Disclosure Of Compensation Related Costs Sharebased Payments [Abstract]
Summary of Nonvested PSUs	A summary of the status of the AVANGRID's nonvested PSUs as of December 31 , 2017 December 31, 2017 Number of PSUs Weighted Average Grant Date Fair Value Nonvested Balance – December 31, 2016 1,523,981 $ 33.01 Granted 94,509 $ 32.89 Forfeited (113,256 ) $ 31.91 Vested (120,975 ) $ 40.07 Nonvested Balance – December 31, 2017 1,384,259 $ 32.57

Assets Held for Sale (Tables)

Assets Held for Sale (Tables)	12 Months Ended
	Dec. 31, 2017
Assets Held For Sale Not Part Of Disposal Group [Abstract]
Summary of Current Assets and Current Liabilities Held for Sale	The current assets and current liabilities held for sale relating to our gas trading and storage businesses consisted of the following: As of December 31, 2017 (Millions) Accounts receivable, net $ 137 Derivative assets 25 Fuel and gas in storage 77 Prepayments and other current assets 19 Property, plant and equipment 71 Intangible assets 28 Assets held for sale $ 357 Accounts payable and accrued liabilities 107 Derivative liabilities 14 Other liabilities 16 Liabilities held for sale $ 137

Restructuring and Severance R64

Restructuring and Severance Related Expenses (Tables)	12 Months Ended
	Dec. 31, 2017
Restructuring And Related Activities [Abstract]
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities and Other Liabilities	For the year ended December 31, 2017, the severance and lease restructuring charges reserves, which are recorded in “Other current liabilities” and “Other liabilities”, consisted of: Year Ended December 31, 2017 (Millions) Beginning Balance $ — Restructuring and severance related expenses 19 Payments (14 ) Ending Balance $ 5

Quarterly Financial Data (una65

Quarterly Financial Data (unaudited) (Tables)	12 Months Ended
	Dec. 31, 2017
Selected Quarterly Financial Information [Abstract]
Schedule of Quarterly Financial Data	Selected quarterly financial data for 2017 and 2016 are set forth below: 1st Quarter 2nd Quarter 3rd Quarter 4th Quarter (Millions, except per share data) 2017 Operating revenues $ 1,758 $ 1,331 $ 1,341 $ 1,533 Operating Income $ 398 $ 223 $ 189 $ (425 ) Net Income $ 239 $ 120 $ 100 $ (77 ) Net Income attributable to Avangrid, Inc. $ 239 $ 120 $ 99 $ (77 ) Earnings Per Common Share, Basic and Diluted: (1) $ 0.77 $ 0.39 $ 0.32 $ (0.25 ) 2016 Operating revenues $ 1,670 $ 1,439 $ 1,418 $ 1,491 Operating Income $ 349 $ 322 $ 217 $ 306 Net Income $ 213 $ 101 $ 109 $ 209 Net Income attributable to Avangrid, Inc. $ 213 $ 101 $ 109 $ 209 Earnings Per Common Share, Basic and Diluted: (1) $ 0.69 $ 0.33 $ 0.35 $ 0.67 (1) Based on weighted average number of 309.5 million and 309.8 million shares outstanding each quarter in 2017 and 2016 for basic and diluted earnings per share, respectively.

Cash Dividends Paid by Subsid66

Cash Dividends Paid by Subsidiaries (Tables)	12 Months Ended
	Dec. 31, 2017
Avangrid, Inc [Member]
Schedule of Cash Dividends Paid by Subsidiaries	Cash dividends paid by subsidiaries are as follows: Years ended December 31, 2017 2016 2015 (In millions) AVANGRID Networks $ 308 $ 220 $ 59 AVANGRID Renewables — 200 750 Other AVANGRID subsidiaries — — 302 $ 308 $ 420 $ 1,111

Background and Nature Of Oper67

Background and Nature Of Operations - Additional Information (Detail) - $ / shares	Dec. 16, 2015	Dec. 31, 2017	Dec. 31, 2017
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	$ 10.50
Membership interest		50.00%	50.00%
Enstor Energy Services, LLC [Member]
Nature Of Business [Line Items]
Assets and liabilities held for sale completion period		12 months	12 months
Disposal date			Mar. 1, 2018
Enstor Gas, LLC [Member]
Nature Of Business [Line Items]
Definitive agreement date			Feb. 16, 2018
Description of disposal date			second quarter of 2018
Iberdrola, S.A. [Member]
Nature Of Business [Line Items]
Shares issued in connection with acquisition	252,234,989
UIL Holdings [Member]
Nature Of Business [Line Items]
Shares issued in connection with acquisition	57,255,850
Shares issued in connection with the acquisition at par value	$ 0.01
Percentage of ownership		18.50%	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	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Immaterial error correction, decrease in amortization of debt (premium) cost	$ (5)	$ (28)	$ 3
Immaterial Correction [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Immaterial error correction, decrease in deferred income taxes		(2.4)	(5)
Immaterial error correction, decrease in amortization of debt (premium) cost		(0.2)	(0.4)
Immaterial Correction [Member] | Retained Earnings
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Immaterial error correction, revision amount	$ 77.2
Immaterial Correction [Member] | Retained Earnings and Investments in Subsidiaries [Member] | Avangrid, Inc [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Immaterial error correction, revision amount		86
Immaterial Correction [Member] | Income Tax Expense [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Immaterial error correction, revision amount		(2.4)	(5)
Immaterial Correction [Member] | Other Income [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Immaterial error correction, revision amount		0.2	0.4
Immaterial Correction [Member] | Equity Earnings and Net Income [Member] | Avangrid, Inc [Member]
Quantifying Misstatement In Current Year Financial Statements [Line Items]
Immaterial error correction, revision amount		$ 2	$ 6

Basis of Presentation - Effect

Basis of Presentation - Effect of Correction on Consolidated Balance Sheet and Consolidated Statements of Income (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended																12 Months Ended
	Dec. 31, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Deferred income taxes	$ 1,452								$ 2,890								$ 1,452	$ 2,890
Total Other Non-current Liabilities	5,013								6,561								5,013	6,561
Total Non-current Liabilities	13,461								13,389								13,461	13,389
Total Liabilities	16,575								16,101								16,575	16,101
Retained earnings	1,475								1,630								1,475	1,630
Total Stockholders' Equity	15,077								15,195								15,077	15,195
Total Equity	15,096								15,208								15,096	15,208	$ 15,150	$ 12,555
Total Liabilities and Equity	31,671								31,309								31,671	31,309
Other income																	58	76	56
Income Before Income Tax																	123	1,009	302
Income tax expense																	(259)	377	29
Net Income	$ (77)		$ 100		$ 120		$ 239		$ 209		$ 109		$ 101		$ 213		$ 382	$ 632	$ 273
Net Income Per Common Share, Basic and Diluted:	$ (0.25)	[1]	$ 0.32	[1]	$ 0.39	[1]	$ 0.77	[1]	$ 0.67	[1]	$ 0.35	[1]	$ 0.33	[1]	$ 0.69	[1]		$ 2.04	$ 1.07
As Reported [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Deferred income taxes									$ 2,976									$ 2,976
Total Other Non-current Liabilities									6,647									6,647
Total Non-current Liabilities									13,475									13,475
Total Liabilities									16,187									16,187
Retained earnings									1,544									1,544
Total Stockholders' Equity									15,109									15,109
Total Equity									15,122									15,122
Total Liabilities and Equity									31,309									31,309
Other income																		76	$ 55
Income Before Income Tax																		1,009	301
Income tax expense																		379	34
Net Income																		$ 630	$ 267
Net Income Per Common Share, Basic and Diluted:																		$ 2.04	$ 1.05
Correction [Member]
Error Corrections And Prior Period Adjustments Restatement [Line Items]
Deferred income taxes									(86)									$ (86)
Total Other Non-current Liabilities									(86)									(86)
Total Non-current Liabilities									(86)									(86)
Total Liabilities									(86)									(86)
Retained earnings									86									86
Total Stockholders' Equity									86									86
Total Equity									$ 86									86
Other income																			$ 1
Income Before Income Tax																			1
Income tax expense																		(2)	(5)
Net Income																		$ 2	$ 6
Net Income Per Common Share, Basic and Diluted:																			$ 0.02
[1]	Based on weighted average number of 309.5 million and 309.8 million shares outstanding each quarter in 2017 and 2016 for basic and diluted earnings per share, respectively

Summary of Significant Accoun70

Summary of Significant Accounting Policies, New Accounting Pronouncements, and Use of Estimates - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Jan. 01, 2018
Accounting Polices [Line Items]
Percentage of tax returns included in taxable income		80.00%
Federal statutory income tax rate		35.00%
Percentage of employees covered by collective bargaining agreement		48.00%
Percentage of expiry		8.00%
Scenario, Forecast
Accounting Polices [Line Items]
Federal statutory income tax rate	21.00%
Minimum [Member]
Accounting Polices [Line Items]
Finite lived intangible assets useful economic life		4 years
Maximum [Member]
Accounting Polices [Line Items]
Finite lived intangible assets useful economic life		40 years
Maximum [Member] | Subsequent Event [Member]
Accounting Polices [Line Items]
Cumulative adjustment that decrease retained earnings and additional paid in capital			$ 100

Summary of Significant Accoun71

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, 2017
Plant [Member] | Minimum [Member] | Combined Cycle Plants [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	35 years
Plant [Member] | Minimum [Member] | Hydroelectric Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	35 years
Plant [Member] | Minimum [Member] | Wind Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	20 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)	75 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] | Wind Power Stations [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	40 years
Plant [Member] | Maximum [Member] | Transport Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	70 years
Plant [Member] | Maximum [Member] | Distribution Facilities [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	82 years
Equipment [Member] | Minimum [Member] | Conventional Meters And Measuring Devices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	15 years
Equipment [Member] | Minimum [Member] | Computer Software[Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	4 years
Equipment [Member] | Maximum [Member] | Conventional Meters And Measuring Devices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	41 years
Equipment [Member] | Maximum [Member] | Computer Software[Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	10 years
Other [Member] | Minimum [Member] | Buildings [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	30 years
Other [Member] | Minimum [Member] | Operations Offices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	5 years
Other [Member] | Maximum [Member] | Buildings [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	82 years
Other [Member] | Maximum [Member] | Operations Offices [Member]
Property Plant And Equipment [Line Items]
Estimated Useful Life (years)	75 years

Industry Regulation - Additiona

Industry Regulation - Additional Information (Detail)

Dec. 19, 2017USD ($)Pole

Oct. 24, 2017AgreementMW

Oct. 16, 2017

Oct. 06, 2017

Aug. 21, 2017

Jun. 20, 2017AgreementMW

May 25, 2017AgreementMW

Feb. 23, 2016USD ($)

Nov. 05, 2015

Oct. 21, 2015USD ($)

Apr. 02, 2015

Jul. 03, 2014

Jan. 22, 2014

Oct. 23, 2013USD ($)MWh

Sep. 01, 2012USD ($)

Mar. 31, 2017OrderProject

Dec. 31, 2016

Dec. 31, 2014

Aug. 31, 2010USD ($)

Apr. 30, 2019

Dec. 31, 2018USD ($)

Apr. 30, 2018

Dec. 31, 2017USD ($)CompanyPlantMW

Apr. 30, 2017

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Dec. 31, 2010

Mar. 11, 2017Customer

Sep. 30, 2012USD ($)

Mar. 31, 2010USD ($)MW

Industry Regulation [Line Items]

Number of networks supply companies | Company

4

Purchase obligation per year

$ 3,503,000,000

Equity ratio

50.00%

50.00%

Depreciation and amortization

$ 824,000,000

$ 804,000,000

$ 695,000,000

Approved return on equity

9.18%

11.74%

Purchase power, description

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

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

70.00%

Percentage of standard service customers with wholesale power supply agreements in place for the first half of 2019

20.00%

Public utilities regulatory authority distribution rate

9.10%

Number of REV related orders issued | Order

3

Number of energy storage projects | Project

2

REV related orders discription

The three orders involve: 1) modifications to the electric utilities’ proposed interconnection earnings adjustment mechanism framework; 2) further DSIP requirements, including filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at each company by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of the Value of DER.

