Avangrid (AGR) 10-Q 2 Nov 18 2018 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2018	Oct. 31, 2018
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2018
Document Fiscal Year Focus	2,018
Document Fiscal Period Focus	Q3
Trading Symbol	AGR
Entity Registrant Name	Avangrid, Inc.
Entity Central Index Key	1,634,997
Current Fiscal Year End Date	--12-31
Entity Filer Category	Large Accelerated Filer
Entity Emerging Growth Company	false
Entity Small Business	false
Entity Common Stock, Shares Outstanding (in shares)		309,005,272

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Statement [Abstract]
Operating Revenues	$ 1,546	$ 1,341	$ 4,813	$ 4,430
Operating Expenses
Purchased power, natural gas and fuel used	342	250	1,197	957
Loss from assets held for sale	1	0	16	0
Operations and maintenance	574	531	1,634	1,546
Depreciation and amortization	226	205	644	608
Taxes other than income taxes, net	150	137	444	422
Total Operating Expenses	1,293	1,123	3,935	3,533
Operating Income	253	218	878	897
Other Income and (Expense)
Other expense	(16)	(15)	(57)	(52)
Earnings from equity method investments	1	0	8	3
Interest expense, net of capitalization	(75)	(71)	(219)	(210)
Income Before Income Tax	163	132	610	638
Income tax expense	29	32	128	179
Net Income	134	100	482	459
Less: Net income attributable to noncontrolling interests	9	1	6	1
Net Income Attributable to Avangrid, Inc.	$ 125	$ 99	$ 476	$ 458
Earnings Per Common Share, Basic (in usd per share)	$ 0.40	$ 0.32	$ 1.54	$ 1.48
Earnings Per Common Share, Diluted (in usd per share)	$ 0.40	$ 0.32	$ 1.54	$ 1.48
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	309,491,082	309,491,082	309,507,443	309,506,831
Diluted (in shares)	309,689,890	309,801,903	309,705,788	309,785,639

Condensed Consolidated Statem_2

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Net Income	$ 134	$ 100	$ 482	$ 459
Other Comprehensive Income (Loss), Net of Tax
Gain on defined benefit plans, net of income taxes of $0.2 for the nine months ended	0	0	1	0
Unrealized gain during the period on derivatives qualifying as cash flow hedges, net of income tax of $1.5 and $3.0 for the three months ended and $4.1 for the nine months ended, respectively	5	5	0	7
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes of $0.4 and $1.3 for the three months ended and $(6.8) and $14.8, for the nine months ended, respectively	1	3	(9)	25
Total Other Comprehensive Income (Loss), Net of Tax	6	8	(8)	32
Comprehensive Income	140	108	474	491
Less: Net income attributable to noncontrolling interests	9	1	6	1
Comprehensive Income Attributable to Avangrid, Inc.	$ 131	$ 107	$ 468	$ 490

Condensed Consolidated Statem_3

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, income tax expense (benefit)	$ 0	$ 0	$ 0.2	$ 0
Unrealized (loss) gain during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	1.5	3	0	4.1
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	$ 0.4	$ 1.3	$ (6.8)	$ 14.8

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Current Assets
Cash and cash equivalents	$ 32	$ 41
Accounts receivable and unbilled revenues, net	1,060	1,040
Accounts receivable from affiliates	3	10
Derivative assets	22	18
Fuel and gas in storage	116	99
Materials and supplies	127	115
Prepayments and other current assets	319	273
Assets held for sale	0	357
Regulatory assets	284	307
Total Current Assets	1,963	2,260
Total Property, Plant and Equipment ($1,261 and $1,303 related to VIEs, respectively)	23,125	22,669
Equity method investments	351	352
Other investments	64	63
Regulatory assets	2,591	2,738
Deferred income taxes regulatory	44	0
Other Assets
Goodwill	3,127	3,127
Intangible assets	326	328
Derivative assets	59	63
Other	105	71
Total Other Assets	3,617	3,589
Total Assets	31,755	31,671
Current Liabilities
Current portion of debt	523	183
Tax equity financing arrangements - VIEs	0	38
Notes payable	500	757
Notes payable to affiliates	0	29
Interest accrued	67	57
Accounts payable and accrued liabilities	1,008	1,071
Accounts payable to affiliates	60	89
Dividends payable	136	134
Taxes accrued	74	89
Derivative liabilities	24	22
Liabilities held for sale	0	137
Other current liabilities	325	330
Regulatory liabilities	194	178
Total Current Liabilities	2,911	3,114
Regulatory liabilities	3,285	3,239
Deferred income taxes regulatory	0	13
Other Non-current Liabilities
Deferred income taxes	1,572	1,452
Deferred income	1,398	1,446
Pension and other postretirement	998	1,049
Tax equity financing arrangements - VIEs	0	60
Derivative liabilities	95	92
Asset retirement obligations	211	196
Environmental remediation costs	333	358
Other	401	360
Total Other Non-current Liabilities	5,008	5,013
Non-current Debt	5,096	5,196
Total Non-current Liabilities	13,389	13,461
Total Liabilities	16,300	16,575
Commitments and Contingencies
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,752,140 and 309,670,932 shares issued; 309,005,272 shares outstanding, respectively	3	3
Additional paid in capital	13,656	13,653
Treasury Stock	(12)	(8)
Retained earnings	1,536	1,475
Accumulated other comprehensive loss	(55)	(46)
Total Stockholders’ Equity	15,128	15,077
Non-controlling interests	327	19
Total Equity	15,455	15,096
Total Liabilities and Equity	$ 31,755	$ 31,671

Condensed Consolidated Balanc_2

Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Property, Plant and Equipment, VIEs	$ 23,125	$ 22,669
Common stock, par value (in usd per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	500,000,000	500,000,000
Common stock, issued (in shares)	309,752,140	309,670,932
Common stock, outstanding (in shares)	309,005,272	309,005,272
Variable Interest Entity, Primary Beneficiary
Property, Plant and Equipment, VIEs	$ 1,261	$ 1,303

Condensed Consolidated Statem_4

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Cash Flow from Operating Activities:
Net Income	$ 134	$ 100	$ 482	$ 459
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization			644	608
Loss from assets held for sale	1	0	16	0
Accretion expenses			10	8
Regulatory assets/liabilities amortization and carrying cost			54	50
Pension cost			93	84
Earnings from equity method investments	(1)	0	(8)	(3)
Unrealized loss (gain) on marked-to-market derivative contracts			6	(13)
Deferred taxes			130	166
Other non-cash items			(42)	(46)
Changes in operating assets and liabilities:
Accounts receivable and unbilled revenues			2	179
Inventories			(23)	(33)
Other assets/liabilities			(61)	(96)
Cash distribution from equity method investments			10	11
Accounts payable and accrued liabilities			(36)	(105)
Taxes accrued			22	10
Regulatory assets/liabilities			18	43
Net Cash Provided by Operating Activities			1,317	1,322
Cash Flow from Investing Activities:
Capital expenditures			(1,173)	(1,704)
Contributions in aid of construction			36	31
Proceeds from sale of assets			132	9
Cash distribution from equity method investments			4	4
Other investments and equity method investments, net			(32)	(7)
Net Cash Used in Investing Activities			(1,033)	(1,667)
Cash Flow from Financing Activities:
Non-current note issuances			324	294
Repayments of non-current debt			(65)	(65)
(Repayments) receipts of other short-term debt, net			(288)	570
Payments on tax equity financing arrangements			0	(84)
Repayments of capital leases			(13)	(32)
Repurchases of common stock			(4)	(3)
Issuances of common stock			(2)	(1)
Distributions to noncontrolling interests			(60)	0
Distributions to noncontrolling interests			219	5
Dividends paid			(401)	(401)
Net Cash (Used in) Provided by Financing Activities			(290)	283
Net Decrease in Cash, Cash Equivalents and Restricted Cash			(6)	(62)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period			46	96	$ 96
Cash, Cash Equivalents and Restricted Cash, End of Period	$ 40	$ 34	40	34	$ 46
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized			159	144
Cash (refund)/paid for income taxes			$ (11)	$ 9

Condensed Consolidated Statem_5

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions		Total	Total Stockholders’ Equity	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Non controlling Interests
Balance, beginning of period at Dec. 31, 2016		$ 15,208	$ 15,195	$ 3		$ 13,653	$ (5)	$ 1,630	$ (86)	$ 13
Balance, beginning of period (in shares) at Dec. 31, 2016	[1]			308,993,149
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		459	458					458		1
Other comprehensive income (loss), net of tax		32	32						32
Comprehensive Income		491
Dividends declared		$ (401)	(401)					(401)
Release of common stock held in trust (in shares)		5,649		5,649	[1]
Issuances of common stock		$ (1)	(1)			(1)
Issuances of common stock (in shares)		70,493		70,493	[1]
Repurchases of common stock		$ (3)	(3)				(3)
Repurchases of common stock (in shares)	[1]			(64,019)
Stock-based compensation		4	4			4
Contributions from noncontrolling interests		5	4					4		1
Balance, end of period at Sep. 30, 2017		15,303	15,288	$ 3		13,656	(8)	1,691	(54)	15
Balance, end of period (in shares) at Sep. 30, 2017	[1],[2]			309,005,272
Balance, beginning of period at Jun. 30, 2017		15,327	15,313	$ 3		13,655	(8)	1,725	(62)	14
Balance, beginning of period (in shares) at Jun. 30, 2017	[2]			309,005,272
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		100	99					99		1
Other comprehensive income (loss), net of tax		8	8						8
Comprehensive Income		108
Dividends declared		(133)	(133)					(133)
Stock-based compensation		1	1			1
Balance, end of period at Sep. 30, 2017		15,303	15,288	$ 3		13,656	(8)	1,691	(54)	15
Balance, end of period (in shares) at Sep. 30, 2017	[1],[2]			309,005,272
Balance, beginning of period at Dec. 31, 2017		$ 15,096	15,077	$ 3		13,653	(8)	1,475	(46)	19
Balance, beginning of period (in shares) at Dec. 31, 2017		309,005,272		309,005,272	[1]
Adoption of accounting standards at Dec. 31, 2017		$ 136	(4)					(3)	(1)	140
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		482	476					476		6
Other comprehensive income (loss), net of tax		(8)	(8)						(8)
Comprehensive Income		474
Dividends declared		$ (404)	(404)					(404)
Release of common stock held in trust (in shares)		0
Issuances of common stock		$ (2)	(2)			1		(3)
Issuances of common stock (in shares)		81,208		81,208	[1]
Repurchases of common stock		$ (4)	(4)				(4)
Repurchases of common stock (in shares)	[1]			(81,208)
Stock-based compensation		2	2			2
Distributions to noncontrolling interests		(60)								(60)
Contributions from noncontrolling interests		217	(5)					(5)		222
Balance, end of period at Sep. 30, 2018		$ 15,455	15,128	$ 3		13,656	(12)	1,536	(55)	327
Balance, end of period (in shares) at Sep. 30, 2018		309,005,272		309,005,272	[1],[2]
Balance, beginning of period at Jun. 30, 2018		$ 15,468	15,135	$ 3		13,655	(12)	1,550	(61)	333
Balance, beginning of period (in shares) at Jun. 30, 2018	[2]			309,005,272
Adoption of accounting standards at Jun. 30, 2018		0
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net Income		134	125					125		9
Other comprehensive income (loss), net of tax		6	6						6
Comprehensive Income		140
Dividends declared		$ (137)	(137)					(137)
Issuances of common stock (in shares)		0
Stock-based compensation		$ 1	1			1
Distributions to noncontrolling interests		(19)								(19)
Contributions from noncontrolling interests		2	(2)					(2)		4
Balance, end of period at Sep. 30, 2018		$ 15,455	$ 15,128	$ 3		$ 13,656	$ (12)	$ 1,536	$ (55)	$ 327
Balance, end of period (in shares) at Sep. 30, 2018		309,005,272		309,005,272	[1],[2]
[1]	(*) Par value of share amounts is $0.01
[2]	(*) Par value of share amounts is $0.01