Federal statutory income tax rate

35.00%

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

9.20%

Basis point added to return on equity

0.25%

Common equity ratio maximum dividend restriction threshold to set rates

3.00%

Number of average months used to set rate

13 months

Restricted net assets

$ 4,550,000,000

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

10

Current authorized distribution ROE for CL&P

9.17%

Cost of renewable connections program

$ 41,500,000

Ratio of equity investment in peaking generation for joint venture

50.00%

Number of peaking generation plants | Plant

2

Power purchase commitments [Member]

Industry Regulation [Line Items]

Period of purchase commitment

20 years

20 years

12 years

Purchase power, description

U.S. Power purchase commitments include the following: (i) a 55MW Biomass PPA for 12 years (four 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 (one year remaining) and (iv) a five year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2023)

Number of power purchase agreements | Agreement

22

6

Power purchase commitment | MW

72

32

55

Number of power purchase agreements terminated | Agreement

1

Number of power purchase agreements remaining | Agreement

21

Power purchase commitment from remaining contracts | MW

70

New York Transco [Member]

Industry Regulation [Line Items]

Percentage Of Return On Equity

9.65%

9.50%

Customer receiving percentage

53.00%

53.00%

Requested return on equity base percentage

10.60%

Requested return on equity basis points incentive

1.50%

Applicants requested

0.50%

Basis point added to return on equity

1.00%

0.50%

New York Transco [Member] | Network [Member]

Industry Regulation [Line Items]

Business combination, equity interest percentage

20.00%

20.00%

March 2017 Windstorm [Member]

Industry Regulation [Line Items]

Number of affected customers | Customer

219,000

October 2017 Storm [Member]

Industry Regulation [Line Items]

Number of broken poles resulting from damages | Pole

1,400

Estimated incremental costs from damages

$ 70,200,000

Capital costs associated with replacement of damaged infrastructure included in estimated incremental costs

32,400,000

Operations and maintenance expense for repairs included in estimated incremental costs

744,000,000,000

Net incremental operations and maintenance expense for restoration of the distribution system

$ 37,000,000

Scenario, Forecast [Member]

Industry Regulation [Line Items]

Federal statutory income tax rate

21.00%

Maximum [Member]

Industry Regulation [Line Items]

Requested return on equity base percentage

11.14%

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

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 storm costs

$ 123,000,000

CMP Distribution [Member] | Storm Costs [Member]

Industry Regulation [Line Items]

Depreciation amortization period

10 years

CMP Distribution [Member] | Regulatory Items Other Than Storm Costs [ Member]

Industry Regulation [Line Items]

Depreciation amortization period

5 years

CMP Distribution [Member] | Minimum [Member]

Industry Regulation [Line Items]

Exposure limit of storm cost

$ 3,000,000

New York State Electric And Gas Corporation

Industry Regulation [Line Items]

Percentage Of Return On Equity

10.00%

Equity ratio

48.00%

Depreciation and amortization

$ 15,200,000

Excess depreciation reserve

$ 303,900,000

Depreciation amortization period

20 years

3 years

New York State Electric And Gas Corporation | Storm Costs [Member]

Industry Regulation [Line Items]

Depreciation amortization period

5 years

New York State Electric And Gas Corporation | Regulatory Items Other Than Storm Costs [ Member]

Industry Regulation [Line Items]

Depreciation amortization period

10 years

RG&E [Member]

Industry Regulation [Line Items]

Depreciation and amortization

$ 5,300,000

Excess depreciation reserve

$ 105,000,000

Depreciation amortization period

20 years

NYSEG Gas [Member]

Industry Regulation [Line Items]

Percentage Of Return On Equity

9.50%

Equity ratio

48.00%

Approved return on equity

9.00%

Equity ratio for earnings sharing

50.00%

Customer receiving percentage

50.00%

NYSEG Gas [Member] | Scenario, Forecast [Member]

Industry Regulation [Line Items]

Percentage Of Return On Equity

9.75%

9.65%

RG&E Electric [Member]

Industry Regulation [Line Items]

Percentage Of Return On Equity

10.00%

Equity ratio

48.00%

Approved return on equity

9.00%

Equity ratio for earnings sharing

50.00%

Customer receiving percentage

75.00%

Percentage of revenue entitled

70.00%

70.00%

Maximum amount of investment under credit agreement

$ 110,000,000

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

Industry Regulation [Line Items]

Amortization Of Deferred Storm Cost

2,500,000

RG&E Electric [Member] | Scenario, Forecast [Member]

Industry Regulation [Line Items]

Percentage Of Return On Equity

10.25%

10.15%

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

Industry Regulation [Line Items]

Reliability support service agreement final payment

$ 2,300,000

RG&E Gas [Member]

Industry Regulation [Line Items]

Percentage Of Return On Equity

10.50%

Equity ratio

48.00%

Approved return on equity

9.00%

Equity ratio for earnings sharing

50.00%

Customer receiving percentage

90.00%

RG&E Gas [Member] | Scenario, Forecast [Member]

Industry Regulation [Line Items]

Percentage Of Return On Equity

10.75%

10.65%

NYSEG Electric [Member]

Industry Regulation [Line Items]

Recovery of deferred storm costs

$ 262,000,000

NYSEG Electric [Member] | Storm Costs [Member]

Industry Regulation [Line Items]

Regulatory items amortization period

10 years

NYSEG Electric [Member] | Regulatory Items Other Than Storm Costs [ Member]

Industry Regulation [Line Items]

Regulatory items amortization period

5 years

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 its 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]

Approved return on equity

9.18%

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.

SCG [Member]

Industry Regulation [Line Items]

Equity ratio

52.00%

Approved return on equity

9.36%

Public utilities regulatory authority distribution rate

9.25%

Proposed ROE for the year 2018

9.95%

Proposed ROE for the year 2019

9.95%

Proposed ROE for the year 2020

9.95%

Amount of proposed ROE for the year 2018

$ 1,500,000

Amount of proposed ROE for the year 2019

4,700,000

Amount of proposed ROE for the year 2020

$ 5,000,000

BGC [Member]

Industry Regulation [Line Items]

Approved return on equity

10.50%

RG&E & GNPP [Member]

Industry Regulation [Line Items]

Modified agreement monthly payment amount

$ 15,400,000

Ginna Nuclear Power Plant LLC [Member]

Industry Regulation [Line Items]

Percentage of revenue entitled

30.00%

30.00%

New Haven Harbor Station Site [Member]

Industry Regulation [Line Items]

Number of Megawatts of program | MWh

2.8

Bridgeport [Member]

Industry Regulation [Line Items]

Number of Megawatts of program | MWh

5

Woodbridge [Member]

Industry Regulation [Line Items]

Number of Megawatts of program | MWh

2.2

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

Industry Regulation [Line Items]

Revenue requirements for equity investment in peaking generation

$ 28,800,000

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

Industry Regulation [Line Items]

Revenue requirements for equity investment in peaking generation

$ 35,800,000

Industry Regulation - Electric

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

Regulatory Assets and Liabili74

Regulatory Assets and Liabilities - Additional Information (Detail) $ in Millions	Sep. 01, 2012	Aug. 31, 2010	Mar. 31, 2017USD ($)	Jun. 30, 2016USD ($)	Dec. 31, 2018	Dec. 31, 2017USD ($)Station	Dec. 31, 2016USD ($)
Regulatory Assets And Liabilities [Line Items]
Unrecorded Regulatory Assets						$ 1,887
Unfunded future income tax expense			$ 14	$ 126			$ 126
Unfunded future Income tax expense collection period						50 years
Deferred costs						$ 2.3
Federal statutory income tax rate						35.00%
UIL Holdings [Member]
Regulatory Assets And Liabilities [Line Items]
Business combination merger related rate credits						$ 2	20
Scenario, Forecast [Member]
Regulatory Assets And Liabilities [Line Items]
Federal statutory income tax rate					21.00%
NEW YORK
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
NEW YORK | Prior Tax Rate [Member]
Regulatory Assets And Liabilities [Line Items]
Statutory income tax rate, state						7.10%
NEW YORK | Revised Tax Rate [Member]
Regulatory Assets And Liabilities [Line Items]
Statutory income tax rate, state						6.50%
NEW YORK | Oswego [Member]
Regulatory Assets And Liabilities [Line Items]
Number of nuclear generating stations | Station						2
NEW YORK | Minimum [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period						27 years
NEW YORK | Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period						39 years
Asset Sale Gain Account [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Economic Development [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Merger Capital Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Positive Benefit Adjustment [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Post Term Amortization [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
New York State Electric And Gas Corporation
Regulatory Assets And Liabilities [Line Items]
Annual amortization of regulatory items						$ 16.5
Regulatory items amortization period		20 years				3 years
New York State Electric And Gas Corporation | Storm Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
New York State Electric And Gas Corporation | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						10 years
New York State Electric And Gas Corporation | Deferred Income Tax Charge [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						50 years
Central Maine Power Company [Member]
Regulatory Assets And Liabilities [Line Items]
Recovery of deferred storm costs						$ 123
Central Maine Power Company [Member] | Storm Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						10 years
Central Maine Power Company [Member] | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
UI [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory assets						$ 93	$ 75
UI [Member] | Storm Costs [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred costs						1
Regulatory assets						0
NYSEG [Member]
Regulatory Assets And Liabilities [Line Items]
Recovery of deferred storm costs						$ 262
NYSEG [Member] | Deferred Property Tax [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
RG&E [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period	20 years
RG&E [Member] | Deferred Property Tax [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years

Regulatory Assets and Liabili75

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Regulatory Asset [Line Items]
Current Regulatory Assets	$ 307	$ 285
Non-current Regulatory Assets	2,738	3,091
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	24	22
Non-current Regulatory Assets	110	134
Pension And Other Post-Retirement Benefits [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	7	7
Non-current Regulatory Assets	1,162	1,320
Storm Costs [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	46	40
Non-current Regulatory Assets	254	187
Temporary Supplemental Assessment Surcharge [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets		4
Support Services [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	27	27
Non-current Regulatory Assets	10	29
Revenue Decoupling Mechanism [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	21	15
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	8	12
Electric Supply Reconciliation [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets		13
Hedges Loss [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	3	10
Contracts For Differences [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	9	14
Non-current Regulatory Assets	84	61
Hardship Programs [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	14	16
Non-current Regulatory Assets	13	18
Deferred Property Tax [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	10	10
Non-current Regulatory Assets	14	33
Plant Decommissioning [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	6	6
Non-current Regulatory Assets	9	14
Deferred Purchased Gas [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	31	14
Deferred Transmission Expense [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	37	13
Environmental Restoration Costs [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	13	14
Non-current Regulatory Assets	283	287
Other [Member]
Regulatory Asset [Line Items]
Current Regulatory Assets	51	48
Non-current Regulatory Assets	71	73
Deferred Meter Replacement Costs [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	29	32
Unamortized Loss On Reacquired Debt [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	17	20
Future Income Tax [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	376	542
Asset Retirement Obligation Costs [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	18	18
Federal Tax Depreciation Normalization Adjustment [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	155	161
Merger Capital Expense [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	2	11
Debt Premium [Member]
Regulatory Asset [Line Items]
Non-current Regulatory Assets	$ 131	$ 151

Regulatory Assets and Liabili76

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	$ 178	$ 192
Non-current Regulatory Liabilities	3,239	1,753
Deferred income taxes regulatory	13	565
Regulatory liabilities including deferred income taxes, noncurrent	3,252	2,318
Support Services [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities		3
Non By Passable Charge [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	5	22
Energy Efficiency Services [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	37	45
Gas Supply Charge And Deferred Natural Gas Cost [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	4	6
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	14	5
Pension And Other Post-Retirement Benefits [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	1	3
Non-current Regulatory Liabilities	74	76
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	14	14
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	21	15
Non-current Regulatory Liabilities	72	95
Yankee DOE Refund [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	4	24
Merger Related Rate Credits [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	1	3
Non-current Regulatory Liabilities	20	21
Carrying Costs On Deferred Income Tax [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	5	5
Non-current Regulatory Liabilities	20	25
Revenue Decoupling Mechanism [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	4	9
Stranded Costs [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	17
Other [Member]
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	51	38
Non-current Regulatory Liabilities	67	73
Accrued Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	1,132	1,117
Tax Act - Remeasurement [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	1,515
Asset Sale Gain Account [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	10	9
Economic Development [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	32	35
Merger Capital Expense [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	6	15
Positive Benefit Adjustment [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	39	42
New York State Tax Rate Change [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	6	9
Post Term Amortization [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities		3
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	19	24
Deferred Property Tax [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	19	19
Net Plant Reconciliation [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	10	10
Variable Rate Debt [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	33	28
Rate Refund [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	27	22
Accumulated Deferred Investment Tax Credits [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	13	15
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	13	13
Transmission Congestion Contracts [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	19	18
Middletown/Norwalk Local Transmission Network Service Collections [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	19	19
Excess Generation Service Charge [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	2
Low Income Programs [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	42	46
Earning sharing provisions [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	22	12
Non-Firm Margin Sharing Credits [Member]
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	$ 8	$ 7

Goodwill and Intangible asset77

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Goodwill [Line Items]
Goodwill	$ 3,127	$ 3,124
Network [Member]
Goodwill [Line Items]
Goodwill	2,747	2,744
Renewables [Member]
Goodwill [Line Items]
Goodwill	$ 380	$ 380

Goodwill and Intangible asset78

Goodwill and Intangible assets - Additional Information (Detail)	Dec. 16, 2015USD ($)	Dec. 31, 2017USD ($)Segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2002USD ($)	Dec. 31, 2000USD ($)
Goodwill [Line Items]
Number of reporting units | Segment		3
Impairment of goodwill		$ 0	$ 0
Amortization expense		22,000,000	25,000,000	$ 54,000,000
Gas Storage Rights [Member]
Goodwill [Line Items]
Impairment of intangible assets			4,100,000	$ 6,500,000
Reclassified from intangible assets held for sale.		$ 193,000,000	$ 0
UIL Holdings [Member]
Goodwill [Line Items]
Goodwill	$ 1,765,000,000
Maine Reporting Unit [Member]
Goodwill [Line Items]
Goodwill						$ 325,000,000
New York Reporting Unit [Member]
Goodwill [Line Items]
Goodwill					$ 654,000,000