Condensed Consolidated Statem_6

Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Statement of Stockholders' Equity [Abstract]
Common stock, par value (in usd per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Other comprehensive income (loss) taxes	$ 1.9	$ 4.3	$ (6.6)	$ 18.9
Dividends declared (in usd per share)	$ 0.44	$ 0.432	$ 1.304	$ 1.296

Background and Nature of Operat

Background and Nature of Operations	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Background and Nature of Operations	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 business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. In December 2017, management committed to a plan to sell the gas storage and trading businesses because they represented non-core businesses that were not aligned with our strategic objectives. At that time, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. On March 1, 2018 , the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC (CCI). On May 1, 2018 , the Company closed a transaction to sell Enstor Gas, LLC, which operated AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of Presentation The accompanying notes should be read in conjunction with the notes to the consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2017 and 2016 and for the three years ended December 31, 2017 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2017 . The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. Intercompany accounts and transactions have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements. We believe the disclosures made are adequate to make the information presented not misleading. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated balance sheets, condensed consolidated statements of income, comprehensive income, cash flows and changes in equity for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and nine months ended September 30, 2018 , are not necessarily indicative of the results for the entire fiscal year ending December 31, 2018.

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Significant Accounting Policies and New Accounting Pronouncements	Significant Accounting Policies and New Accounting Pronouncements As of September 30, 2018 , the new accounting pronouncements that we have adopted as of January 1, 2018, and reflected in our consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2017 and 2016, and for the three years ended December 31, 2017 . Adoption of New Accounting Pronouncements (a) Revenue from contracts with customers In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC), Topic 606, Revenue from Contracts with Customers (ASC 606) replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The FASB further amended ASC 606 through various updates issued thereafter. The core principle is for an entity to recognize revenue to represent the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted ASC 606 effective January 1, 2018, and applied the modified retrospective method, for which we did not have a cumulative effect adjustment to retained earnings for initial application of the guidance. Refer to Note 4 for further details. (b) Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets The FASB issued amendments in February 2017 concerning asset derecognition and partial sales of nonfinancial assets. The amendments clarify the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets, and also define in-substance nonfinancial assets. Those amendments apply to a company that: sells nonfinancial assets (land, buildings, materials and supplies, intangible assets) to noncustomers; sells nonfinancial assets and financial assets (cash, receivables) when the value is concentrated in the nonfinancial assets; or sells partial ownership interests in nonfinancial assets. The amendments do not apply to sales to customers or to sales of businesses. The new guidance in ASC 610-20 on accounting for derecognition of a nonfinancial asset and an in-substance nonfinancial asset applies only when the asset (or asset group) does not meet the definition of a business and is not a not-for-profit activity. An entity must apply the amendments at the same time that it applies the new ASC 606 revenue recognition standard. We adopted ASC 610-20 effective January 1, 2018, and applied the modified retrospective method, which affected the accounting for our tax equity investments. As shown in the table below, we recorded a cumulative adjustment that decreased retained earnings. The cumulative adjustment relates to the reclassification of our tax equity investments to noncontrolling interests. As a result, we recorded our tax equity investments based on the Hypothetical Liquidation at Book Value (HLBV) accounting method and we will record changes in the HLBV at each reporting period within net income/loss attributable to noncontrolling interests. The cumulative effects of the changes to our consolidated balance sheet as of January 1, 2018, for our adoption of ASC 606 and ASC 610-20 were as follows: Balance Sheet Balance at December 31, 2017 Adjustments Due to ASC 606 Adjustments Due to ASC 610-20 Balance at (Millions) Liabilities Tax equity financing arrangements - VIEs $ 98 $ — $ (98 ) $ — Deferred income taxes 1,452 — (40 ) 1,412 Equity Retained earnings 1,475 — (2 ) 1,473 Non-controlling interests $ 19 $ — $ 140 $ 159 We also adopted the following standards as of their effective date of January 1, 2018, none of which had a material effect on our consolidated results of operations, financial position, cash flows, and disclosures. (c) Classifying and measuring financial instruments In January 2016, the FASB issued final guidance on the classification and measurement of financial instruments. As a result of our adoption we reclassified immaterial amounts from AOCI to retained earnings. (d) Certain classifications in the statement of cash flows In August 2016, the FASB issued amendments to address existing diversity in practice concerning the classification of certain cash receipts and payments on the statement of cash flows, which must be applied on a full retrospective basis. Upon adoption, we had no changes to our cash flow classifications and disclosures in our consolidated financial statements. (e) Improving the presentation of net periodic benefit costs In March 2017, the FASB issued amendments to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost in the financial statements. We retrospectively adopted the amendments that require us to present the service cost component separately from the other (non-service) components of net benefit cost, to report the service cost component in the income statement line item where we report the corresponding compensation cost, and to present all non-service components outside of operating cost. As a result, we have reclassified the non-service components – interest cost, expected return on plan assets, amortization of prior service cost (benefit), amortization of net loss, and settlement charge – from Operations and maintenance to Other income/(expense) within the statement of income. Prospectively, from adoption, we will capitalize only the service cost component when applicable (for example, as a cost of a self-constructed asset). We elected to apply the practical expedient that allows us to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in our notes to financial statements for Post-retirement and Similar Obligations as the basis for those periods. In addition to those amounts, we included amortization of net benefit costs recorded as regulatory deferrals as a result of purchase accounting in a prior year. In connection with applying the practical expedient, in periods after adoption we will continue to include in operating income all legacy net benefit costs previously capitalized as a cost of self-constructed assets and other deferred regulatory costs. Our adoption of the amendments did not affect prior period net income attributable to AVANGRID. Beginning in 2018, non-service cost components incurred by the Networks utilities are no longer eligible for construction capitalization, but such costs can be deferred and included as a component of customer rates if permitted by their regulator. For the three and nine months ended September 30, 2018 , immaterial additional expense has been incurred as a result of the adoption of this standard. The effect of the change in retrospective presentation related to the net periodic cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated statement of income was as follows: Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Statement of Income As Revised As Previously Reported Effect of Change Higher / (Lower) As Revised As Previously Reported Effect of Change Higher / (Lower) (Millions) Operations and maintenance $ 531 $ 560 $ (29 ) $ 1,546 $ 1,633 $ (87 ) Other income / (expense) $ (15 ) $ 14 $ (29 ) $ (52 ) $ 35 $ (87 ) We have also revised the segment information related to our Networks reportable segment provided in Note 13 for the three and nine months ended September 30, 2017 , to reflect the change as a result of the adoption of these amendments. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements issued since December 31, 2017 , that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) Leases, amendments and updates In January 2018, the FASB issued amendments to clarify the application of the new leases guidance to land easements (also commonly called rights of way) and provide relief concerning adoption efforts for existing land easements that are not accounted for as leases under current GAAP. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We are still assessing our election of the land easement practical expedient, which could materially affect our financial position if we do not elect it, primarily because of the volume of existing land contacts not accounted for as leases under current GAAP. In July 2018, the FASB issued a number of technical corrections and improvements to the new leases guidance, which affect narrow aspects of the guidance and are effective as noted above. We continue to assess the corrections and improvements, but do not expect they will have a significant effect upon adoption. Also, in July 2018 the FASB issued amendments to the leases standard to allow entities an additional option for transition. The guidance currently requires a modified retrospective transition method of adoption, under which lessees and lessors are to recognize and measure leases at the beginning of the earliest comparative period presented. The additional, optional transition method allows an entity to initially apply the requirements of the leases standard at the adoption date. If an entity adopts the optional transition method, it would not restate amounts reported for comparative periods presented in the consolidated financial statements, and not provide disclosures required under the new standard for dates and periods before January 1, 2019. We continue to assess the additional transition option to decide which method to adopt based on the outcome of our implementation plan and steps, described below. We continue to review our contracts and continue to execute a broad implementation plan as we prepare for our adoption of the new leases guidance on January 1, 2019. The key components of our implementation plan and steps that have been underway include: 1) uploading complete and pertinent lease contract data into a new accounting system that integrates with existing systems; 2) identifying, evaluating and documenting related technical accounting issues, industry implementation issues, policy considerations and financial reporting implications; 3) identifying and implementing changes to processes and controls to ensure all aspects of the new guidance are effectively addressed; and 4) simulating the effects of the leases standard to assess the expected impact upon adoption and to finalize transition option and practical expedient selections. Through September 2018, we have substantially completed step 1; including our final reviews of information and lease contract data uploaded in the new accounting system database, and validating the simulation and outputs from the new lease accounting system. We have also completed preliminary system configuration and testing is in process, which has allowed us to simulate our lease contracts under the new lease standard using different assumptions with practical expedients and transition options to make appropriate decisions upon adoption. In other respects, we continue to make progress with Steps 2 through 4 and plan to complete them in the fourth quarter of 2018. We expect an increase in assets, the corresponding liabilities and additional disclosures as a result of our adoption of the new leases guidance. However, we do not expect significant changes to our pattern of expense recognition. Also, we do not expect a significant change in our leasing activities between now and adoption. (b) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018, the FASB issued amendments to address a narrow-scope financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) enacted on December 22, 2017, by the U.S. federal government. Under current guidance, the adjustment of deferred taxes for the effect of a change in tax laws or rates is required to be included in income from continuing operations, thus the associated tax effects of items within accumulated OCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. The amendments allow a reclassification from accumulated OCI 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 accumulated OCI to earnings (specific identification or portfolio method). We have not early adopted the amendments as of September 30, 2018 . We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows and disclosures. (c) Changes to the disclosure requirements for fair value measurement and defined benefit plans In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans. The amendments concerning fair value measurement remove, modify and add certain disclosure requirements, in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. The amendments to fair value measurement disclosures are effective for all entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted as specified. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively. We have not early adopted the amendments as of September 30, 2018. We do not expect our adoption of the amendments to materially affect our disclosures. The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. They remove disclosures that are no longer considered cost beneficial, add certain new relevant disclosures and clarify specific requirements of disclosures concerning information for defined benefit pension plans. The amendments to defined benefit plan disclosures are effective for fiscal years ending after December 15, 2020. Early adoption is permitted and application is to be on a retrospective basis. We have not early adopted the amendments as of September 30, 2018. We do not expect our adoption of the amendments to materially affect our disclosures. (d) Customer accounting for implementation costs incurred in a cloud computing arrangement The FASB issued amendments in August 2018 to clarify the accounting for implementation costs of a cloud computing arrangement (also referred to as a hosting arrangement) that is a service contract. Implementation costs, which include implementation, setup and other upfront costs, are either to be deferred or expensed as incurred, in accordance with existing internal-use software guidance for similar costs. The amendments require a customer to expense capitalized implementation costs over the contractual term of the arrangement, including any optional renewal periods the customer is reasonably certain it will exercise. An entity is to present deferred implementation costs on the balance sheet, income statement and cash flows consistent with the subscription fees associated with the arrangement. The amendments enhance disclosures to include certain qualitative and quantitative information about implementation costs for internal-use software and all hosting arrangements, not just hosting arrangements that are service contracts. The amendments are effective for public business entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. An entity may apply the amendments either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We have not early adopted the amendments as of September 30, 2018. We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows and disclosures.

Revenue

Revenue	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Revenue	Revenue On January 1, 2018, we adopted ASC 606 and all related amendments using the modified retrospective method, which we applied only to contracts that were not completed as of January 1, 2018. For reporting periods beginning on January 1, 2018, we present revenue in accordance with ASC 606, and have not adjusted comparative prior period information, which we continue to report under the legacy accounting standards in effect for those prior periods. For the three and nine months ended September 30, 2018 , the effect of applying ASC 606 to recognize revenue as compared to applying the legacy accounting standards was not material. We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any material significant payment terms because we receive payment at or shortly after the point of sale. The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about reportable segments, refer to Note 13. Networks Segment Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts, with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas. Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial. Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to Federal Energy Regulatory Commission (FERC) regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO), or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer. The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the transmission service. We record revenue for all of those sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less . Networks does not have any material significant payment terms because it receives payment at or shortly after the point of sale. For its New York utilities, Networks assesses its deferred payment arrangements at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result. Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations, and other demand side management programs. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues. Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property, and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives, or ARPs. Renewables Segment Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar, and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC. Renewables does not have any material significant payment terms because it receives payment at or shortly after the point of sale. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements. Renewables classifies certain contracts for the sale of electricity as either leases or derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer. Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration. Other Other, which does not represent a segment, derives its revenues primarily from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards, gas trading contracts not classified as derivatives, and other miscellaneous revenues including intersegment eliminations. See Note 20 – Assets Held For Sale for further discussion of the sale of the gas storage and trading businesses. Contract Costs and Practical Expedient We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. Renewables has an origination sharing bonus plan that meets the requirements for capitalization. Costs incurred prior to 2018 were insignificant and not capitalized. Costs capitalized to date in 2018 are also insignificant, with amortization on a straight-line basis over the term of the related contract for which the terms may be from three years to 20 years . We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs. Revenues disaggregated by major source for our reportable segments for the three and nine months ended September 30, 2018 are as follows: Three Months Ended September 30, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,010 $ — $ — $ 1,010 Regulated operations – natural gas 169 — — 169 Nonregulated operations – wind — 198 — 198 Nonregulated operations – solar — 4 — 4 Nonregulated operations – thermal — 22 — 22 Nonregulated operations – gas storage — — 1 1 Other (a) 14 (25 ) 2 (9 ) Revenue from contracts with customers 1,193 199 3 1,395 Leasing revenue 9 76 — 85 Derivative revenue — 40 — 40 Alternative revenue programs 22 — — 22 Other revenue 4 — — 4 Total operating revenues $ 1,228 $ 315 $ 3 $ 1,546 Nine Months Ended September 30, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 2,736 $ — $ — $ 2,736 Regulated operations – natural gas 1,007 — — 1,007 Nonregulated operations – wind — 546 — 546 Nonregulated operations – solar — 12 — 12 Nonregulated operations – thermal — 36 — 36 Nonregulated operations – gas storage — — 11 11 Other (a) 45 (58 ) 11 (2 ) Revenue from contracts with customers 3,788 536 22 4,346 Leasing revenue 27 255 — 282 Derivative revenue — 105 10 115 Alternative revenue programs 66 — — 66 Other revenue 4 — — 4 Total operating revenues $ 3,885 $ 896 $ 32 $ 4,813 (a) Primarily includes certain intra-month trading activities, billing, collection, and administrative charges, sundry billings, and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate, Gas and intersegment eliminations. As of September 30, 2018 , accounts receivable balances related to contracts with customers were approximately $1,015 million , which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets. As of September 30, 2018 , for contracts with durations greater than one year (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied), and (2) when we expect to recognize the revenue, were as follows: As of September 30, 2018 2019 2020 2021 2022 2023 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 7 $ 8 $ 9 $ 9 $ 9 $ 25 $ 67 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 14 8 3 3 3 1 32 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 20 12 9 5 4 12 62 Total operating revenues $ 41 $ 28 $ 21 $ 17 $ 16 $ 38 $ 161 We do not disclose information about remaining performance obligations for (i) contracts with an original expected duration of one year or less and (ii) contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	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 are 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; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,754 million . 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 August 25, 2014, the Maine Public Utility Commission (MPUC) approved a stipulation agreement that provided for a distribution rate increase for Central Maine Power (CMP) of approximately $24.3 million , effective July 1, 2014, with an allowed return on equity (ROE) of 9.45% and an allowed equity ratio of 50% . The stipulation provided for the implementation of a revenue decoupling mechanism (RDM), reserve accounting and sharing of incremental storm costs, a separate proceeding for recovery of a new billing system and no earning sharing. On May 29, 2018, a ten-person complaint was filed with the MPUC against CMP, Networks and AVANGRID. The complaint requested that the MPUC open a rate case to determine if CMP is making excessive returns on investment and, therefore, whether CMP’s retail rates should be lower. The complaint also requested the MPUC deny certain costs associated with the October 2017 windstorm. On July 24, 2018, the MPUC issued an order dismissing the complaint and its associated request to deny the recovery of costs associated with the October 2017 windstorm. The order initiated an investigation into CMP’s rates and revenue requirement and directed CMP to make a filing consistent with the requirements for a general rate case no later than October 15, 2018. Consistent with the order in the 10-person complaint proceeding, on August 7, 2018, the MPUC issued a Notice of Investigation, opening the proceeding in which CMP would make its rate case filing and through which the MPUC will examine the rates and revenue requirements of CMP. On October 15, 2018, CMP filed a general rate case as directed by the MPUC requesting a ROE of 10% and an equity ratio of 55% . The company is proposing to use savings arising out of changes in federal taxation pursuant to the Tax Act to keep its distribution prices stable while making its electric system more reliable. The MPUC has established a ten-month process to review CMP’s filing and we expect a decision in August of 2019. CMP’s general rate case filing includes a proposal to enhance the resiliency of the energy grid by expanding vegetation management and pursuing additional reliability measures such as pole replacements and addition of tree wire in selected areas. Such investments are designed to strengthen CMP’s power grid so it can better stand up to severe weather. CMP is planning to use savings from the federal Tax Act to pay for the costs of resiliency programs, other investments in infrastructure and certain cost increases since 2014. We cannot predict the outcome of this matter. On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal filed with the NYPSC by New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E) and by certain other signatory parties on February 19, 2016, in connection with a three -year rate plan for electric and gas service at NYSEG and RG&E effective May 1, 2016. Following the approval of the Joint Proposal most of the regulatory deferrals related to NYSEG are amortized over a five -year period, except the portion of storm costs to be recovered over ten years, unfunded deferred taxes being amortized over a period of fifty years and plant related tax items which are amortized over the life of associated plant. Annual amortization expense for NYSEG is approximately $16.5 million per rate year. RG&E items that are being amortized are plant related tax items, which are amortized over the life of associated plant, and unfunded deferred taxes being amortized over a period of fifty years. A majority of the other items related to RG&E, which net to a regulatory liability, remain deferred and will not be amortized until future proceedings. The approved Joint Proposal provides for annual rate increases and an allowed rate of return on common equity of 9.0% for each of NYSEG and RG&E. 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 (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates, and continuation of the existing RDM for each company. In December 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017. These new distribution schedules provide for, among other things, annual tariff increases and an ROE of 9.10% based on a 50% equity ratio, continued UI’s existing earnings sharing mechanism (ESM) pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year , and the continued existence of a decoupling mechanism. The schedules also 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. In December 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with rate increases of $1.5 million , $4.7 million and $5.0 million in 2018, 2019, and 2020, respectively. The new tariff also includes an RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for Connecticut Natural Gas Corporation (CNG), ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on a ROE of 9.25% and approximately 52% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist. On May 17, 2018, The Berkshire Gas Company (BGC) filed a petition with the Department of Public Utilities (DPU) for approval of a general increase in its gas distribution rates to be effective April 1, 2019 . BGC requested an increase to the base distribution rate revenue requirement of $4.54 million , offset by decreases in other factors of $1.43 million , resulting in a net change in operating revenue of $3.11 million , and a 10.35% ROE applied to existing capital structure. BGC’s filing takes into account the reduction in the federal corporate income tax rate that results from the Tax Act, which became effective January 1, 2018. As part of the filing, BGC also proposed an alternative ratemaking mechanism (ARM) that will allow it to annually adjust its rates without filing for a base rate proceeding. The proposed ARM has a five-year term that begins in 2019 with the establishment of rates approved in this proceeding and is followed by four annual rate adjustments in 2020 through 2023. Further, BGC proposed to implement a rate mechanism to decouple its gas revenues from its sales and a reconciling mechanism to recover costs associated with pension and other post-retirement employee benefits. On June 29, 2018, Connecticut Natural Gas Corporation (CNG) filed an application with PURA for new tariffs to become effective January 1, 2019. CNG requested a three-year rate plan for calendar years 2019, 2020 and 2021. The Application requests an increase in rates of $16.6 million in 2019, an incremental increase of $10.1 million in 2020, and an incremental increase of $1.1 million in 2021. In addition, the application proposes to implement a customer rate credit of $1.25 million per year through 2027 as an offset in base rates, arising from the merger commitments made in connection with AVANGRID’s acquisition of UIL Holdings Corporation (UIL) in December 2015; a return to customers of the full tax benefits resulting from the reduction in the corporate federal income tax rate in the Tax Act; and