Goodwill and Intangible asset79

Goodwill and Intangible assets - Summary of Intangible Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 604	$ 923
Accumulated Amortization	(276)	(385)
Net Carrying Amount	328	538
Wind Development [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	583	587
Accumulated Amortization	(264)	(254)
Net Carrying Amount	319	333
Other [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount	21	17
Accumulated Amortization	(12)	(11)
Net Carrying Amount	$ 9	6
Gas Storage Rights [Member]
Finite Lived Intangible Assets [Line Items]
Gross Carrying Amount		319
Accumulated Amortization		(120)
Net Carrying Amount		$ 199

Goodwill and Intangible asset80

Goodwill and Intangible assets - Schedule of Amortization Expense (Detail) $ in Millions	Dec. 31, 2017USD ($)
Goodwill And Intangible Assets Disclosure [Abstract]
2,018	$ 16
2,019	19
2,020	18
2,021	21
2,022	$ 22

Property, Plant and Equipment81

Property, Plant and Equipment (Detail) - USD ($) $ in Millions	Dec. 31, 2017		Dec. 31, 2016		Dec. 31, 2015
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 28,741	[1]	$ 27,063	[2]
Total accumulated depreciation	(7,497)	[3]	(6,986)	[4]
Total Net Property, Plant and Equipment in Service	21,244		20,077
Construction work in progress	1,425		1,471
Total Property, Plant and Equipment	22,669		21,548		$ 20,711
Regulated [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	16,836	[1]	15,692	[2]
Total accumulated depreciation	(4,172)	[3]	(3,839)	[4]
Total Net Property, Plant and Equipment in Service	12,664		11,853
Construction work in progress	987		966
Total Property, Plant and Equipment	13,651		12,819
Unregulated [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	11,905	[1]	11,371	[2]
Total accumulated depreciation	(3,325)	[3]	(3,147)	[4]
Total Net Property, Plant and Equipment in Service	8,580		8,224
Construction work in progress	438		505
Total Property, Plant and Equipment	9,018		8,729
Electric Generation, Distribution and Transmission Equipment [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	24,625		22,634
Electric Generation, Distribution and Transmission Equipment [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	13,108		12,259
Electric Generation, Distribution and Transmission Equipment [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	11,517		10,375
Natural Gas, Transportation and Distribution Equipment [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	3,741		4,094
Natural Gas, Transportation and Distribution Equipment [Member] | Regulated [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	3,728		3,433
Natural Gas, Transportation and Distribution Equipment [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	13		661
Other Common Operating Property [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	375		335
Other Common Operating Property [Member] | Unregulated [Member]
Property Plant And Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 375		$ 335
[1]	Includes capitalized leases of $204 million primarily related to electric generation, distribution, transmission and other.
[2]	Includes capitalized leases of $208 million primarily related to electric generation, distribution, transmission and other.
[3]	Includes accumulated amortization of capitalized leases of $68 million.
[4]	Includes accumulated amortization of capitalized leases of $60 million.

Property, Plant and Equipment -

Property, Plant and Equipment - (Parenthetical) (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Property Plant And Equipment [Line Items]
Capital lease obligations	$ 74	$ 104
Accumulated Capitalized Interest Costs	68	60
Electric Generation, Distribution and Transmission Equipment [Member]
Property Plant And Equipment [Line Items]
Capital lease obligations	$ 204	$ 208

Property, Plant and Equipment83

Property, Plant and Equipment - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Sep. 30, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Property Plant And Equipment [Line Items]
Regulated property, plant and equipment classified to assets held for sale		$ 489	$ 0
Interest costs capitalized		28	20	$ 13
Accrued liabilities for property, plant and equipment additions		209	338	148
Tangible asset impairment charges		5	0	12
Depreciation		$ 802	$ 779	$ 641
Solar Star Oregon II [Member]
Property Plant And Equipment [Line Items]
Total purchase price	$ 121
Purchase price paid at the date of acquisition	105
Fair value of assets acquired	122
Liability recognized for contingent consideration payable	$ 13

Asset Retirement Obligations -

Asset Retirement Obligations - Reconciliation of ARO (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Beginning Balance	$ 161	$ 184
Liabilities settled during the year	(1)	(7)
Liabilities incurred during the year	13	3
Accretion expense	10	10
Revisions in estimated cash flows	13	(29)
Ending Balance	$ 196	$ 161

Asset Retirement Obligations 85

Asset Retirement Obligations - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted Cash	$ 2	$ 2
Estimated annual increase in expense upon revision	$ 2

Debt - Schedule of Long-term De

Debt - Schedule of Long-term Debt (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Capital lease obligations	$ 74	$ 104
Unamortized debt issuance costs and discount	(38)	(31)
Long-Term Debt	5,379	4,859
Less: debt due within one year, included in current liabilities	183	349
Total Non-current Debt	$ 5,196	4,510
First Mortgage Bonds - Fixed [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start	2,018
Debt Instrument, Maturity Date, End	2,045
Long-Term Debt	$ 2,054	$ 1,752
First Mortgage Bonds - Fixed [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	3.07%	3.07%
First Mortgage Bonds - Fixed [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	10.60%	10.60%
Unsecured Pollution Control Notes - Fixed [Member]
Debt Instrument [Line Items]
Debt instrument maturity year	2,020
Long-Term Debt	$ 200	$ 200
Unsecured Pollution Control Notes - Fixed [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	2.00%	2.00%
Unsecured Pollution Control Notes - Fixed [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	2.375%	2.375%
Unsecured Pollution Control Notes – Variable [Member]
Debt Instrument [Line Items]
Debt instrument maturity year	2,032
Long-Term Debt	$ 62	$ 62
Debt instrument, interest rate	1.94%	1.32%
Other Various Non-current Debt - Fixed [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start	2,018
Debt Instrument, Maturity Date, End	2,045
Long-Term Debt	$ 3,027	$ 2,772
Other Various Non-current Debt - Fixed [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	2.89%	2.89%
Other Various Non-current Debt - Fixed [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	10.48%	10.48%
Obligations Under Capital Leases [Member]
Debt Instrument [Line Items]
Debt Instrument, Maturity Date, Start	2,018
Debt Instrument, Maturity Date, End	2,030
Obligations Under Capital Leases [Member] | Minimum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	4.00%	4.00%
Obligations Under Capital Leases [Member] | Maximum [Member]
Debt Instrument [Line Items]
Debt instrument, interest rate	4.44%	4.44%

Debt - Schedule of Long-term 87

Debt - Schedule of Long-term Debt (Parenthetical) (Detail) $ in Millions	Dec. 31, 2017USD ($)
First Mortgage Bonds - Fixed [Member]
Debt Instrument [Line Items]
Bond pledged as collateral	$ 6,365

Debt - Additional Information (

Debt - Additional Information (Detail) - USD ($)	Nov. 21, 2017	May 24, 2017	Apr. 05, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	May 13, 2016
Debt Instrument [Line Items]
Non-current note issuance				$ 888,000,000	$ 493,000,000	$ 350,000,000
Estimated fair value of debt				5,799,000,000	5,204,000,000
Notes payable				786,000,000	161,000,000
Commercial paper				507,000,000	150,000,000
Credit facility amount drawn				250,000,000
Notes payable to affiliates				29,000,000	10,000,000
Other notes payable					1,000,000
Credit facility remaining borrowing capacity				743,000,000	1,350,000,000
UIL Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity							$ 1,000,000,000
AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility amount drawn				$ 250,000,000	0
Credit facility maximum borrowing capacity			$ 1,500,000,000
Maturity date for credit facility				Apr. 5, 2021
AVANGRID Credit Facility [Member] | Minimum [Member]
Debt Instrument [Line Items]
Credit facility initial fees range			0.10%
AVANGRID Credit Facility [Member] | Maximum [Member]
Debt Instrument [Line Items]
Credit facility initial fees range			0.175%
Level 3 [Member]
Debt Instrument [Line Items]
Estimated fair value of debt					61,000,000
Avangrid, Inc [Member]
Debt Instrument [Line Items]
Non-current note issuance				$ 594,000,000	$ 483,000,000
Avangrid, Inc [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 1,000,000,000
3.150% Notes due 2024 [Member] | Avangrid, Inc [Member]
Debt Instrument [Line Items]
Debt instrument principal amount	$ 600,000,000
Debt instrument maturity year	2,024
Interest rate on outstanding loans	3.15%
Non-current note issuance	$ 594,000,000
RG&E [Member] | 3.10% First Mortgage Bonds due 2027 [Member]
Debt Instrument [Line Items]
Debt instrument principal amount		$ 300,000,000
Debt instrument maturity year		2,027
Interest rate on outstanding loans		3.10%
Non-current note issuance		$ 294,000,000
NYSEG, RGE, CMP and UI [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			250,000,000
CNG and SCG [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			150,000,000
BGC [Member] | AVANGRID Credit Facility [Member]
Debt Instrument [Line Items]
Credit facility maximum borrowing capacity			$ 25,000,000

Debt - Schedule of Maturities a

Debt - Schedule of Maturities and Repayments of Long-term Debt (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Debt Instrument [Line Items]
Total	$ 5,196	$ 4,510
Non-current debt, including sinking fund obligations and capital lease payments, due over the next five [Member]
Debt Instrument [Line Items]
2,018	183
2,019	357
2,020	722
2,021	307
2,022	369
Total	$ 1,938

Fair Value of Financial Instr90

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other Assets	$ 71	$ 241
Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value input, gas or power delivery period (in years)	2 years
Restricted Cash [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Other Assets	$ 5	$ 5
RG&E [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Percentage of electric load obligations using contracts for a NYISO location	70.00%

Fair Value of Financial Instr91

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 106	$ 172
Derivative financial instruments, liabilities	(128)	(153)
Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(195)	(281)
Derivative financial instruments, liabilities	147	296
Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	41	40
Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	69	75
Derivative financial instruments, liabilities	(9)	(15)
Derivative Financial Instrument Power [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(49)	(42)
Derivative financial instruments, liabilities	37	39
Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	25	77
Derivative financial instruments, liabilities	(15)	(43)
Derivative Financial Instrument Gas [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(146)	(239)
Derivative financial instruments, liabilities	110	257
Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	12	20
Derivative financial instruments, liabilities	(104)	(95)
Fair Value, Inputs, Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	103	191
Derivative financial instruments, liabilities	(94)	(237)
Fair Value, Inputs, Level 1 [Member] | Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	41	40
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	14	11
Derivative financial instruments, liabilities	(14)	(24)
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	89	180
Derivative financial instruments, liabilities	(80)	(213)
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	48	80
Derivative financial instruments, liabilities	(37)	(61)
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	30	48
Derivative financial instruments, liabilities	(17)	(27)
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	18	32
Derivative financial instruments, liabilities	(20)	(34)
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	150	182
Derivative financial instruments, liabilities	(144)	(151)
Level 3 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	74	58
Derivative financial instruments, liabilities	(15)	(3)
Level 3 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	64	104
Derivative financial instruments, liabilities	(25)	(53)
Level 3 [Member] | Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	12	20
Derivative financial instruments, liabilities	$ (104)	$ (95)

Fair Value of Financial Instr92

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument Fair Value Carrying Value [Abstract]
Fair value as of January 1,		$ 31	$ (19)	$ 57
Gains for the year recognized in operating revenues		18	67	33
Losses for the year recognized in operating revenues		(1)		(8)
Total gains or losses for the period recognized in operating revenues		17	67	25
Gains recognized in OCI		2	1	2
Losses recognized in OCI		(1)		(3)
Total gains or losses recognized in OCI		1	1	(1)
Net change recognized in regulatory assets and liabilities		(17)	(8)
Purchases		(5)	3	(73)
Settlements		(17)	(9)	(14)
Transfers out of Level 3	[1]	(4)	(4)	(13)
Fair value as of December 31,		6	31	(19)
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		$ 17	$ 67	$ 25
[1]	Transfers out of Level 3 were the result of increased observability of market data.