ratemaking proposals to transition the DIMP mechanism to operate as a true-up mechanism, and to apply CNG’s current decoupling mechanism to all firm customers going forward . On August 30, 2018, CNG entered into a Settlement Agreement with the Office of Consumer Counsel and PURA Prosecutorial Staff that provides for new rates effective January 1, 2019. The Settlement Agreement has been submitted to PURA for approval. The Settlement Agreement establishes an increase in rates of $9.9 million in 2019, an incremental increase of $4.6 million in 2020, and an incremental increase of $5.2 million in 2021, for a total increase of $19.7 million over the three -year rate plan. PURA is currently conducting a review of the Settlement Agreement and is expected to render a decision by the end of 2018. Current and non-current regulatory assets as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 24 $ 24 Pension and other post-retirement benefits 12 7 Storm costs 65 46 Rate adjustment mechanism 17 — Reliability support services 19 27 Revenue decoupling mechanism 10 21 Transmission revenue reconciliation mechanism 7 8 Electric supply reconciliation 7 — Hedges losses — 3 Contracts for differences 8 9 Hardship programs 13 14 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 12 31 Deferred transmission expense 16 37 Environmental remediation costs 14 13 Other 44 51 Total Current Regulatory Assets 284 307 Non-current Pension and other post-retirement benefits cost deferrals 116 110 Pension and other post-retirement benefits 1,035 1,162 Storm costs 296 254 Deferred meter replacement costs 27 29 Unamortized losses on reacquired debt 16 17 Environmental remediation costs 270 283 Unfunded future income taxes 369 376 Asset retirement obligation 19 18 Deferred property tax — 14 Federal tax depreciation normalization adjustment 152 155 Merger capital expense target customer credit 1 2 Debt premium 120 131 Reliability support services — 10 Plant decommissioning 7 9 Contracts for differences 90 84 Hardship programs 9 13 Deferred income taxes regulatory 44 — Other 64 71 Total Non-current Regulatory Assets $ 2,635 $ 2,738 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings. “Storm costs” for 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 a 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 September 30, 2018 . “Deferred meter replacement costs” represent the deferral of the book value of retired meters that were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. Following the approval of the Joint Proposal by the NYPSC, these amounts will be collected over a fifty -year period, and the NYPSC Staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances. “Asset retirement obligations” (ARO) represent the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amount for NYSEG and RG&E is being amortized over a five year period following the approval of the Joint Proposal by the NYPSC. “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rates years covering 2011 forward. The recovery period in New York is from 27 to 39 years and for CMP this will be determined in future MPUC rate proceedings. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Contracts for Differences” (CfDs) represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. “Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve month period. “Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided for in rates. “Other” includes post term amortization deferrals and various items subject to reconciliation including rate change levelization and loss on re-acquired debt. Current and non-current regulatory liabilities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Current Non by-passable charges $ 6 $ 5 Energy efficiency portfolio standard 56 37 Gas supply charge and deferred natural gas cost 2 4 Transmission revenue reconciliation mechanism 6 14 Pension and other post-retirement benefits — 1 Pension and other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 23 21 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE Refund — 4 Merger related rate credits — 1 Revenue decoupling mechanism 4 4 Stranded costs 3 17 Hedges gains 7 — Other 68 51 Total Current Regulatory Liabilities 194 178 Non-current Accrued removal obligations 1,145 1,132 2017 Tax Act 1,566 1,515 Asset sale gain account 10 10 Carrying costs on deferred income tax bonus depreciation 55 72 Economic development 28 32 Merger capital expense target customer credit account 6 6 Pension and other post-retirement benefits cost deferrals 63 74 Positive benefit adjustment 37 39 New York state tax rate change 4 6 Theoretical reserve flow thru impact 15 19 Deferred property tax 24 19 Net plant reconciliation 19 10 Variable rate debt 42 33 Carrying costs on deferred income tax - Mixed Services 263(a) 16 20 Rate refund – FERC ROE proceeding 27 27 Transmission congestion contracts 21 19 Merger-related rate credits 18 20 Accumulated deferred investment tax credits 13 13 Asset retirement obligation 12 13 Earning sharing provisions 17 22 Middletown/Norwalk local transmission network service collections 18 19 Excess generation service charge 10 2 Low income programs 35 42 Non-firm margin sharing credits 13 8 Deferred income taxes regulatory — 13 Other 71 67 Total Non-current Regulatory Liabilities $ 3,285 $ 3,252 “Non by-passable charges” represent the non by-passable charges 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 amounts billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station located in Oswego, New York. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Economic development” represents the economic development program which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Merger capital expense target customer credit” account was created as a result of NYSEG and RG&E not meeting certain capital expenditure requirements established in the order approving the purchase of AVANGRID (formerly Energy East Corporation) by Iberdrola. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this, a regulatory liability is not reflected within the rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. The amortization period is five years following the approval of the Joint Proposal by the NYPSC and included in the Ginna RSSA settlement. “New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from 7.1% to 6.5% . The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is five years following the approval of the Joint Proposal by the NYPSC. “2017 Tax Act” represents the impact from remeasurement and over-recoveries as a result of the Tax Act. 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 and currently 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, respectively, to review and address the implications associated with the Tax Act on the utilities providing service in such states. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the three and nine months ended September 30, 2018 , respectively, $1 million and $3 million of rate credits were applied against customer bills. In the three and nine months ended September 30, 2017 , respectively, $0 and $2 million of rate credits were applied against customer bills. “Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “Low Income Programs” represent various hardship and payment plan programs approved for recovery. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	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 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. • UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables and Gas activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical product with no adjustment are included in the Level 1 fair value. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in Level 2 fair value. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in Level 3 fair value. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. We determine the fair value of our interest rate swap derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate swaps). 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 Level 1. Restricted cash was $8 million and $5 million as of September 30, 2018 and December 31, 2017 , respectively, which is included in other assets on the balance sheet. The financial instruments measured at fair value as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 12 15 76 (33 ) 70 Derivative financial instruments - gas — 7 42 (49 ) — Contracts for differences — — 7 — 7 Derivative financial instruments – other — 4 — — 4 Total 12 26 125 (82 ) 81 Derivative liabilities Derivative financial instruments - power (8 ) (16 ) (22 ) 40 (6 ) Derivative financial instruments - gas — (8 ) (9 ) 12 (5 ) Contracts for differences — — (105 ) — (105 ) Derivative financial instruments – other — (3 ) — — (3 ) Total $ (8 ) $ (27 ) $ (136 ) $ 52 $ (119 ) 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 ) Included in the derivative financial instruments – gas are derivative assets and liabilities of the Gas segment classified as held for sale on the condensed consolidated balance sheet as of December 31, 2017 . See Note 20 – Assets Held For Sale for further discussion. The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2018 and 2017 , respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2018 2017 2018 2017 Fair Value Beginning of Period, $ (1 ) $ 32 $ 6 $ 31 Gains recognized in operating revenues — 9 11 20 (Losses) recognized in operating revenues (5 ) — (8 ) (3 ) Total (losses) gains recognized in operating revenues (5 ) 9 3 17 Gains recognized in OCI — 1 — 2 (Losses) recognized in OCI (1 ) — (1 ) (1 ) Total (losses) gains recognized in OCI (1 ) 1 (1 ) 1 Net change recognized in regulatory assets and liabilities 2 2 (6 ) 4 Purchases (3 ) 5 (6 ) 3 Settlements (3 ) (3 ) (7 ) (10 ) Fair Value as of September 30, $ (11 ) $ 46 $ (11 ) $ 46 Gains (losses) for the period included in operating revenues attributable to the change in unrealized gains (losses) relating to financial instruments still held at the reporting date $ (5 ) $ 9 $ 3 $ 17 For assets and liabilities that are recognized in the condensed consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the periods reported. Level 3 Fair Value Measurement The tables below illustrate the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives. As of September 30, 2018 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power Transactions with Transactions are Observable and NYMEX ($/MMBtu) $ 2.94 $ 3.93 $ 2.44 with delivery exceeding two on a corroborated by Indiana hub ($/MWh) $ 30.62 $ 53.90 $ 19.10 period > two years discounted market data for identical or Mid C ($/MWh) $ 23.31 $ 57.00 $ (0.50 ) years basis similar products Minn hub ($/MWh) $ 25.18 $ 49.85 $ 12.51 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 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 the 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 the fair value of the CfDs (see Note 7 for further discussion of CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input September 30, 2018 Risk of non-performance 0% - 0.59% Discount rate 2.59% - 3.05% Forward pricing ($ per KW-month) $4.30 - $9.55 Fair Value of Debt As of September 30, 2018 and December 31, 2017 , debt consisted of first mortgage bonds, fixed and variable unsecured pollution control notes, other various non-current debt securities and obligations under capital leases. The estimated fair value of debt amounted to $5,781 million and $5,799 million as of September 30, 2018 and December 31, 2017 , respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy pertaining to the fair value of debt is considered Level 2, except for unsecured pollution control notes-variable with a fair value of $61 million as of December 31, 2017 , which were repaid in the second quarter of 2018 and were considered Level 3. The fair value of these unsecured pollution control notes-variable were determined using unobservable interest rates as the market for these notes is inactive. On June 29, 2018, NYSEG and RG&E remarketed $326 million in aggregate principal amount of Pollution Control Revenue Bonds, issued through the New York State Energy Research and Development Authority, with mandatory tender and maturity dates ranging from 2023 to 2029 and interest rates ranging 2.625% - 3.50% . On October 2, 2018, UI remarketed $64.5 million in aggregate principal amount of Pollution Control Refunding Revenue Bonds, issued through the Business Finance Authority of the State of New Hampshire, with mandatory tender date in 2023 and an interest rate of 2.80% . In September 2018, UI, CNG, SCG and BGC offered a total $295 million of debt securities in the private placement market. In connection with the offering, on October 4, 2018, collectively UI, CNG and BGC executed a note purchase agreement to issue senior unsecured notes, and SCG executed a bond purchase agreement to issue secured mortgage bonds. On October 4, 2018, UI issued $100 million of senior unsecured notes maturing in 2028 at an interest rate of 4.07% . The remaining $195 million in aggregate amount of notes/bonds are expected to be issued in January 2019, subject to certain closing conditions.