Fair Value of Financial Instr93

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	12 Months Ended
	Dec. 31, 2017$ / MMBTU$ / MWh
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Instruments	Fixed price power and gas swaps with delivery period > two years
Instrument Description	Transactions with delivery periods exceeding two years
Valuation Technique	Transactions are valued against forward market prices on a discounted basis
Valuation Inputs	Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products
CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	NYMEX ($/MMBtu)
CME SWAPS MARKETS (NYMEX) [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	3.07
CME SWAPS MARKETS (NYMEX) [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	3.93
CME SWAPS MARKETS (NYMEX) [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	2.35
Indiana Hub [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Indiana hub ($/MWh)
Indiana Hub [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	31.77
Indiana Hub [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	65.55
Indiana Hub [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	18.53
Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Mid C ($/MWh)
Mid C [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	24.59
Mid C [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	46.50
Mid C [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	(0.50)
Minn Hub [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Minn hub ($/MWh)
Minn Hub [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	26.40
Minn Hub [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	62.33
Minn Hub [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	9.56

Fair Value of Financial Instr94

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, 2017$ / MWh
Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.11%
Discount rate	1.89%
Forward pricing ($ per MW)	5.30
Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.49%
Discount rate	2.40%
Forward pricing ($ per MW)	9.55

Derivative Instruments and He95

Derivative Instruments and Hedging - Additional Information (Detail) - USD ($)		12 Months Ended
		Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities			$ 47,000,000	$ 81,000,000	$ (74,000,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income			(8,000,000)	(22,000,000)	(25,000,000)
Derivative financial instruments, assets			106,000,000	172,000,000
Gross Amounts of Recognized Liabilities			128,000,000	153,000,000
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes	[1]		14,000,000	(16,000,000)	7,000,000
Assets Held for Sale, Not Discontinued Operations [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments classified as assets held for sale				0
UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets			12,000,000	19,000,000
Regulatory Assets			93,000,000	75,000,000
Gross Amounts of Recognized Liabilities			104,000,000	95,000,000
Regulatory liabilities			$ 0	0
Contracts For Differences [Member] | UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers			20.00%
Contracts For Differences [Member] | CL&P [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers			80.00%
Derivative financial instruments, assets			$ 0	0
Gross Amounts of Recognized Liabilities			90,000,000	70,000,000
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	[2]		(1,000,000)		(3,000,000)
Network [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges			8,000,000	8,000,000	8,600,000
Ineffective portion of Cash flow hedge			0	0	0
Unrealized gain(loss) from hedging activities reported on OCI			$ (100,000)
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months			12 months
Network [Member] | Cash Flow Hedging [Member] | Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes		$ 8,000,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months		$ 100,000
Network [Member] | forward starting swaps [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps			$ 68,800,000	76,700,000
Network [Member] | Electricity Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities			(200,000)	(12,300,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income			(36,900,000)	(66,700,000)	(46,900,000)
Network [Member] | Natural Gas Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities			(2,500,000)	3,500,000
Gain (Loss) reclassified from regulatory assets and liabilities into income			$ (200,000)	(1,900,000)	(6,300,000)
Network [Member] | Fuel Derivatives [Member] | Cash Flow Hedging [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges			12 months
Renewables and Gas Activities [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Ineffective portion of Cash flow hedge			$ 2,600,000	(6,800,000)	4,800,000
Unrealized gain(loss) from hedging activities reported on OCI			$ 20,900,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months			12 months
Gain Recognized in OCI Derivatives Effective Portion			$ (500,000)	400,000	$ 2,300,000
Net loss in accumulated OCI related to discontinued cash flow hedge			200,000
Counter Party [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities			3,000,000
Cash Collateral Pledged			30,000,000	$ 20,000,000
Counter Party [Member] | UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative collateral obligation to be paid in decrease in credit rating below investment grade			$ 15,800,000
[1]	Reclassification is reflected in the operating expenses line item in the consolidated statements of income.
[2]	Changes in OCI are reported in pre-tax dollars, the reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the consolidated statements of income.

Derivative Instruments and He96

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions	Dec. 31, 2015	Dec. 31, 2017	Dec. 31, 2016
Derivative Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Assets (Liabilities)	$ (1)	$ (8)	$ (7)
Derivative Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Assets (Liabilities)		$ (9)	$ (1)

Derivative Instruments and He97

Derivative Instruments and Hedging - Net Notional Volume (Detail)	Dec. 31, 2017MWhDTHgal	Dec. 31, 2016MWhDTHgal
Network [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	3,900,000	5,600,000
Network [Member] | Natural Gas Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	6,100,000	5,800,000
Network [Member] | Fleet Fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | gal	2,100,000	2,300,000
Renewables and Gas Activities [Member] | Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	68,000,000	49,000,000
Renewables and Gas Activities [Member] | Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	62,000,000	45,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	4,000,000	3,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	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	285,000,000	329,000,000
Renewables and Gas Activities [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	12,000,000	8,000,000

Derivative Instruments and He98

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Network [Member] | UIL Holdings [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	$ 7	$ 12
Total derivatives as presented in the balance sheet	7	12
Network [Member] | UIL Holdings [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	20	19
Derivative liabilities	(13)	(7)
Derivative Fair Value, Net	7	12
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	5	11
Total derivatives as presented in the balance sheet	5	11
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	5	16
Derivative liabilities		(5)
Derivative Fair Value, Net	5	11
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(19)	(33)
Cash collateral receivable	3	10
Total derivatives as presented in the balance sheet	(16)	(23)
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	13	7
Derivative liabilities	(32)	(40)
Derivative Fair Value, Net	(19)	(33)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(88)	(74)
Cash collateral receivable		2
Total derivatives as presented in the balance sheet	(88)	(72)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets		5
Derivative liabilities	(88)	(79)
Derivative Fair Value, Net	(88)	(74)
Renewables and Gas Activities [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	53	104
Total derivatives as presented in the balance sheet	36	87
Cash collateral receivable (payable)	(17)	(17)
Renewables and Gas Activities [Member] | Current Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	111	198
Derivative liabilities	(82)	(118)
Derivative Fair Value, Net	29	80
Renewables and Gas Activities [Member] | Current Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	24	25
Derivative liabilities		(1)
Derivative Fair Value, Net	24	24
Renewables and Gas Activities [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	97	108
Total derivatives as presented in the balance sheet	58	62
Cash collateral receivable (payable)	(39)	(46)
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	99	108
Derivative liabilities	(5)	(4)
Derivative Fair Value, Net	94	104
Renewables and Gas Activities [Member] | Noncurrent Assets [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	4	4
Derivative liabilities	(1)
Derivative Fair Value, Net	3	4
Renewables and Gas Activities [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(23)	(93)
Total derivatives as presented in the balance sheet	(20)	(52)
Cash collateral receivable (payable)	3	41
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	31	78
Derivative liabilities	(51)	(132)
Derivative Fair Value, Net	(20)	(54)
Renewables and Gas Activities [Member] | Current Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(3)	(39)
Derivative Fair Value, Net	(3)	(39)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(7)	(30)
Total derivatives as presented in the balance sheet	(4)	(6)
Cash collateral receivable (payable)	3	24
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Not Designated as Hedging Instruments [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	4	7
Derivative liabilities	(10)	(16)
Derivative Fair Value, Net	(6)	(9)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member] | Designated as Hedging Instrument [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	2
Derivative liabilities	(3)	(21)
Derivative Fair Value, Net	$ (1)	$ (21)

Derivative Instruments and He99

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI on Derivatives Effective Portion	[1]	$ (1)		$ (3)
Loss Reclassified from Accumulated OCI into Income Effective Portion	[1]	9	$ 10	12
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income Effective Portion	[2]	14	(43)	(2)
(Loss) Gain Recognized in OCI on Derivatives Effective Portion	[2]	41	(42)	57
Interest Rate Contract [Member] | Network [Member] | Interest expense [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income Effective Portion	[1]	8	8	9
Commodity Contract [Member] | Network [Member] | Operating expenses [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI on Derivatives Effective Portion	[1]	(1)		(3)
Loss Reclassified from Accumulated OCI into Income Effective Portion	[1]	1	2	3
Commodity Contract [Member] | Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives Effective Portion	[2]	41	(42)	57
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Revenue [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss Reclassified from Accumulated OCI into Income Effective Portion	[2]	$ 14	$ (43)	$ (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 consolidated statements of income.
[2]	Changes in OCI are reported on a pre-tax basis.

Derivative Instruments and H100

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 70	$ 91
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	55	56
Long [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(3)	(2)
Long [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	19	30
Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(13)	3
Short [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	8	6
Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 4	$ (2)

Derivative Instruments and H101

Derivative Instruments and Hedging - Effect of Trading Derivatives (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (8)	$ (22)	$ (25)
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(3)	3	6
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	4	(7)	(5)
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(1)	4
Renewables and Gas Activities [Member] | Trading Derivatives [Member] | Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (8)	$ (22)	$ (26)

Derivative Instruments and H102

Derivative Instruments and Hedging - Effect of Non-Trading Derivatives (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (8)	$ (22)	$ (25)
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(15)	13	29
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	1	9	(8)
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(3)	(20)	(5)
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(5)	(10)	24
Renewables and Gas Activities [Member] | Non-Trading Derivatives [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (8)	$ 34	$ 18

Commitments and Contingent L103

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

Oct. 06, 2017

Oct. 05, 2017Lawsuit

Jun. 20, 2017MW

May 25, 2017MW

Apr. 14, 2017

Apr. 29, 2016

Mar. 22, 2016

Feb. 23, 2016

Oct. 21, 2015USD ($)

Jul. 31, 2014

Jan. 22, 2014

Dec. 26, 2012

Dec. 31, 2017USD ($)UnitMW

Dec. 31, 2016USD ($)

Dec. 31, 2015USD ($)

Mar. 11, 2017Customer

Loss Contingencies [Line Items]

Approved return on equity

9.18%

11.74%

Requested return on equity base percentage

9.20%

Disclosure of Rate Matters

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

Midpoint of base return on equity warranted percentage

9.39%

Regulatory liabilities

$ 3,239

$ 1,753

Loss contingency, date of dismissal

Oct. 5, 2017

Number of complaints dismissed | Lawsuit

4

Loss contingency dismissal description

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

Price of the PPAs

$ 259

Operating lease expenses

71.5

70.6

$ 47.7

Contingent rent payment for electricity generation facility

$ 18.6

22.2

22.2

Modified agreement monthly payment amount

$ 15.4

Purchase power, description

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

Standby letters of credit

$ 2,400

Power purchase commitments [Member]

Loss Contingencies [Line Items]

Purchase power, description

U.S. Power purchase commitments include the following: (i) a 55MW Biomass PPA for 12 years (four 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 (one year remaining) and (iv) a five year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2023)

Power purchase commitment | MW

72

32

55

Period of purchase commitment

20 years

20 years

12 years

Power purchase commitment, remaining period

4 years

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 years

Power purchase commitment, remaining period

1 year

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 (four 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 years

Power purchase commitment, remaining period

4 years

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

Loss Contingencies [Line Items]

Power purchase commitment | MW

34.4

RG&E Electric [Member]

Loss Contingencies [Line Items]

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%

Support Services [Member]

Loss Contingencies [Line Items]

Operating lease expenses

$ 5.6

114.9

79.9

Support Services [Member] | Coal Fired Generating Station

Loss Contingencies [Line Items]

Operating lease expenses

$ 17.6

$ 37.8

$ 25.5

Number of Coal-Fired Generating Unit | Unit

2

March 2017 Windstorm [Member]

Loss Contingencies [Line Items]

Number of affected customers | Customer

219,000

Maximum [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

11.14%

Complaint II [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.70%

Disclosure of Rate Matters

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

Requested effective return on equity base percentage

11.14%

Regulatory liabilities

$ 22.5

Complaint II [Member] | Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Complaint III [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.84%

Requested effective return on equity base percentage

11.14%

Regulatory liabilities

$ 4.4

Complaint III [Member] | Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Complaint II and III [Member]

Loss Contingencies [Line Items]

Disclosure of Rate Matters

On November 24, 2014, FERC accepted the Complaint III, established a 15-month refund effective date of July 31, 2014, and set this matter consolidated with Complaint II for hearing in June 2015. Hearings relating to the refund periods and going forward period were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the NETOs filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The FERC Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that: (1) for the 15-month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the 15 month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The Initial Decision is the Administrative Law Judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in 2018.