Derivative Instruments and Hedg

Derivative Instruments and Hedging	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Derivative Instruments and Hedging Our Networks, Renewables and Gas activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on the condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities. (a) Networks activities NYSEG and RG&E each have an electric commodity charge that passes through rates costs for the market price of electricity. We 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 liabilities and assets for electricity derivatives was a gain of $6.7 million and a loss of $2.2 million , respectively, as of September 30, 2018 , and a loss of $0.2 million as of December 31, 2017 . The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a gain of $4.1 million and $8.7 million for the three and nine months ended September 30, 2018 , respectively, and a loss of $7.9 million and $29.2 million for the three and nine months ended September 30, 2017 , respectively. NYSEG and RG&E each have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amount recognized in regulatory liabilities and assets for natural gas hedges was a gain of $0.1 million and a loss of $2.5 million as of September 30, 2018 and December 31, 2017 , respectively. The amount reclassified from regulatory assets and liabilities into income, which is included in natural gas purchased, was a loss of $0 and $1.7 million for the three and nine months ended September 30, 2018 , respectively, and a gain of $0 and $0.6 million for the three and nine months ended September 30, 2017 , respectively. Pursuant to a PURA order, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of September 30, 2018 , UI has recorded a gross derivative asset of $7 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $98 million , a gross derivative liability of $105 million ( $97 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0 . As of December 31, 2017 , UI had recorded a gross derivative asset of $12 million ( $0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $93 million , a gross derivative liability of $104 million ( $90 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0 . The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three and nine months ended September 30, 2018 and 2017 , respectively, were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Derivative assets $ (1 ) $ (2 ) $ (5 ) $ (6 ) Derivative liabilities $ 2 $ 4 $ (1 ) $ 10 The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts (MWh) 4.0 3.9 Natural gas purchase contracts (Dth) 7.7 6.1 Fleet fuel purchase contracts (Gallons) 2.0 2.1 The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Networks activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 16 $ 3 $ 5 $ 1 Derivative liabilities (5 ) (1 ) (18 ) (95 ) 11 2 (13 ) (94 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 11 2 (13 ) (94 ) Cash collateral receivable — — — 2 Total derivatives as presented in the balance sheet $ 11 $ 2 $ (13 ) $ (92 ) As of December 31, 2017 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 20 $ 5 $ 13 $ — Derivative liabilities (13 ) — (32 ) (88 ) 7 5 (19 ) (88 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 7 5 (19 ) (88 ) Cash collateral receivable — — 3 — Total derivatives as presented in the balance sheet $ 7 $ 5 $ (16 ) $ (88 ) The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses — Total $ — $ 2 2017 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses 1 Total $ — $ 3 Nine Months Ended September 30, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Interest rate contracts $ — Interest expense $ 6 Commodity contracts — Operating expenses — Total $ — $ 6 2017 Interest rate contracts $ — Interest expense $ 6 Commodity contracts (1 ) Operating expenses 1 Total $ (1 ) $ 7 _________________________ (a) Changes in accumulated OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchased power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $62.8 million and $68.8 million as of September 30, 2018 and December 31, 2017 , respectively. We recorded $2.0 million and $6.0 million in net derivative losses related to discontinued cash flow hedges for both three and nine months ended September 30, 2018 and 2017 . We will amortize approximately $2.0 million of discontinued cash flow hedges for the remainder of 2018. During the three and nine months ended September 30, 2018 and 2017 , there was no ineffective portion for cash flow hedges. The unrealized loss of $0.2 million on hedge activities is reported in accumulated OCI because the forecasted transaction is considered to be probable as of September 30, 2018 . We expect that $0.2 million of these losses will be reclassified into earnings within the next twelve months . The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months . (b) Renewables and Gas activities The below presented quantitative information includes derivative financial instruments associated with Gas activities, which were classified as held for sale in the condensed consolidated balance sheet as of December 31, 2017 (see Note 20 - Assets Held for Sale). We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities. Renewables has 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. The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (MWh/Dth in millions) Wholesale electricity purchase contracts 3 4 Wholesale electricity sales contracts 5 6 Natural gas and other fuel purchase contracts 22 285 Financial power contracts 10 12 Basis swaps – purchases 33 68 Basis swaps – sales 1 62 The fair values of derivative contracts associated with Renewables and Gas activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts $ 4 $ (3 ) Wholesale electricity sales contracts — 8 Natural gas and other fuel purchase contracts (1 ) 19 Financial power contracts 54 55 Basis swaps – purchases (4 ) (13 ) Basis swaps – sales — 4 Total $ 53 $ 70 The effect of trading derivatives associated with Renewables and Gas activities for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Wholesale electricity purchase contracts $ (3 ) $ — $ 3 $ (2 ) Wholesale electricity sales contracts 1 1 — 4 Financial power contracts — (2 ) (2 ) (2 ) Financial and natural gas contracts — — 3 4 Total (Loss) Gain $ (2 ) $ (1 ) $ 4 $ 4 The effect of non-trading derivatives associated with Renewables and Gas activities for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Wholesale electricity purchase contracts $ 1 $ — $ 5 $ (2 ) Wholesale electricity sales contracts — (4 ) (7 ) 2 Financial power contracts (12 ) 2 (11 ) 8 Financial and natural gas contracts 4 (1 ) 8 (6 ) Total (Loss) Gain $ (7 ) $ (3 ) $ (5 ) $ 2 Such gains and losses are included in Operating revenues and in Purchased power, natural gas and fuel used operating expenses in the condensed consolidated statements of income, depending upon the nature of the transaction. The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 17 $ 96 $ 12 $ 8 Derivative liabilities (2 ) (4 ) (23 ) (18 ) 15 92 (11 ) (10 ) Designated as hedging instruments Derivative assets 1 2 1 4 Derivative liabilities — — (3 ) (5 ) 1 2 (2 ) (1 ) Total derivatives before offset of cash collateral 16 94 (13 ) (11 ) Cash collateral (payable) receivable (9 ) (37 ) 5 8 Total derivatives as presented in the balance sheet $ 7 $ 57 $ (8 ) $ (3 ) 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 (payable) receivable (17 ) (39 ) 3 3 Total derivatives as presented in the balance sheet, including assets and liabilities held for sale $ 36 $ 58 $ (20 ) $ (4 ) The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives Location of Loss (Gain) Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Commodity contracts $ (3 ) Operating revenues $ (1 ) Total $ (3 ) $ (1 ) 2017 Commodity contracts $ 8 Operating revenues $ 1 Total $ 8 $ 1 Nine Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives Location of Loss (Gain) Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Commodity contracts $ (4 ) Operating revenues $ (21 ) Total $ (4 ) $ (21 ) 2017 Commodity contracts $ 12 Operating revenues $ 31 Total $ 12 $ 31 _____________________ (a) Changes in accumulated OCI are reported on a pre-tax basis. Amounts are reclassified from accumulated OCI into income in the period during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $ 0.7 million of loss included in accumulated OCI at September 30, 2018 , is expected to be reclassified into earnings within the next twelve months. We recorded a net gain of $0.2 million and $0 in the three and nine months ended September 30, 2018 , respectively, and a net gain of $0.5 million and $1.0 million , in the three and nine months ended September 30, 2017 , respectively, in earnings as a result of ineffectiveness from cash flow hedges. The net loss in accumulated OCI related to a discontinued cash flow hedge is $0.4 million as of September 30, 2018 , out of which an immaterial amount will be amortized in the remainder of 2018. We recorded $0 and $0.1 million in net derivative losses related to discontinued cash flow hedges for the three and nine months ended September 30, 2018 , respectively. (c) Interest rate swaps AVANGRID uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. In the second quarter of 2018, AVANGRID entered into two forward interest rate swaps, with a total notional amount of $500 million , to hedge the issuance of forecasted fixed rate debt in 2019. The forward interest rate swaps are designated and qualify as cash flow hedges, have mandatory termination dates of June 28, 2019, and are expected to be settled upon the forecasted debt issuance. The effective portion of the gain or loss on the interest rate swap derivative is reported as a component of accumulated OCI and reclassified into earnings in the period or periods during which related interest payments of the forecasted debt will occur. Pre-tax gains of $8.1 million and $3.7 million were recognized in accumulated OCI for the three and nine months ended September 30, 2018 from the effective portion of changes in the fair value of the interest rate swap derivative instruments. The amounts in accumulated OCI are expected to be reclassified into earnings upon interest rate swap settlement over the underlying debt maturity period. During both the three and nine months ended September 30, 2018 , no ineffectiveness was recorded from cash flow hedges. The forward interest rate swap derivative assets of $3.7 million are included in current assets on the balance sheet and do not have related offsetting cash collateral or other derivative assets/liabilities to be offset with. (d) 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 applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by 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 falls below investment grade. If such an event had occurred as of September 30, 2018 , UI would have had to post an aggregate of approximately $14 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 in the event of a counterparty default or contract termination. 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 $11 million and $30 million as of September 30, 2018 and December 31, 2017 , respectively. Derivative instruments settlements and collateral payments are included in “Other assets/liabilities” of operating activities in the condensed consolidated statements of cash flows. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of September 30, 2018 is $2.2 million .