Reasonably possible loss, in additional reserve, pre tax

$ 17.1

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

Loss Contingencies [Line Items]

Approved return on equity

10.57%

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

Loss Contingencies [Line Items]

Approved return on equity

9.59%

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

Loss Contingencies [Line Items]

Approved return on equity

10.90%

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

Loss Contingencies [Line Items]

Approved return on equity

8.61%

Requested existing base return on equity base percentage

10.57%

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

Loss Contingencies [Line Items]

Approved return on equity

11.24%

Before Amendment [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.14%

Beginning in 2019 and Expiring in 2023 [Member] | Power purchase commitments [Member] | Hydro Capacity and Energy [Member]

Loss Contingencies [Line Items]

Period of purchase commitment

5 years

Power purchase commitment, beginning year

2,019

Power purchase commitment, expiring year

2,023

Commitments and Contingent L104

Commitments and Contingent Liabilities - Schedule of Future Minimum Lease Payment (Detail) $ in Millions	Dec. 31, 2017USD ($)
Commitments And Contingencies Disclosure [Abstract]
Operating lease, 2018	$ 36
Operating lease, 2019	35
Operating leases, 2020	36
Operating leases, 2021	36
Operating leases, 2022	31
Operating leases, Thereafter	757
Total operating lease	931
Capital lease, 2018	7
Capital lease, 2019	8
Capital leases, 2020	8
Capital leases, 2021	5
Capital leases, 2022	2
Capital leases, Thereafter	47
Total capital lease	77
Operating and capital leases, 2018	43
Operating and capital leases, 2019	43
Operating and capital leases, 2020	44
Operating and capital leases, 2021	41
Operating and capital leases, 2022	33
Operating and capital leases, Thereafter	804
Total operating and capital leases	$ 1,008

Commitments and Contingent L105

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, 2017USD ($)
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2018	$ 979
Forward purchase commitments, 2019	563
Forward purchase commitments, 2020	327
Forward purchase commitments, 2021	258
Forward purchase commitments, 2022	195
Forward purchase commitments, thereafter	1,181
Total forward purchase commitments	3,503
Forward sales commitments, 2018	157
Forward sales commitments, 2019	114
Forward sales commitments, 2020	78
Forward sales commitments, 2021	55
Forward sales commitments, 2022	23
Forward sales commitments, thereafter	42
Total forward sales commitments	469
Derivative Financial Instrument Gas [Member]
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2018	280
Forward purchase commitments, 2019	239
Forward purchase commitments, 2020	186
Forward purchase commitments, 2021	149
Forward purchase commitments, 2022	120
Forward purchase commitments, thereafter	638
Total forward purchase commitments	1,612
Forward sales commitments, 2018	26
Forward sales commitments, 2019	9
Forward sales commitments, 2020	7
Forward sales commitments, 2021	4
Total forward sales commitments	46
Power [Member]
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2018	171
Forward purchase commitments, 2019	123
Forward purchase commitments, 2020	102
Forward purchase commitments, 2021	89
Forward purchase commitments, 2022	63
Forward purchase commitments, thereafter	443
Total forward purchase commitments	991
Forward sales commitments, 2018	127
Forward sales commitments, 2019	104
Forward sales commitments, 2020	71
Forward sales commitments, 2021	51
Forward sales commitments, 2022	23
Forward sales commitments, thereafter	42
Total forward sales commitments	418
Other Forward Purchases And Sales Commitments
Oil And Gas Delivery Commitments And Contracts [Line Items]
Forward purchase commitments, 2018	528
Forward purchase commitments, 2019	201
Forward purchase commitments, 2020	39
Forward purchase commitments, 2021	20
Forward purchase commitments, 2022	12
Forward purchase commitments, thereafter	100
Total forward purchase commitments	900
Forward sales commitments, 2018	4
Forward sales commitments, 2019	1
Total forward sales commitments	$ 5

Environmental Liabilities - Add

Environmental Liabilities - Additional Information (Detail) $ in Millions	Jul. 05, 2017USD ($)	Sep. 11, 2014USD ($)	Aug. 14, 2013USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)	Dec. 31, 2017USD ($)siteLocation	Dec. 31, 2016USD ($)	Aug. 04, 2016USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							25
Number of sites where gas was manufactured in the past | site							53
Number of sites for which we have entered into consent orders to investigate and remediate | site							49
Costs related to investigation and remediation							$ 389	$ 388
Accrual for environmental loss contingencies		$ 27					$ 22
Damages for incurred costs payment amount		$ 22
Refund of environmental remediation cost paid					$ 5
Number of sites with modified decision | site							9
First Energy [Member]
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax						$ 60
Environmental costs paid				$ 30
First Energy [Member] | Past Costs [Member]
Environmental Exit Cost [Line Items]
Accrual for environmental loss contingencies				27
First Energy [Member] | Pre-judgment Interest [Member]
Environmental Exit Cost [Line Items]
Environmental costs paid				$ 3
Century Indemnity and OneBeacon [Member]
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax			$ 89
Number of hazardous waste sites | Location							22
Legal discovery process expected closing year description							Century Indemnity and OneBeacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s
Asnat [Member] | Environmental Remediation Activities [Member]
Environmental Exit Cost [Line Items]
Pretrial memorandum claiming damages	$ 10
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 25		$ 30
Maximum [Member] | Century Indemnity and OneBeacon [Member]
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax			$ 282
New York State Registry [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							15
Number of sites where gas was manufactured in the past | site							8
Maine's Uncontrolled Sites Program [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							6
Number of sites where gas was manufactured in the past | site							2
Massachusetts Non- Priority Confirmed Disposal Site List [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							1
National Priorities List [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							9
Ten of Twenty-five Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 5
Another Ten Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							8
Another Ten Sites [Member] | Minimum [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							12
Another Ten Sites [Member] | Maximum [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 21
New York Voluntary Cleanup Program [Member]
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site							12
Maine's Voluntary Response Action Program [Member]
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site							3
Manufactured Gas Plants | Connecticut [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 100	$ 97
Manufactured Gas Plants | Minimum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							213
Manufactured Gas Plants | Maximum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 442

Income Taxes - Additional Infor

Income Taxes - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Taxes [Line Items]
Fedral statutory income tax rate		35.00%
Valuation allowance for deferred tax assets		$ 21,000,000	$ 31,000,000
Decrease in valuation allowance, net of federal benefit		10,000,000
Tax credit carryforword reduction in valuation alowance		15,900,000
Change in corporate tax rate from reducing the federal benefit of state taxes		3,000,000
Additional valuation on state net operating losses		8,500,000
Additional valuation on state net operating losses release in Maine super credits		5,300,000
Accruals for interest and penalties on tax reserves		400,000	$ 2,000,000	$ 2,000,000
Unrecognized tax benefits that would impact effective tax rate		14,000,000
Net decrease to unrecognized tax benefits		0
Federal
Income Taxes [Line Items]
Net operating loss carry forwards		$ 3,600,000,000
Expiration year for net operating losses		2,028
Expiration year for tax credits		2,023
State
Income Taxes [Line Items]
Net operating loss carry forwards		$ 231,000,000
Tax credit carry forward		37,000,000
Recognized valuation allowance		$ 21,000,000
Expiration year for net operating losses		2,021
Renewable Energy and Investment | Federal
Income Taxes [Line Items]
Tax credit carry forward		$ 404,000,000
R&D | Federal
Income Taxes [Line Items]
Tax credit carry forward		404,000,000
Other | Federal
Income Taxes [Line Items]
Tax credit carry forward		$ 404,000,000
Scenario, Forecast [Member]
Income Taxes [Line Items]
Fedral statutory income tax rate	21.00%

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Current
Federal	$ (20)	$ (6)	$ (20)
State	12	8	(33)
Current taxes charged to (benefit) expense	(8)	2	(53)
Deferred
Federal	(124)	412	131
State	(73)	2	(6)
Deferred taxes charged to (benefit) expense	(197)	414	125
Production tax credits	(53)	(38)	(42)
Investment tax credits	(1)	(1)	(1)
Total Income Tax (Benefit) Expense	$ (259)	$ 377	$ 29

Income Taxes - Schedule of Diff

Income Taxes - Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 43	$ 353	$ 106
Depreciation and amortization not normalized	9	61	15
Investment tax credit amortization	(1)	(1)	(1)
Tax return related adjustments	7	(2)	6
Production tax credits	(53)	(38)	(42)
Tax equity financing arrangements	(10)	(27)	(42)
Federal tax rate impact on held for sale classification	82
State tax (benefit) expense, net of federal benefit	(40)	7	(25)
Tax Act - remeasurement	(328)
Non-deductible acquisition costs			9
Other, net	32	24	3
Total Income Tax (Benefit) Expense	$ (259)	$ 377	$ 29

Income Taxes - Schedule of Defe

Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Non-current Deferred Income Tax Liabilities (Assets)
Property related	$ 3,543	$ 5,195
Unfunded future income taxes	75	216
Federal and state tax credits	(574)	(417)
Accumulated deferred investment tax credits	14	14
Federal and state NOL’s	(975)	(1,397)
Joint ventures/partnerships	302	565
Nontaxable grant revenue	(449)	(581)
Pension and other post-retirement benefits	(33)	52
Tax Act - tax on regulatory remeasurement	(401)
Other	(58)	(223)
Non-current Deferred Income Tax Liabilities	1,444	3,424
Add: Valuation allowance	21	31
Total Non-current Deferred Income Tax Liabilities	1,465	3,455
Less amounts classified as regulatory liabilities non-current deferred income taxes	13	565
Deferred income taxes	1,452	2,890
Deferred tax assets	2,490	2,617
Deferred tax liabilities	$ 3,955	$ 6,072

Income Taxes - Schedule of Reco

Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Income Tax Disclosure [Abstract]
Beginning Balance	$ 40	$ 36	$ 38
Increases for tax positions related to prior years	23	8	1
Decreases for tax positions related to prior years	(16)	(4)
Reduction for tax position related to settlements with taxing authorities	(2)		(3)
Ending Balance	$ 45	$ 40	$ 36

Post-Retirement and Similar 112

Post-Retirement and Similar Obligations - Obligations and Funded Status (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016
Pension Plan [Member]
Change in plan assets
Fair value of plan assets, Beginning balance	[1]	$ 1,582
Fair Value of Plan Assets, Ending balance		1,734	$ 1,582	[1]
Other Postretirement Benefit Plan [Member]
Change in plan assets
Fair value of plan assets, Beginning balance		160
Fair Value of Plan Assets, Ending balance		165	160
Networks and ARHI [Member] | Pension Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance		3,448	3,509
Service cost		42	44
Interest cost		139	142
Actuarial loss (gain)		188	(43)
Benefits paid		(219)	(204)
Reclassified to held for sale		(5)
Benefit Obligation, Ending balance		3,593	3,448
Change in plan assets
Fair value of plan assets, Beginning balance		2,672	2,664
Actual return on plan assets		382	169
Employer contributions		33	43
Benefits paid		(219)	(204)
Reclassified to held for sale		(3)
Fair Value of Plan Assets, Ending balance		2,865	2,672
Funded Status as of December 31,		(728)	(776)
Networks and ARHI [Member] | Other Postretirement Benefit Plan [Member]
Change in benefit obligation
Benefit obligation, Beginning balance		495	525
Service cost		4	5
Interest cost		22	21
Plan participants’ contributions		7	7
Actuarial loss (gain)		3	(24)
Benefits paid		(39)	(39)
Reclassified to held for sale		(1)
Benefit Obligation, Ending balance		491	495
Change in plan assets
Fair value of plan assets, Beginning balance		160	162
Actual return on plan assets		17	11
Employer contributions		20	30
Plan participants’ contributions		7	7
Benefits paid		(39)	(39)
Withdrawals from VEBA			(11)
Fair Value of Plan Assets, Ending balance		165	160
Funded Status as of December 31,		$ (326)	$ (335)
[1]	Certain amounts in this table have been reclassified to conform to 2017 presentation.

Post-Retirement and Similar 113

Post-Retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Non-current liabilities	$ (728)	$ (776)
Total	(728)	(776)
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(321)	(330)
Total	$ (326)	$ (335)

Post-Retirement and Similar 114

Post-Retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Detail) - ARHI - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net (gain) loss	$ 25	$ 23	$ 25
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net (gain) loss	$ (4)	$ (3)	$ (1)

Post-Retirement and Similar 115

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, 2017	Dec. 31, 2016	Dec. 31, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss	$ 737	$ 860	$ 994
Prior service cost (credit)	6	7	9
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Net loss	35	44	76
Prior service cost (credit)	$ (31)	$ (40)	$ (49)

Post-Retirement and Similar 116

Post-Retirement and Similar Obligations - Additional Information (Detail) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2018
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	37.00%
Equity Securities [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	35.00%
Equity Securities [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	54.00%
Equity Alternative Securities [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	3.00%
Equity Alternative Securities [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	20.00%
Liability Hedging Assets [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	43.00%
Liability Hedging Assets [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	45.00%
Other Postretirement Benefit Plan [Member] | Large Cap Domestic Equities [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	27.00%
Other Postretirement Benefit Plan [Member] | Large Cap Domestic Equities [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	66.00%
Other Postretirement Benefit Plan [Member] | Small Cap Domestic Equities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	5.00%
Other Postretirement Benefit Plan [Member] | International Developed Markets [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	8.00%
Other Postretirement Benefit Plan [Member] | Emerging Market Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	6.00%
Other Postretirement Benefit Plan [Member] | Core Fixed Income [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	24.00%
Other Postretirement Benefit Plan [Member] | Global High Yield Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	4.00%
Other Postretirement Benefit Plan [Member] | International Developed Market Debt [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	3.00%
Other Postretirement Benefit Plan [Member] | Real Estate [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	6.00%
Other Postretirement Benefit Plan [Member] | Tangible Assets [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	6.00%
Other Postretirement Benefit Plan [Member] | Environmental Remediation Activities [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	31.00%
Other Postretirement Benefit Plan [Member] | Other Multi-asset Funds [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	3.00%
Other Postretirement Benefit Plan [Member] | Other Multi-asset Funds [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	11.00%
Scenario, Forecast [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan assets				$ 0
Scenario, Forecast [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan assets				$ 0
Networks and ARHI [Member]
Defined Benefit Plan Disclosure [Line Items]
Accumulated benefit obligation	$ 3,363,000,000	$ 3,214,000,000
Networks and ARHI [Member] | Non-Qualified Pension Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Other current and Other Non-current Liabilities	55,000,000	57,000,000
Networks and ARHI [Member] | Defined Contribution Plans [Member]
Defined Benefit Plan Disclosure [Line Items]
Annual contributions made	36,000,000	$ 34,000,000	$ 17,000,000
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected contribution for pension benefit plans during 2018	$ 48,000,000
Asset return seeking percentage category			7.50%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	7.00%	7.40%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	7.75%	7.75%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	6.13%	7.16%
ARHI | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	5.50%	5.50%	5.50%
ARHI | Pension Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	33.00%
ARHI | Pension Plan [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	50.00%
ARHI | Pension Plan [Member] | Other Investment Types [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	17.00%
ARHI | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Asset return seeking percentage category	5.50%	5.50%	5.75%
ARHI | Other Postretirement Benefit Plan [Member] | Equity Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	48.00%
ARHI | Other Postretirement Benefit Plan [Member] | Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	49.00%
ARHI | Other Postretirement Benefit Plan [Member] | Other Investment Types [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	3.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Equity Securities [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	46.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Equity Securities [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	66.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Fixed Income [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	30.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Fixed Income [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	31.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Other Investment Types [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	3.00%
AVANGRID Networks [Member] | Other Postretirement Benefit Plan [Member] | Other Investment Types [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	23.00%