Contingencies

Contingencies	9 Months Ended
	Sep. 30, 2018
Commitments and Contingencies Disclosure [Abstract]
Contingencies	Contingencies We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a complaint (Complaint I) with the FERC pursuant to sections 206 and 306 of the Federal Power Act. The filing parties sought an order from the FERC reducing the 11.14% base ROE used in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) to 9.2% . CMP, MEPCO and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint. On June 19, 2014, the FERC issued its decision in Complaint I, establishing an ROE methodology and setting an issue for a paper hearing. On October 16, 2014, the FERC issued its final decision in Complaint I setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014, and ordered the NETOs to file a refund report. On November 17, 2014, the NETOs filed the requested refund report. On March 3, 2015, the FERC issued an order on requests for rehearing of its October 16, 2014 decision. The March order upheld the FERC’s June 19, 2014 decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. In June 2015, the NETOs and complainants both filed an appeal of the FERC’s final order in the U.S. Court of Appeals for the District of Columbia (the Court). On April 14, 2017, the Court vacated FERC’s decision on Complaint I and remanded it to the FERC. The Court held that the 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 the 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 the FERC did not provide reasoned judgment as to why an ROE of 10.57% at the midpoint of the upper end of the zone of reasonableness is a just and reasonable ROE. Instead, FERC had only explained in its order that the midpoint of 9.39% was not just and reasonable and a higher base ROE was warranted. On June 5, 2017, the NETOs made a filing with the 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 the 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 the FERC has a quorum of commissioners. On October 6, 2017, the FERC issued an order rejecting the NETOs request to collect transmission revenue requirements at the higher ROE of 11.14% , pending a FERC order on remand. In reaching this decision, the 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, the FERC reasoned that the NETOs will not be harmed financially by not immediately returning to their pre-Complaint I ROE. 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, the FERC accepted Complaint II, established a 15 -month refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in Complaint I. On July 31, 2014, a third ROE complaint (Complaint III) was filed for a subsequent rate period requesting the then effective ROE of 11.14% be reduced to 8.84% . On November 24, 2014, the FERC accepted Complaint III, established a 15 -month refund effective date of July 31, 2014, and consolidated this matter 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 the FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the Court. 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 FERC administrative law judge’s recommendation to the FERC Commissioners. 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 $23.2 million and $4.4 million , respectively, as of September 30, 2018 , which has not changed since December 31, 2017, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge 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. On April 29, 2016, a fourth ROE complaint (Complaint IV) was filed for a rate period subsequent to prior complaints requesting the then existing base ROE of 10.57% be reduced to 8.61% and the ROE Cap be set at 11.24% . The NETOs filed a response to the Complaint IV on June 3, 2016. On September 20, 2016, the FERC accepted the Complaint IV, established a 15 -month refund effective date of April 29, 2016, and set the matter for hearing and settlement judge procedures. In April 2017, the NETOs filed for a stay in the hearings pending the FERC taking action on the Court order described above. That request was denied by the FERC administrative law judge. On November 21, 2017, the parties submitted updates to their ROE analyses and recommendations with the NETOs continuing to advocate that the existing base ROE of 10.57% should remain in effect. Hearings were held in December 2017. On March 27, 2018, the FERC administrative law judge issued an initial decision rejecting Complaint IV, finding the currently-filed base ROE of 10.57% , which, with incentive adders, may reach a maximum ROE of 11.74% , is not unjust and unreasonable, and hence is not unlawful. Briefs on Exceptions to the FERC administrative law judge’s initial decision were filed on April 26, 2018, and Briefs Opposing Exceptions were filed on May 23, 2018. The FERC has not yet issued its final decision in this docket. 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 the 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 the FERC does not complete its review of a complaint within the 15 -month period. In the event the FERC chooses not to dismiss the complaints, the NETOs request that the FERC consolidate the complaints for decision as the evidentiary records are either closed or advanced enough for the FERC to address the requirements of the Court decision and expeditiously issue a final order. The FERC has not yet ruled on this Motion. We cannot predict the outcome of this proceeding. On October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at FERC (the October 2018 Order). The FERC proposes to use this new methodology to resolve Complaints I, II, III, and IV filed by the New England state consumer advocates. The new proposed ROE methodology set forth in the October 2018 Order considers more than just the two-step discounted cash flow (DCF) analysis adopted in the FERC order on Complaint I vacated by the Court. The new proposed ROE methodology uses three financial analyses (i.e., DCF, the capital-asset pricing model, and the expected earnings analysis) to produce a range of returns to narrow the zone of reasonableness when assessing whether a complainant has met its initial burden of demonstrating that the utility’s existing ROE is unjust and unreasonable. The new proposed ROE methodology establishes a range of just and reasonable ROEs of 9.60% to 10.99% and proposes a just and reasonable base ROE of 10.41% with a new ROE cap of 13.08% . The October 2018 Order directs the NETOs to file briefs with objections and rates consistent with the proposed methodology in all four Complaints by December 17, 2018. We cannot predict the outcome of this proceeding. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm On March 11, 2017, the New York State Department of Public Service (the Department) commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which affected more than 219,000 NYSEG and RG&E customers. The Department Staff issued a report (the Staff Report) of the findings from their investigation on November 16, 2017. The Staff Report made several recommendations for future storm response and also alleged that NYSEG and RG&E had violated their own emergency response plan in a number of respects. Also on November 16, 2017, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Order) requiring the companies to address whether the NYPSC should mandate, reject or modify, in whole or in part the recommendations made in the Staff Report. The Order also required the companies to show cause why the NYPSC should not commence an administrative penalty proceeding. On May 18, 2018, NYSEG and RG&E filed a settlement joint proposal and investment joint proposal before the NYPSC to settle potential penalties and avoid litigation related to the March 2017 windstorm, pursuant to which, among other things, NYSEG and RG&E have agreed to make $3.9 million in investments in 2018 designed to increase resiliency and improve emergency response in the areas impacted by the storm. The investments will not be reflected in rate base or operating expenses in establishing future delivery rates. The joint proposals are subject to public comment and NYPSC approval. We cannot predict the final outcome of this matter. New York State Department of Public Service Investigation of the Preparation for and Response to the March 2018 Winter Storms In March 2018, following two severe winter storms that impacted over more than a million electric utility customers in New York, including 520,000 NYSEG and RG&E customers, the NYPSC initiated a comprehensive investigation of all the New York electric utilities’ preparation and response to those events. The investigation has been expanded to include other 2018 New York spring storm events. We cannot predict the final outcome of this matter. California Energy Crisis Litigation Two California agencies brought a complaint in 2001 against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding. 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, the 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 a FERC administrative law judge 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 conduct that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million . Renewables position, as presented at hearings and agreed to by FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. In April 2018 Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. We cannot predict the outcome of this proceeding. Class Actions Regarding LDC Gas Transportation Service on Algonquin Gas Transmission Breiding et al. v. Eversource and Avangrid - Class Action . On November 16, 2017, a class action lawsuit was filed in the U.S. District Court for the District of Massachusetts on behalf of customers in New England against the Company and Eversource alleging that certain of their respective subsidiaries that take gas transportation service over the Algonquin Gas Transmission (AGT), which for AVANGRID would be its indirect subsidiaries SCG and CNG, engaged in pipeline capacity scheduling practices on AGT that resulted in artificially increased electricity prices in New England. These allegations were based on the conclusions of a White Paper issued by the Environmental Defense Fund (EDF), an environmental advocacy organization, on October 10, 2017, purporting to analyze the relationship between the New England electricity market and the New England local gas distribution companies. The plaintiffs assert claims under federal antitrust law, state antitrust, unfair competition and consumer protection laws, and under the common law of unjust enrichment. They seek damages, disgorgement, restitution, injunctive relief, and attorney fees and costs. The Company filed a Motion to Dismiss all of the claims on January 29, 2018. On February 27, 2018, the FERC released the results of a FERC staff inquiry into the pipeline capacity scheduling practices on the AGT. The inquiry arose out of the allegations made by the EDF in its White Paper. FERC announced that, based on an extensive review of public and non-public data, it had determined that the EDF study was flawed and led to incorrect conclusions. FERC also stated that the staff inquiry revealed no evidence of anticompetitive withholding of natural gas pipeline capacity on the AGT and that it would take no further action on the matter. On March 28, 2018, the plaintiffs filed a consolidated amended complaint, repeating the prior claims, except omitting the common law claim of unjust enrichment. On April 27, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry conclusion. The plaintiffs filed opposition to the motion to dismiss on May 25, 2018. The U.S. District Court for the District of Massachusetts held a hearing on the motion on August 1, 2018. On September 11, 2018, the District Court granted the Company’s Motion and dismissed all claims. On October 10, 2018, the plaintiffs filed a notice of appeal. We cannot predict the outcome of this appeal. PNE Energy Supply LLC v. Eversource Energy and Avangrid, Inc. - Class Action . On August 10, 2018, PNE Energy Supply LLC, a competitive energy supplier located in New England that purchases electricity in the day-ahead and real time wholesale electric market, filed a civil antitrust action, on behalf of itself and those similarly situated, against the Company and Eversource alleging that their respective gas subsidiaries illegally manipulated the supply of pipeline capacity in the “secondary capacity market” in order to artificially inflate New England natural gas and electricity prices. These allegations were also based on the conclusions of the White Paper issued by EDF. The plaintiff claims to represent entities who purchased electricity directly in the wholesale electricity market that it claims was targeted by the alleged anticompetitive conduct of Eversource and the Company. On September 28, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry and the dismissal of the related case, "Breiding et al. v. Eversource and Avangrid," by the same Court in September. The plaintiffs filed opposition to the motion to dismiss on October 26, 2018. We cannot predict the outcome of this class action lawsuit. Guarantee Commitments to Third Parties As of September 30, 2018 , we had approximately $2.6 billion of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of September 30, 2018 , neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liabilities