Post-Retirement and Similar 117

Post-Retirement and Similar Obligations - Schedule of Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans (Detail) - Networks and ARHI [Member] - Pension Plan [Member] - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Defined Benefit Plan Disclosure [Line Items]
PBO in excess of plan assets, Projected benefit obligation	$ 3,593	$ 3,448
PBO in excess of plan assets, Fair value of plan assets	2,865	2,672
ABO in excess of plan assets, Accumulated benefit obligation	3,363	3,214
ABO in excess of plan assets, Fair value of plan assets	$ 2,865	$ 2,672

Post-Retirement and Similar 118

Post-Retirement and Similar Obligations - Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations Recognized (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Net Periodic Benefit Cost:
Service cost	$ 42	$ 44	$ 36
Interest cost	137	140	97
Expected return on plan assets	(195)	(199)	(156)
Amortization of prior service cost (benefit)	2	2	3
Amortization of net loss	126	123	130
Special termination benefit charge			2
Settlement charge			2
Net Periodic Benefit Cost	112	110	114
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlements			(2)
Net loss (gain)	3	(11)	69
Amortization of net loss	(126)	(123)	(130)
Amortization of prior service (cost) benefit	(2)	(2)	(3)
Total Other Changes	(125)	(136)	(66)
Total Recognized	(13)	(26)	48
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Net Periodic Benefit Cost:
Service cost	5	5	4
Interest cost	21	20	15
Expected return on plan assets	(8)	(8)	(7)
Amortization of prior service cost (benefit)	(9)	(9)	(9)
Amortization of net loss	5	8	7
Net Periodic Benefit Cost	14	16	10
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	(5)	(24)	(12)
Amortization of net loss	(5)	(8)	(7)
Current year prior service cost			(1)
Amortization of prior service (cost) benefit	9	9	9
Total Other Changes	(1)	(23)	(11)
Total Recognized	13	(7)	(1)
ARHI | Pension Plan [Member]
Net Periodic Benefit Cost:
Interest cost	2	2	2
Expected return on plan assets	(2)	(2)	(2)
Amortization of net loss	1	1	1
Settlement charge		1
Net Periodic Benefit Cost	1	2	1
Other Changes in plan assets and benefit obligations recognized in OCI:
Net loss (gain)	2		4
Amortization of net loss	(1)	(1)	(1)
Total Other Changes	1	(1)	3
Total Recognized	2	1	4
ARHI | Other Postretirement Benefit Plan [Member]
Net Periodic Benefit Cost:
Service cost			1
Interest cost	1	1	1
Net Periodic Benefit Cost	1	1	2
Other Changes in plan assets and benefit obligations recognized in OCI:
Net loss (gain)	(1)	(2)	(8)
Total Other Changes	$ (1)	(2)	(8)
Total Recognized		$ (1)	$ (6)

Post-Retirement and Similar 119

Post-Retirement and Similar Obligations - Schedule of Amounts Expected to be Amortized from Regulatory Assets or Liabilities and OCI into Net Periodic Benefit Cost (Detail) - Scenario, Forecast [Member] $ in Millions	Dec. 31, 2018USD ($)
Pension Plan [Member] | OCI [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss	$ 1
Regulatory Assets or Liabilities [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss	150
Estimated prior service cost (benefit)	1
Regulatory Assets or Liabilities [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Estimated net loss	5
Estimated prior service cost (benefit)	$ (9)

Post-Retirement and Similar 120

Post-Retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets			7.50%
Rate of compensation increase - Networks			4.10%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.63%	4.12%
Rate of compensation increase	3.50%	3.50%
Discount rate	4.12%	4.12%	3.80%
Expected long-term return on plan assets	7.00%	7.40%
Rate of compensation increase - Networks	3.50%	3.50%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Pension Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.80%	4.24%
Rate of compensation increase	4.20%	4.20%
Discount rate	4.24%	4.24%	4.24%
Expected long-term return on plan assets	7.75%	7.75%
Rate of compensation increase - Networks	4.20%	4.20%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	6.13%	7.16%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Nontaxable Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	6.50%	7.00%	7.50%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Taxable Trust [Member]
Defined Benefit Plan Disclosure [Line Items]
Expected long-term return on plan assets	4.25%	4.50%	5.00%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.63%	4.12%
Discount rate	4.12%	4.12%	3.80%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Other Postretirement Benefit Plan [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.80%	4.24%
Discount rate	4.24%	4.24%	4.24%
ARHI | Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.80%	3.81%
Discount rate	3.81%	3.90%	3.90%
Expected long-term return on plan assets	5.50%	5.50%	5.50%
ARHI | Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Discount rate	3.80%	3.81%
Discount rate	3.81%	3.90%	3.90%
Expected long-term return on plan assets	5.50%	5.50%	5.75%

Post-Retirement and Similar 121

Post-Retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Detail)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
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%
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	6.75%	7.00%
Year that the rate reaches the ultimate trend rate	2,026	2,026
Iberdrola Renewables Holding, Inc. (IRHI) [Member] | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	8.50%	9.00%
Year that the rate reaches the ultimate trend rate	2,028	2,028
ARHI
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
ARHI | Minimum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.50%	6.75%
Year that the rate reaches the ultimate trend rate	2,028	2,026
ARHI | Maximum [Member]
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	8.50%	8.50%
Year that the rate reaches the ultimate trend rate	2,030	2,028

Post-Retirement and Similar 122

Post-Retirement and Similar Obligations - Schedule of Effects of One-Percent Change In Assumed Health Care Cost Trend Rates (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
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	15
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Effect on total of service and interest cost, 1% Decrease	(1)
Effect on postretirement benefit obligation, 1% Decrease	$ (12)

Post-Retirement and Similar 123

Post-Retirement and Similar Obligations - Estimated Future Benefit Payments (Detail) - Improvement and Modernization Act of 2003 [Member] - Networks and ARHI [Member] $ in Millions	Dec. 31, 2017USD ($)
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2,018	$ 234
2,019	215
2,020	218
2,021	221
2,022	225
2023 - 2027	1,122
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
2,018	33
2,019	33
2,020	33
2,021	33
2,022	33
2023 - 2027	165
Medicare Act Subsidy Receipts [Member]
Defined Benefit Plan Disclosure [Line Items]
2023 - 2027	$ 4

Post-Retirement and Similar 124

Post-Retirement and Similar Obligations - Fair Value of Benefits Plan Assets by Asset Category (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 1,734	$ 1,582	[1]
Other investments measured at net asset value	1,131	1,090	[1]
Total	2,865	2,672	[1]
Pension Plan [Member] | Corporate Bond Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	447	358	[1]
Pension Plan [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	129	120	[1]
Pension Plan [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	4	4	[1]
Pension Plan [Member] | Cash and Cash Equivalents [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	18	49	[1]
Pension Plan [Member] | U.S. Government Securities [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	13	172	[1]
Pension Plan [Member] | Registered Investment Companies [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	134	122	[1]
Pension Plan [Member] | Equity Commingled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	436	371	[1]
Pension Plan [Member] | Other, Principally Annuity, Fixed Income [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	553	386	[1]
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	462	414	[1]
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	129	120	[1]
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	13	172	[1]
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	134	122	[1]
Pension Plan [Member] | Fair Value, Inputs, Level 1 [Member] | Equity Commingled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	186
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	1,272	1,168	[1]
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	447	358	[1]
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Preferred Stock [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	4	4	[1]
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	18	49	[1]
Pension Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Equity Commingled Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	250	371	[1]
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	553	386	[1]
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	165	160
Other Postretirement Benefit Plan [Member] | Common Stocks [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	20	23
Other Postretirement Benefit Plan [Member] | Money Market Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	4	6
Other Postretirement Benefit Plan [Member] | Mutual Funds Fixed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	35	41
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	77	72
Other Postretirement Benefit Plan [Member] | Mutual Funds, Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	27	16
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 1 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	128	118
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	20	23
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	35	39
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	50	43
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	19	9
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	37	42
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Money Market Funds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category		2
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Funds Fixed [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category		2
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Government and Corporate Bonds [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	2	2
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Funds Equity
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	27	29
Other Postretirement Benefit Plan [Member] | Fair Value, Inputs, Level 2 [Member] | Mutual Funds, Other [Member]
Defined Benefit Plan Disclosure [Line Items]
Fair value of assets, by asset category	$ 8	$ 7
[1]	Certain amounts in this table have been reclassified to conform to 2017 presentation.

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Dec. 15, 2015	May 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Nov. 30, 2011
Class Of Stock [Line Items]
Common stock, authorized			500,000,000	500,000,000
Common stock, issued			309,670,932	309,600,439	243
Common stock, outstanding	252,235,232		309,005,272	308,993,149
Common stock, par value			$ 0.01	$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 13,653	$ 13,653
Treasury stock, shares			485,810	491,459
Convertible preferred stock, shares outstanding			0	0
Issuance of common stock, shares			70,493	109,357
Release of common stock held in trust			5,649	135,014
Treasury shares of common stock			179,850
Repurchase of common stock, shares		64,019		115,831
Repurchases of common stock			$ 8	$ 5
Common stock issued from stock split	252,234,989
Iberdrola Renewables Holding, Inc [Member]
Class Of Stock [Line Items]
Percentage of equity owned by parent			81.50%	81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		12 Months Ended
		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)		$ 25	$ (26)	$ 33
Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense(benefit)		(26)	(65)	(23)	$ (63)
Accumulated Other Comprehensive (Loss) Income		(46)	(86)	(52)	(99)
Gain on defined benefit plans, net of income taxes			7	4
Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense(benefit)	[1]	14	(16)	7
Net unrealized (loss) gain on derivatives qualifying as cash flow hedges		39	(42)	40
Other comprehensive income, net of tax		40	(34)	47
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Reclassification adjustment for losses on settled cash flow hedges, net of income tax expense(benefit)	[1]	(56)	(70)	(54)	(61)
Designated as Hedging Instrument [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)		30	5	31	(2)
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Loss on defined benefit plans, net of income tax expense (benefit)		(14)	(14)	(21)	(25)
Gain on defined benefit plans, net of income taxes			7	4
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Loss on defined benefit plans, net of income tax expense (benefit)		(6)	(7)	(8)	$ (11)
Gain on defined benefit plans, net of income taxes		$ 1	$ 1	$ 3
[1]	Reclassification is reflected in the operating expenses line item in the consolidated statements of income.

Equity - Accumulated Other C127

Equity - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized (loss) gain during period on derivatives qualified as cash flow hedges, income tax expense (benefit)	$ 15.2	$ (15.8)	$ 20.9
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	9.3	(11)	4.9
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain on defined benefit plans, income tax expense (benefit)		4.3	2.2
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain on defined benefit plans, income tax expense (benefit)	$ 0.2	$ 0.4	$ 1.7

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended								12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Numerator:
Net income attributable to AVANGRID	$ (77)	$ 99	$ 120	$ 239	$ 209	$ 109	$ 101	$ 213	$ 381	$ 632	$ 273
Denominator:
Weighted average number of shares outstanding - basic									309,502,861	309,512,553	254,588,212
Weighted average number of shares outstanding - diluted									309,661,883	309,817,322	254,605,111
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic									$ 1.23	$ 2.04	$ 1.07
Earnings Per Common Share, Diluted									$ 1.23	$ 2.04	$ 1.07

Variable Interest Entities - Ad

Variable Interest Entities - Additional Information (Detail) - USD ($)	1 Months Ended		12 Months Ended
	Nov. 30, 2017	Feb. 28, 2017	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Variable Interest Entity [Line Items]
Accrued interest average rate			8.40%	5.40%
Assets of variable interest entities (VIEs)			$ 1,441,000,000	$ 1,343,000,000
Liabilities of variable interest entities (VIEs)			185,000,000	244,000,000
Equity method investments of variable interest entities (VIEs)			352,000,000	387,000,000	$ 385,000,000
Upfront cash payments			0
Locust Ridge Wind Farm, LLC [Member]
Variable Interest Entity [Line Items]
Acquisition of equity investor's interest		$ 5,000,000
Wind Power III LLC [Member]
Variable Interest Entity [Line Items]
Acquisition of equity investor's interest	$ 15,000,000
Variable Interest Entity, Primary Beneficiary [Member]
Variable Interest Entity [Line Items]
Equity method investments of variable interest entities (VIEs)			$ 107,000,000	$ 161,000,000

Grants, Government Incentive130

Grants, Government Incentives and Deferred Income - Schedule of Changes in Deferred Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016
Deferred Revenue Arrangement [Line Items]
Beginning Balance	$ 1,483	$ 1,553
Additions	35
Reclassified to held for sale	(2)
Recognized in income	(70)	(70)
Ending Balance	1,446	1,483
Government Grants [Member]
Deferred Revenue Arrangement [Line Items]
Beginning Balance	1,461	1,529
Additions	33
Recognized in income	(67)	(68)
Ending Balance	1,427	1,461
Other Deferred Income [Member]
Deferred Revenue Arrangement [Line Items]
Beginning Balance	22	24
Additions	2
Reclassified to held for sale	(2)
Recognized in income	(3)	(2)
Ending Balance	$ 19	$ 22

Grants, Government Incentive131

Grants, Government Incentives and Deferred Income - Additional Information (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Deferred Revenue Disclosure [Abstract]
Deferred other income reclassification to liabilities to held for sale	$ 2,000,000	$ 0

Equity Method Investments - Add

Equity Method Investments - Additional Information (Detail) $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2016USD ($)	Dec. 31, 2017USD ($)PlantJointVentureMW	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)	Dec. 31, 2014
Schedule Of Investments [Line Items]
Equity method investments		$ 352	$ 387	$ 385
OTTI recorded on investment		$ 49
Number of peaking generation plants | Plant		2
Equity method investment, distributions received		$ 20	20	$ 12
Equity method investment, distributions received in RECs		$ 3.5
Vineyard Wind, LLC [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage		50.00%
Equity method investments		$ 10
Nameplate capacity of offshore wind facility | MW		1,600
Network [Member] | New York Transco [Member]
Schedule Of Investments [Line Items]
Equity method investments		$ 23	22
Business combination, equity interest percentage		20.00%			20.00%
Shell Wind Energy Inc [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage		50.00%
Equity method investments		$ 18	45
Horizon Wind Energy LLC [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage		50.00%
Number of joint ventures | JointVenture		2
Flat Rock Wind Power LLC [Member]
Schedule Of Investments [Line Items]
Equity method investments		$ 120	128
Flat Rock Wind Power II LLC [Member]
Schedule Of Investments [Line Items]
Equity method investments		$ 57	64
NRG Energy Inc [Member]
Schedule Of Investments [Line Items]
Joint venture, ownership percentage		50.00%
Equity method investments		$ 124	128
Number of peaking generation plants | Plant		2
Iroquois [Member]
Schedule Of Investments [Line Items]
Equity method investments			22
Proceeds from sale of ownership Interest	$ 53.8		53.8
Net income on disposition of business	$ 19		$ 19

Other Financial Statements I133

Other Financial Statements Items - Schedule of Other Income and (Expense) (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Other Nonoperating Income Expense [Abstract]
Allowance for funds used during construction	$ 36	$ 26	$ 21
Carrying costs on regulatory assets	11	14	28
Other	11	36	7
Total Other Income	$ 58	$ 76	$ 56

Other Financial Statements I134

Other Financial Statements Items - Additional Information (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017
Accounts Notes And Loans Receivable [Line Items]
Gain on sale of investment	$ 33
Other	241	$ 71
Deferred Payment Arrangements [Member]
Accounts Notes And Loans Receivable [Line Items]
Accounts receivable	54	$ 55
Safe Harbor Turbine Payments [Member]
Accounts Notes And Loans Receivable [Line Items]
Other	$ 186

Other Financial Statements I135

Other Financial Statements Items - Schedule of Accounts Receivable (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Receivables [Abstract]
Trade receivables	$ 1,104	$ 1,183
Allowance for bad debts	(64)	(64)	$ (62)	$ (49)
Total Accounts Receivable	$ 1,040	$ 1,119

Other Financial Statements I136

Other Financial Statements Items - Schedule of Change in Allowance For Bad Debts (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Receivables [Abstract]
Beginning balance	$ 64	$ 62	$ 49
Current period provision	69	48	46
Write-off as uncollectible	(69)	(46)	(33)
Ending balance	$ 64	$ 64	$ 62

Other Financial Statements I137

Other Financial Statements Items - Schedule of Prepayments and Other Current Assets (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Receivables [Abstract]
Prepaid other taxes	$ 194	$ 153
Broker margin and collateral accounts	32	32
Loans to third parties	2	3
Fixed-term deposits		3
Other pledged deposits	9	8
Prepaid expenses	33	53
Other	3	3
Total	$ 273	$ 255

Other Financial Statements I138

Other Financial Statements Items - Schedule of Other Current Liabilities (Detail) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Payables And Accruals [Abstract]
Advances received	$ 113	$ 107
Accrued salaries	87	84
Short-term environmental provisions	69	34
Collateral deposits received	43	45
Pension and other postretirement	5	5
Other	13	4
Total	$ 330	$ 279

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)Segment	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	3
Operating Revenues	$ 5,963	$ 6,018	$ 4,367
Regulated Electric Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	3,585	3,686	2,779
Regulated Gas Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	1,375	1,306	605
Other Networks [Member]
Segment Reporting Information [Line Items]
Operating Revenues	(10)	35	2
Renewable Energy Generation Of Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues	1,038	1,000	1,051
Gas Storage Services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	(25)	7	21
Gas Trading Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	$ 1	$ (14)	$ (92)
Network [Member]
Segment Reporting Information [Line Items]
Number of reportable segments | Segment	1
Number of operating segments | Segment	8
Gas [Member]
Segment Reporting Information [Line Items]
Non cash capital contribution to settle outstanding intercompany debt payables	$ 921

Segment information (Detail)

Segment information (Detail) - USD ($) $ in Millions		3 Months Ended								12 Months Ended
		Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenue - external										$ 5,963	$ 6,018	$ 4,367
Impairment										642		12
Depreciation and amortization										824	804	695
Operating income (loss)		$ (425)	$ 189	$ 223	$ 398	$ 306	$ 217	$ 322	$ 349	385	1,194	513
Adjusted EBITDA										1,851	1,998	1,220
Earnings (loss) from equity method investments										(40)	7
Interest expense, net of capitalization										280	268	267
Income tax (benefit) expense										(259)	377	29
Capital expenditures										2,416	1,707	1,082
Property, plant and equipment		22,669				21,548				22,669	21,548	20,711
Equity method investments		352				387				352	387	385
Total assets		31,671				31,309				31,671	31,309	30,743
Operating Segments [Member] | Network [Member]
Segment Reporting Information [Line Items]
Revenue - external										4,950	5,027	3,386
Revenue - intersegment										11	3
Depreciation and amortization										474	466	328
Operating income (loss)										994	1,086	537
Adjusted EBITDA										1,468	1,552	865
Earnings (loss) from equity method investments										15	15	1
Interest expense, net of capitalization										244	252	227
Income tax (benefit) expense										316	415	146
Capital expenditures										1,305	1,140	773
Property, plant and equipment		13,876				13,032				13,876	13,032	12,363
Equity method investments		147				151				147	151	110
Total assets		21,411				20,753				21,411	20,753	20,126
Operating Segments [Member] | Renewables [Member]
Segment Reporting Information [Line Items]
Revenue - external										1,038	1,000	1,051
Revenue - intersegment										9	15	16
Impairment												12
Depreciation and amortization										325	313	344
Operating income (loss)										92	149	100
Adjusted EBITDA										417	462	456
Earnings (loss) from equity method investments										(55)	(8)	(5)
Interest expense, net of capitalization										28	50	54
Income tax (benefit) expense										(320)	7	8
Capital expenditures										1,097	561	304
Property, plant and equipment		8,786				8,015				8,786	8,015	7,835
Equity method investments		205				236				205	236	253
Total assets		11,308				9,884				11,308	9,884	10,685
Operating Segments [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Revenue - external										(26)	(7)	(71)
Revenue - intersegment										41	39	52
Impairment										642
Depreciation and amortization										25	25	23
Operating income (loss)										(701)	(41)	(85)
Adjusted EBITDA										(34)	(16)	(62)
Interest expense, net of capitalization										24	25	31
Income tax (benefit) expense										(212)	(22)	(44)
Capital expenditures										7	6	5
Property, plant and equipment						501					501	513
Total assets		383				1,124				383	1,124	1,265
Corporate and Intercompany Eliminations [Member]
Segment Reporting Information [Line Items]
Revenue - external	[1]									1	(2)	1
Revenue - intersegment	[1]									(61)	(57)	(68)
Operating income (loss)	[1]											(39)
Adjusted EBITDA	[1]											(39)
Earnings (loss) from equity method investments	[1]											4
Interest expense, net of capitalization	[1]									(16)	(59)	(45)
Income tax (benefit) expense	[1]									(43)	(23)	(81)
Capital expenditures	[1]									7
Property, plant and equipment	[1]	7								7
Equity method investments	[1]											22
Total assets	[1]	$ (1,431)				$ (452)				$ (1,431)	$ (452)	$ (1,333)
[1]	Does not represent a segment. It mainly includes Corporate and intercompany eliminations.

Segment information - Reconcili

Segment information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Segment Reporting [Abstract]
Consolidated Adjusted EBITDA	$ 1,851	$ 1,998	$ 1,220
Impairment	642		12
Depreciation and amortization	824	804	695
Interest expense, net of capitalization	280	268	267
Income tax expense	(259)	377	29
Other income	58	76	56
Earnings from equity method investments	(40)	7
Net Income	$ 382	$ 632	$ 273

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Iberdrola Financiacion, S.A. [Member]
Related Party Transaction [Line Items]
Purchases From	$ (2)	$ (2)	$ (1)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Purchases From	(9)	(8)	(9)
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Purchases From	(33)	(37)	(55)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Sales To	1
Purchases From	(36)	(31)	(35)
Iberdrola Energia Monterrey, S.A. de C.V. [Member]
Related Party Transaction [Line Items]
Sales To	46	18
Other Related Parties [Member]
Related Party Transaction [Line Items]
Sales To	1	3	3
Purchases From	$ (1)	$ (1)	$ (2)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Related Party Transaction [Line Items]
Notes payable	$ 29,000,000	$ 10,000,000
Receivable from related party, write-off	69,000,000	46,000,000	$ 33,000,000
Impairments	642,000,000		12,000,000
Equity method investments	352,000,000	387,000,000	385,000,000
Contributions in aid of construction	57,000,000	69,000,000	$ 38,000,000
Deposit balance	0	0
Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Portion of amount receivable from related parties	2,000,000	1,000,000
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Notes payable	29,000,000	10,000,000
Affiliated Entity [Member] | Impairment of non-current assets [Member]
Related Party Transaction [Line Items]
Receivable from related party, write-off	10,000,000
Impairments	$ 0
Iberdrola, S.A. [Member] | Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired	8.10%
Related party transaction, amount	$ 266,000,000	269,000,000
Payments to related party		92,000,000
Network [Member] | New York Transco [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%			20.00%
Increase in equity method investments		21,000,000
Equity method investments	$ 23,000,000	22,000,000
Total cash consideration received		67,000,000
Proceed from contributions in assets transfer		43,000,000
Contributions in aid of construction		22,000,000
Proceed from contributions in advanced lease payment		$ 2,000,000
Lease period of land and attachment right		99 years
Portion of amount receivable from related parties	$ 6,000,000	$ 11,000,000

Related Party Transactions -144

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2017	Dec. 31, 2016
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Owed To	$ (31)	$ (14)
Siemens-Gamesa [Member]
Related Party Transaction [Line Items]
Owed By	2	1
Owed To	(51)	(181)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Owed By	1
Owed To	(32)	(30)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Owed By		2
Iberdrola Energia Monterrey, S.A. de C.V. [Member]
Related Party Transaction [Line Items]
Owed By	1	11
Other Related Parties [Member]
Related Party Transaction [Line Items]
Owed By	6	11
Owed To	$ (4)	$ (3)