Environmental Liabilities	9 Months Ended
	Sep. 30, 2018
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	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 several for certain sites. We have recorded an estimated liability of $5 million related to ten of the twenty-five sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another ten sites where we believe it is probable that we will incur remediation costs and or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. We recorded a corresponding regulatory asset because we expect to recover these costs in rates. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Our estimate for costs to remediate these sites ranges from $12 million to $21 million as of September 30, 2018 . Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Eight sites are included in the New York State Registry; twelve sites are included in the New York Voluntary Cleanup Program; three sites are part of Maine’s Voluntary Response Action Program and two sites are 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 September 30, 2018 . Our estimate could change materially based on the 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 of our 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 for these sites as of September 30, 2018 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. As of September 30, 2018 and December 31, 2017 , the liability associated with our MGP sites in Connecticut, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $99 million and $100 million , respectively. Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $374 million and $389 million as of September 30, 2018 and December 31, 2017 , respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2054. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former manufactured gas sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor, requiring FirstEnergy to pay NYSEG approximately $60 million for past and future clean-up costs at the sixteen sites in dispute. On September 9, 2011, FirstEnergy paid NYSEG $30 million , representing their share of past costs of $27 million and pre-judgment interest of $3 million . FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million , excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean up expenses at nine MGP sites. Based on current projections, FirstEnergy’s share is estimated at approximately $22 million . This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG ratepayers. Century Indemnity and OneBeacon On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at 22 former manufactured gas plants. Based on estimated clean-up costs of $282 million , the carriers’ allocable share could equal or exceed approximately $89 million , excluding pre-judgment interest, although this amount may change substantially depending upon the determination of various factual matters and legal issues during the case. Century Indemnity and OneBeacon have answered, admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. On March 31, 2017, the District Court granted motions filed by Century Indemnity and One Beacon dismissing all of NYSEG’s claims against both defendants on the grounds of late notice. NYSEG filed a motion with the District Court on April 14, 2017 seeking reconsideration of the Court’s decision, which was denied by an order dated March 27, 2018. NYSEG filed a notice appealing the District Court’s dismissal on April 9, 2018. 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 Connecticut Department of Energy and Environmental Protection (DEEP) concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the English Station site; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages. This lawsuit had been stayed in May 2014 pending mediation. Due to lack of activity in the case, the court terminated the stay and scheduled a status conference for July 6, 2017. On July 5, 2017, Asnat filed a pretrial memorandum claiming damages of $10 million for “environmental remediation activities” and lost use of the property. In December 2017, Plaintiffs filed a Request for Leave to Amend Complaint and Motion to Cite-In Additional Parties, including former UIL officers and employees and other UI officers, which motion was approved in February 2018. Plaintiffs filed a revised complaint with the court on April 16, 2018 alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. The complaint was further revised July 3, 2018. We filed a Motion to Dismiss in August 2018. We cannot predict the outcome of this matter. On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April 2015. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with the DEEP. On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the consent order, to the extent that the cost of this investigation and remediation is less than $30 million , UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut and the Commissioner of DEEP. UI is obligated to comply with the terms of the consent order even if the cost of such compliance exceeds $30 million . Under the terms of the consent order, the State will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties; however, it is not bound to agree to or support any means of recovery or funding. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order. As of September 30, 2018 and December 31, 2017 , the amount reserved for this matter was $20 million and $25 million , respectively. We cannot predict the outcome of this matter.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
Post-retirement and Similar Obligations	Post-retirement and Similar Obligations We made $32 million and $40 million of pension contributions for the three and nine months ended September 30, 2018 , respectively. We expect to make additional contributions of $8 million for the remainder of 2018. The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Service cost $ 11 $ 10 $ 33 $ 32 Interest cost 32 35 96 104 Expected return on plan assets (50 ) (49 ) (150 ) (148 ) Amortization of: Prior service costs — — 1 1 Actuarial loss 38 32 113 95 Net Periodic Benefit Cost $ 31 $ 28 $ 93 $ 84 The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Service cost $ 1 $ 2 $ 3 $ 4 Interest cost 4 5 13 15 Expected return on plan assets (2 ) (2 ) (6 ) (6 ) Amortization of: Prior service costs (2 ) (3 ) (6 ) (7 ) Actuarial loss 1 1 4 3 Net Periodic Benefit Cost $ 2 $ 3 $ 8 $ 9 Beginning in 2018, in the condensed consolidated statements of income, we include the service cost component in other operating expenses net of capitalized portion, and include the components of net periodic benefit cost other than the service cost component in other expense.

Equity

Equity	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Equity	Equity As of September 30, 2018 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which are owned by Iberdrola, each having a par value of 0.01 , for a total value of common stock capital of $3 million and additional paid in capital of $13,656 million . As of December 31, 2017 , our share capital consisted of 500,000,000 shares of common stock authorized, 309,670,932 shares issued and 309,005,272 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of 0.01 , for a total value of common stock capital of $3 million and additional paid in capital of $13,653 million . We had 485,810 shares of common stock held in trust and no convertible preferred shares outstanding as of both September 30, 2018 and December 31, 2017 , respectively. During the three months ended September 30, 2018 , and 2017 we issued no shares of common stock and released no shares of common stock held in trust. During the nine months ended September 30, 2018 and 2017 , we issued 81,208 and 70,493 shares of common stock, respectively, and released 0 and 5,649 shares of common stock held in trust each having a par value of $0.01 . On April 28, 2016, we entered into a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage by Iberdrola at 81.5% . The stock repurchase program may be suspended or discontinued at any time upon notice. Out of a total of 261,058 treasury shares of common stock of AVANGRID as of September 30, 2018 , 115,831 shares were repurchased during 2016, 64,019 shares were repurchased in May 2017 and 81,208 shares were repurchased in May 2018, all in the open market. The total cost of all repurchases, including commissions, was $12 million as of September 30, 2018 . Accumulated Other Comprehensive Loss Accumulated Other Comprehensive (Loss) Gain for the three months ended September 30, 2018 and 2017 , respectively, consisted of: As of June, Adoption of Three Months Ended September 30, As of September 30, As of June 30, Three Months Ended September 30, As of September 30, 2018 standard 2018 2018 2017 2017 2017 (Millions) Gain on revaluation of defined benefit plans $ (13 ) $ — $ — $ (13 ) $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans (7 ) — — (7 ) (7 ) — (7 ) Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $1.5 for 2018 and $3.0 for 2017 25 — 5 30 7 5 12 Reclassification to net income of losses on cash flow hedges, net of income tax expense of $0.4 for 2018 $1.3 for 2017(a) (66 ) — 1 (65 ) (48 ) 3 (45 ) Gain on derivatives qualifying as cash flow hedges (41 ) — 6 (35 ) (41 ) 8 (33 ) Accumulated Other Comprehensive (Loss) Gain $ (61 ) $ — $ 6 $ (55 ) $ (62 ) $ 8 $ (54 ) Accumulated Other Comprehensive (Loss) Gain for the nine months ended September 30, 2018 and 2017 , respectively, consisted of: As of December 31, Adoption of Nine Months Ended September 30, As of September 30, As of December 31, Nine Months Ended September 30, As of September 30, 2017 standard 2018 2018 2016 2017 2017 (Millions) Gain on revaluation of defined benefit plans net of tax expense of $0.2 for 2018 $ (14 ) $ — $ 1 $ (13 ) $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans (6 ) (1 ) — (7 ) (7 ) — (7 ) Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $4.1 for 2017 30 — — 30 5 7 12 Reclassification to net income of (gains) losses on cash flow hedges, net of income tax (benefit) expense of $(6.8) for 2018 and $14.8 for 2017(a) (56 ) — (9 ) (65 ) (70 ) 25 (45 ) (Loss) gain on derivatives qualifying as cash flow hedges (26 ) — (9 ) (35 ) (65 ) 32 (33 ) Accumulated Other Comprehensive (Loss) Gain $ (46 ) $ (1 ) $ (8 ) $ (55 ) $ (86 ) $ 32 $ (54 ) ________________________ (a)Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Earnings Per Share

Earnings Per Share	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Earnings Per Share	Earnings Per Share Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three and nine months ended September 30, 2018 and 2017 , while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculation for the three months ended September 30, 2017 and the nine months ended September 30, 2018 and 2017 . The dilutive securities, which consist of performance and restricted units, did not result in a change in our earnings per share calculation for the three months ended September 30, 2018 . The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 125 $ 99 $ 476 $ 458 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,491,082 309,507,443 309,506,831 Weighted average number of shares outstanding - diluted 309,689,890 309,801,903 309,705,788 309,785,639 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.40 $ 0.32 $ 1.54 $ 1.48 Earnings Per Common Share, Diluted $ 0.40 $ 0.32 $ 1.54 $ 1.48

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Segment Information	Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following two reportable segments: • Networks: includes all of the energy transmission and distribution activities, any other regulated activity originating in New York and Maine and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. Based on the quantitative assessment and due to the disposition of gas trading and storage businesses (see Note 20 – Assets Held For Sale for further discussion) the Gas business no longer meets the reportable segment criteria effective in the first quarter of 2018. Additionally, to better align the evaluation of the segment information for both internal and external purposes, effective in the second quarter of 2018, the evaluation of the segments performance by the chief operating decision maker was changed from adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) used in the prior periods to adjusted net income. As a result, the prior period segment information has been restated to conform to the 2018 presentation. We define adjusted net income as net income adjusted to exclude restructuring charges, mark-to-market adjustments to reflect the effect of mark-to-market changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity, loss from held for sale measurement, income from release of collateral, impact of the Tax Act and adjustments for the non-core Gas business. Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense, and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the condensed consolidated financial statements. Segment information for the three months ended September 30, 2018 , consisted of: Three Months Ended September 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,232 $ 315 $ (1 ) $ 1,546 Revenue - intersegment (4 ) — 4 — Loss from assets held for sale — — 1 1 Depreciation and amortization 128 98 — 226 Operating income 207 40 6 253 Earnings (losses) from equity method investments 4 (3 ) — 1 Interest expense, net of capitalization 64 13 (2 ) 75 Income tax expense (benefit) 31 2 (4 ) 29 Adjusted net income 96 33 10 139 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the three months ended September 30, 2018 , are: $1,038 million from regulated electric operations, $188 million from regulated gas operations and $6 million from other operations of Networks; $315 million primarily from renewable energy generation of Renewables. Segment information for the three months ended September 30, 2017 , consisted of: Three Months Ended September 30, 2017 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,126 $ 241 $ (26 ) $ 1,341 Revenue - intersegment (1 ) — 1 — Depreciation and amortization 119 80 6 205 Operating income (loss) 236 2 (20 ) 218 Earnings (losses) from equity method investments 5 (5 ) — — Interest expense, net of capitalization 62 7 2 71 Income tax expense (benefit) 57 (23 ) (2 ) 32 Adjusted net income 106 17 1 125 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the three months ended September 30, 2017 , are: $941 million from regulated electric operations, $181 million from regulated gas operations and $4 million from other operations of Networks; $241 million primarily from renewable energy generation of Renewables. Segment information as of and for the nine months ended September 30, 2018 , consisted of: Nine Months Ended September 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 3,884 $ 894 $ 35 $ 4,813 Revenue - intersegment 1 2 (3 ) — Loss from assets held for sale — — 16 16 Depreciation and amortization 374 270 — 644 Operating income 734 139 5 878 Earnings (losses) from equity method investments 10 (2 ) — 8 Interest expense, net of capitalization 189 28 2 219 Income tax expense (benefit) 118 (30 ) 40 128 Adjusted net income (loss) 376 147 (13 ) 511 Capital expenditures 873 300 — 1,173 As of September 30, 2018 Property, plant and equipment 14,385 8,732 8 23,125 Equity method investments 142 209 — 351 Total assets $ 21,674 $ 10,516 $ (435 ) $ 31,755 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the nine months ended September 30, 2018 , are: $2,857 million from regulated electric operations, $1,030 million from regulated gas operations and $(3) million from other operations of Networks; $894 million primarily from renewable energy generation of Renewables. Segment information for the nine months ended September 30, 2017 , consisted of: Nine Months Ended September 30, 2017 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 3,651 $ 789 $ (10 ) $ 4,430 Revenue - intersegment — 4 (4 ) — Depreciation and amortization 352 238 18 608 Operating income (loss) 826 108 (37 ) 897 Earnings (losses) from equity method investments 12 (9 ) — 3 Interest expense, net of capitalization 183 23 4 210 Income tax expense (benefit) 229 (38 ) (12 ) 179 Adjusted net income 374 114 6 494 Capital expenditures 842 855 7 1,704 As of December 31, 2017 Property, plant and equipment 13,876 8,786 7 22,669 Equity method investments 147 205 — 352 Total assets $ 21,411 $ 11,308 $ (1,048 ) $ 31,671 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Included in revenue-external for the nine months ended September 30, 2017 , are: $2,683 million from regulated electric operations, $966 million from regulated gas operations and $2 million from other operations of Networks; $789 million primarily from renewable energy generation of Renewables. Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and nine months ended September 30, 2018 and 2017 , respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 139 $ 125 $ 511 $ 494 Adjustments: Loss from assets held for sale (1) (1 ) — (16 ) — Mark-to-market adjustments - Renewables (2) (10 ) (4 ) (9 ) 2 Restructuring charges (3) (1 ) (3 ) (2 ) (3 ) Income from release of collateral - Renewables (4) (7 ) — — — Impact of the Tax Act (5) — — (7 ) — Income tax impact of adjustments 5 2 (11 ) — Gas Storage, net of tax (6) — (21 ) 10 (35 ) Net Income Attributable to Avangrid, Inc. $ 125 $ 99 $ 476 $ 458 (1) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses (See Note 20 - Assets Held for Sale – for further details). (2) Mark-to-market adjustments relate to changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity and gas. (3) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment (See Note 19 - Restructuring and Severance Related Expenses – for further details). (4) Relates to cash collateral released in excess of outstanding receivables from a bankruptcy proceeding with a Renewables customer regarding two power purchase agreements. (5) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (6) Removal of the impact from Gas activity in the reconciliation to the AVANGRID Net Income.