Stock-Based Compensation - Addi

Stock-Based Compensation - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended			12 Months Ended
	Oct. 31, 2017shares	Mar. 31, 2017shares	Jul. 31, 2016$ / sharesshares	Dec. 31, 2017USD ($)Installment$ / sharesshares	Dec. 31, 2016USD ($)	Dec. 31, 2015USD ($)
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of shares authorized for stock-based compensation plans | shares				2,500,000
Stock-based compensation expense				$ 1.2	$ 0.6	$ 6
Income tax benefit recognized for stock-based compensation arrangements				0.5	0.2	$ 2.4
Stock-based compensation other non-current liabilities				$ 5.5	$ 9.5
Iberdrola [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Employee related remaining liabilities settlement date				2018-03
Performance Shares Units [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of PSUs granted | shares				94,509
Share-based payment award options grant date fair value, per share | $ / shares				$ 32.89
Unrecognized cost for non-vested PSUs				$ 5.1
Recognition of PSU costs, weighted-average period				4 years
Performance Shares Units [Member] | Officers and Employees [Member]
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of PSUs granted | shares	85,759	85,759	1,298,683
Number of installment payments of employee related payables | Installment				3
Share-based payment award options grant date fair value, per share | $ / shares			$ 31.80
Share-based payment award options requisite service period				7 years
Share-based Compensation Award, Tranche One
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance stock units vested amount installment payment year				2,020
Share-based Compensation Award, Tranche Two
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance stock units vested amount installment payment year				2,021
Share-based Compensation Award, Tranche Three
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Performance stock units vested amount installment payment year				2,022

Stock-Based Compensation - Summ

Stock-Based Compensation - Summary of Nonvested PSUs (Detail) - Performance Shares Units [Member]	12 Months Ended
	Dec. 31, 2017$ / sharesshares
Share Based Compensation Arrangement By Share Based Payment Award [Line Items]
Number of PSUs, Nonvested Balance – December 31, 2016 | shares	1,523,981
Number of PSUs granted | shares	94,509
Number of PSUs, Forfeited | shares	(113,256)
Number of PSUs, Vested | shares	(120,975)
Number of PSUs, Nonvested Balance – December 31, 2017 | shares	1,384,259
Weighted Average Grant Date Fair Value, Nonvested Balance – December 31, 2016 | $ / shares	$ 33.01
Weighted Average Grant Date Fair Value, Granted | $ / shares	32.89
Weighted Average Grant Date Fair Value, Forfeited | $ / shares	31.91
Weighted Average Grant Date Fair Value, Vested | $ / shares	40.07
Weighted Average Grant Date Fair Value, Nonvested Balance – December 31, 2017 | $ / shares	$ 32.57

Assets Held for Sale - Addition

Assets Held for Sale - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Dec. 31, 2018	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015	Mar. 01, 2018	Feb. 16, 2018
Assets Held For Sale Not Discontinued Operations [Line Items]
Loss before income tax, adjusted to corporate overhead				$ 123	$ 1,009	$ 302
Enstor Energy Services, LLC [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets and liabilities held for sale completion period	12 months			12 months
Disposal date				Mar. 1, 2018
Enstor Gas, LLC [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Definitive agreement date				Feb. 16, 2018
Description of disposal date				second quarter of 2018
Gas Trading Business [Member] | Enstor Energy Services, LLC [Member] | Subsequent Event [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale, consideration receivable							$ 64.5
Gas Trading and Storage Businesses [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Loss on assets held for sale	$ 642	$ 642
Loss before income tax, adjusted to corporate overhead				$ 715	$ 58	$ 108
Gas Storage Business [Member] | Enstor Gas, LLC [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Change in estimated fair value of assets held for sale				$ 11
Gas Storage Business [Member] | Enstor Gas, LLC [Member] | Scenario, Forecast [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Expected after tax loss			$ 8.1
Gas Storage Business [Member] | Enstor Gas, LLC [Member] | Subsequent Event [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale, consideration receivable								$ 75

Assets Held for Sale - Summary

Assets Held for Sale - Summary of Current Assets and Current Liabilities Held for Sale (Detail) - USD ($)	Dec. 31, 2017	Dec. 31, 2016
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale	$ 357,000,000
Liabilities held for sale	137,000,000
Assets Held for Sale, Not Discontinued Operations [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Derivative assets		$ 0
Assets Held for Sale, Not Discontinued Operations [Member] | Gas Trading and Storage Businesses [Member]
Assets Held For Sale Not Discontinued Operations [Line Items]
Accounts receivable, net	137,000,000
Derivative assets	25,000,000
Fuel and gas in storage	77,000,000
Prepayments and other current assets	19,000,000
Property, plant and equipment	71,000,000
Intangible assets	28,000,000
Assets held for sale	357,000,000
Accounts payable and accrued liabilities	107,000,000
Derivative liabilities	14,000,000
Other liabilities	16,000,000
Liabilities held for sale	$ 137,000,000

Restructuring and Severance 149

Restructuring and Severance Related Expenses - Additional Information (Detail) $ in Millions	12 Months Ended
	Dec. 31, 2017USD ($)
Restructuring And Related Cost [Line Items]
Severance agreement description	The remaining costs for severance agreements are being accrued ratably over the service periods, which span intermittent periods through December 2018.
Operations and Maintenance [Member]
Restructuring And Related Cost [Line Items]
Severance expenses	$ 15.2
Lease termination expenses	4
Depreciation and Amortization [Member]
Restructuring And Related Cost [Line Items]
Accelerated amortization of leasehold improvements	$ 1.2

Restructuring and Severance 150

Restructuring and Severance Related Expenses - Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities and Other Liabilities (Detail) - USD ($) $ in Millions	3 Months Ended		12 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Dec. 31, 2017
Restructuring And Related Activities [Abstract]
Restructuring and severance related expenses	$ 17.1	$ 2.1	$ 19
Payments			(14)
Ending Balance	$ 5		$ 5

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, 2017		Sep. 30, 2017		Jun. 30, 2017		Mar. 31, 2017		Dec. 31, 2016		Sep. 30, 2016		Jun. 30, 2016		Mar. 31, 2016		Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Quarterly Financial Information Disclosure [Abstract]
Operating revenues	$ 1,533		$ 1,341		$ 1,331		$ 1,758		$ 1,491		$ 1,418		$ 1,439		$ 1,670
Operating Income	(425)		189		223		398		306		217		322		349		$ 385	$ 1,194	$ 513
Net Income	(77)		100		120		239		209		109		101		213		382	632	273
Net Income attributable to Avangrid, Inc.	$ (77)		$ 99		$ 120		$ 239		$ 209		$ 109		$ 101		$ 213		$ 381	$ 632	$ 273
Earnings Per Common Share, Basic and Diluted:	$ (0.25)	[1]	$ 0.32	[1]	$ 0.39	[1]	$ 0.77	[1]	$ 0.67	[1]	$ 0.35	[1]	$ 0.33	[1]	$ 0.69	[1]		$ 2.04	$ 1.07
[1]	Based on weighted average number of 309.5 million and 309.8 million shares outstanding each quarter in 2017 and 2016 for basic and diluted earnings per share, respectively

Schedule of Quarterly Financ152

Schedule of Quarterly Financial Data (unaudited) (Parenthetical) (Detail) - shares shares in Millions	3 Months Ended
	Dec. 31, 2017	Sep. 30, 2017	Jun. 30, 2017	Mar. 31, 2017	Dec. 31, 2016	Sep. 30, 2016	Jun. 30, 2016	Mar. 31, 2016
Quarterly Financial Information Disclosure [Abstract]
Weighted average shares outstanding	309.5	309.5	309.5	309.5	309.8	309.8	309.8	309.8

Quarterly Financial Data (un153

Quarterly Financial Data (unaudited) - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	3 Months Ended					12 Months Ended
	Dec. 31, 2017	Dec. 31, 2017	Sep. 30, 2017	Mar. 31, 2017	Jun. 30, 2016	Mar. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Selected Quarterly Financial Information [Line Items]
Severance and lease restructuring charges		$ 17.1	$ 2.1				$ 19
Unfunded future income tax expense				$ 14	$ 126			$ 126
Measurement of deferred income tax balances result of Tax Act		328
Gas Trading and Storage Businesses [Member]
Selected Quarterly Financial Information [Line Items]
Loss on assets held for sale	$ 642	642
Loss on assets held for sale, after income taxes		$ 463
Iroquois [Member]
Selected Quarterly Financial Information [Line Items]
Proceeds from sale of ownership Interest						$ 53.8		53.8
Net income on disposition of business						$ 19		$ 19

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) - $ / shares	Feb. 15, 2018	Dec. 31, 2017	Dec. 31, 2016	Mar. 08, 2018	Nov. 30, 2011
Subsequent Event [Line Items]
Quarterly dividend payable, per share		$ 1.728	$ 1.728
Common stock, issued		309,670,932	309,600,439		243
Common stock, par value		$ 0.01	$ 0.01
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividend declared date	Feb. 15, 2018
Quarterly dividend payable, per share	$ 0.432
Dividend payment date	Apr. 2, 2018
Dividend record date	Mar. 9, 2018
Common stock, issued				81,208
Common stock, par value				$ 0.01

Acquisition of UIL and Issua155

Acquisition of UIL and Issuance of Common Stock - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Feb. 15, 2018	Dec. 16, 2015	May 31, 2017	Dec. 31, 2017	Dec. 31, 2016	Mar. 08, 2018
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
Treasury stock, shares				485,810	491,459
Convertible preferred stock, shares outstanding				0	0
Issuance of common stock, shares				70,493	109,357
Release of common stock held in trust				5,649	135,014
Treasury shares of common stock				179,850
Repurchase of common stock, shares			64,019		115,831
Repurchases of common stock				$ 8	$ 5
Subsequent Event [Member]
Business Acquisition [Line Items]
Common stock, par value						$ 0.01
Dividend declared date	Feb. 15, 2018
Dividend payment date	Apr. 2, 2018
Dividend record date	Mar. 9, 2018
Avangrid, Inc [Member]
Business Acquisition [Line Items]
Common stock, par value				$ 0.01	$ 0.01
Treasury stock, shares				485,810	491,459
Convertible preferred stock, shares outstanding				0	0
Issuance of common stock, shares				70,493	109,357
Release of common stock held in trust				5,649	135,014
Treasury shares of common stock				179,850
Repurchase of common stock, shares			64,019		115,831
Repurchases of common stock				$ 8	$ 5
Avangrid, Inc [Member] | Subsequent Event [Member]
Business Acquisition [Line Items]
Dividend declared date	Feb. 15, 2018
Quarterly dividend payable, per share	$ 0.432
Dividend payment date	Apr. 2, 2018
Dividend record date	Mar. 9, 2018
Avangrid, Inc [Member] | UIL Holdings [Member]
Business Acquisition [Line Items]
Effective date of business acquisition of UIL Holdings				Feb. 25, 2015
Issuance of share in connection of acquisition				In connection with the acquisition, AVANGRID issued 309,490,839 shares of its common stock, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share, and 57,255,850 shares (including held in trust as treasury stock) were issued to UIL shareowners in addition to payment of $10.50 in cash per each share of the common stock of UIL issued and outstanding at the acquisition date.
Shares issued in connection with acquisition		309,490,839
Business acquisition, share price		$ 10.50
Percentage of ownership		18.50%
Common stock, par value		$ 0.01
Avangrid, Inc [Member] | UIL Holdings [Member] | UIL shareowners [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition		57,255,850
Avangrid, Inc [Member] | UIL Holdings [Member] | Iberdrola, S.A. [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition		252,234,989
Iberdrola Renewables Holding, Inc [Member]
Business Acquisition [Line Items]
Percentage of equity owned by parent				81.50%

Non-current Debt - Additional I

Non-current Debt - Additional Information (Detail) - USD ($) $ in Millions	Nov. 21, 2017	Dec. 19, 2016	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Debt Instrument [Line Items]
Non-current note issuance				$ 888	$ 493	$ 350
UIL, and The Bank of New York Mellon [Member]
Debt Instrument [Line Items]
Debt instrument principal amount		$ 450
Debt instrument, interest rate		4.625%
Debt instrument maturity year		2,020
Capital contribution to subsidiary by parent			$ 483
Avangrid, Inc [Member]
Debt Instrument [Line Items]
Non-current note issuance				$ 594	$ 483
Avangrid, Inc [Member] | 3.150% Notes due 2024 [Member]
Debt Instrument [Line Items]
Debt instrument principal amount	$ 600
Debt instrument, interest rate	3.15%
Debt instrument maturity year	2,024
Non-current note issuance	$ 594

Cash Dividends Paid by Subsi157

Cash Dividends Paid by Subsidiaries (Detail) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2017	Dec. 31, 2016	Dec. 31, 2015
Cash Dividend [Line Items]
Cash dividends paid	$ 308	$ 420	$ 1,111
AVANGRID Networks [Member]
Cash Dividend [Line Items]
Cash dividends paid	$ 308	220	59
AVANGRID Renewables [Member]
Cash Dividend [Line Items]
Cash dividends paid		$ 200	750
Other AVANGRID subsidiaries [Member]
Cash Dividend [Line Items]
Cash dividends paid			$ 302

Cash Dividends Paid by Subsi158

Cash Dividends Paid by Subsidiaries - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended	12 Months Ended
	Dec. 31, 2016	Dec. 31, 2017	Dec. 31, 2016
Avangrid, Inc [Member]
Cash Dividend [Line Items]
Non cash contribution/dividend recorded by parent company		$ 1,318	$ (827)
Central Maine Power Company [Member]
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 50