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Related Party Transactions	Related Party Transactions We engage in related party transactions that are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ (8 ) Iberdrola Renovables Energía, S.L. — (3 ) — (2 ) Iberdrola, S.A. — (10 ) 1 (10 ) Iberdrola Energia Monterrey, S.A. de C.V. — — 14 — Other 3 (2 ) 1 — Nine Months Ended September 30, 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (4 ) $ — $ (28 ) Iberdrola Renovables Energía, S.L. — (10 ) — (7 ) Iberdrola, S.A. — (36 ) 1 (28 ) Iberdrola Energia Monterrey, S.A. de C.V. 3 — 43 — Other 4 (3 ) 2 (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 $2 million and $266 million for the periods ended September 30, 2018 and December 31, 2017 , respectively. Related party balances as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 December 31, 2017 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ — $ (1 ) $ — $ (31 ) Siemens-Gamesa — (11 ) 2 (51 ) Iberdrola, S.A. — (36 ) 1 (32 ) Iberdrola Renovables Energía, S.L. — (10 ) — — Iberdrola Energia Monterrey, S.A. de C.V. — — 1 — Other 3 (2 ) 6 (4 ) Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. Transactions with Iberdrola Canada Energy Services (ICES) predominantly relate to the purchase of gas for ARHI’s gas-fired cogeneration facility in Klamath, Oregon. Included in the amounts owed to ICES are notes payable of $0 and $29 million as of September 30, 2018 and December 31, 2017 , respectively. Transactions with Iberdrola Energia Monterrey predominantly relate to the sale of gas by Enstor Gas for the power generation plant in Monterrey, Mexico. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances. Networks holds an approximate 20% ownership interest in the regulated New York TransCo, LLC (New York TransCo). Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. As of September 30, 2018 and December 31, 2017 , the amount receivable from New York TransCo was $1 million and $6 million , respectively. Renewables holds a 50% ownership in Vineyard Wind, LLC (Vineyard), a joint venture with Copenhagen Infrastructure Partners. Vineyard acquired a lease from the U.S. Bureau of Ocean Energy Management containing rights to develop offshore wind generation in a 260 square mile area located southeast of Martha’s Vineyard. The leased area has the capacity for siting up to approximately 3,000 MW. In May 2018, Vineyard was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard’s proposed 800 MW wind farm and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. We account for Vineyard under the equity method of accounting. Under the provisions of the LLC agreement, Renewables has committed $92 million in total contributions, of which $42 million has been funded to date. As of September 30, 2018 the amount receivable from Vineyard was $ 1.3 million. There was no amount receivable from Vineyard as of December 31, 2017 . AVANGRID manages its overall liquidity position as part of the 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 September 30, 2018 and December 31, 2017 , was zero . On June 18, 2018, AVANGRID entered into a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023 . AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of September 30, 2018 , there was no outstanding amount under this credit facility.

Supplemental Balance Sheet Info

Supplemental Balance Sheet Information	9 Months Ended
	Sep. 30, 2018
Balance Sheet Related Disclosures [Abstract]
Supplemental Balance Sheet Information	Supplemental Balance Sheet Information Accounts receivable Accounts receivable include amounts due under deferred payment arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. The utility company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as current. We establish provisions for uncollectible accounts for DPAs by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collection efforts have been exhausted. DPA receivable balances were $66 million and $55 million at September 30, 2018 and December 31, 2017 , respectively. The allowance for doubtful accounts for DPAs at September 30, 2018 and December 31, 2017 , was $33 million and $30 million , respectively. Furthermore, the provision for bad debts associated with the DPAs for the three and nine months ended September 30, 2018 was $1 million and $3 million , respectively, and for the three and nine months ended September 30, 2017 was $0 and $3 million , respectively. Prepayments and other current assets Included in prepayments and other current assets are $210 million and $194 million of prepaid other taxes as of September 30, 2018 and December 31, 2017 , respectively. Property, plant and equipment and intangible assets The accumulated depreciation and amortization as of September 30, 2018 and December 31, 2017 , respectively, were as follows: September 30, December 31, As of 2018 2017 (Millions) Property, plant and equipment Accumulated depreciation $ 8,238 $ 7,497 Intangible assets Accumulated amortization $ 287 $ 276

Income Tax Expense

Income Tax Expense	9 Months Ended
	Sep. 30, 2018
Income Tax Disclosure [Abstract]
Income Tax Expense	Income Tax Expense The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2018 , were 17.8% and 21.0% , respectively, which, for the three months ended September 30, 2018 is lower than the 21% statutory federal income tax rate applicable in 2018, predominantly due to discrete tax adjustments recorded during the period offset by the recognition of production tax credits associated with wind production, and for the nine months ended September 30, 2018 is in line with the 21% statutory federal income tax rate applicable in 2018, predominantly due to $22.1 million of tax expense recorded in connection with the disposal of the Gas business and discrete adjustments recorded during the period offset by the recognition of production tax credits associated with wind production. The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2017 , were 24.2% and 28.1% , respectively, which were lower than the 35% statutory federal income tax rate applicable in 2017, predominantly due to the recognition of production tax credits associated with wind production in both periods. Additionally, $14 million in income tax expense for the nine months ended September 30, 2017 , is due to unfunded future income tax to reflect the change from a flow through to normalization method, which was recorded as an increase to revenue, with an offsetting and equal increase to income tax expense. This was offset by other discrete tax adjustments during the period. Upon enactment of the Tax Act, the Company remeasured its existing deferred income tax balances as of December 31, 2017 to reflect the decrease in the corporate income tax rate from 35% to 21% , which resulted in a material decrease to its net deferred income tax liability balances. In connection with the Tax Act, the U.S. Securities and Exchange Commission issued guidance in Staff Accounting Bulletin 118 (SAB 118), which clarified accounting for income taxes under ASC 740, Income Taxes, if information was not yet available or complete and provided up to a one year measurement period in which to complete the required analyses and accounting. Following SAB 118 guidance, the Company recorded provisional income tax amounts as of December 31, 2017 related to the Tax Act based on reasonable estimates that could be determined at that time. As of September 30, 2018 , we are continuing to refine our accounting for income taxes related to the Tax Act and no material impacts have been recorded for the three and nine months ended September 30, 2018 . The main items we are working to finalize relate to estimates of the income tax accounting for plant related adjustments impacting our Networks entities. The Company expects final adjustments to the provisional amounts to be recorded in the fourth quarter of 2018 and the adjustments could be material to the Company’s future results of operations or financial positions.

Stock-Based Compensation Expens

Stock-Based Compensation Expense	9 Months Ended
	Sep. 30, 2018
Disclosure of Compensation Related Costs, Share-based Payments [Abstract]
Stock-Based Compensation Expense	Stock-Based Compensation Expense Pursuant to the 2016 Avangrid, Inc. Omnibus Incentive Plan, 34,361 additional performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in March and June 2018. The PSUs will vest upon achievement of certain performance- and market-based metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020 , 2021 and 2022 . The fair value on the grant date was determined based on $31.80 per share. In June 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan 60,000 restricted stock units (RSUs) were granted to the Chief Executive Officer of AVANGRID. The RSUs vest in full in one installment on the date of AVANGRID’s regular annual shareholders meeting occurring in calendar year 2020, provided that the award holder remains continuously employed with AVANGRID through such date. The fair value on the grant date was determined based on $50.40 per share. The total stock-based compensation expense, which is included in operations and maintenance of the condensed consolidated statements of income, for the three and nine months ended September 30, 2018 was $0.8 million and $1.2 million , respectively, and for the three and nine months ended September 30, 2017 was $1.4 million and $5.3 million , respectively. Before 2016, AVANGRID’s historical stock-based compensation expense and liabilities were based on shares of Iberdrola and not on shares of AVANGRID. These Iberdrola shares-based awards were early terminated at the end of 2015, and the remaining liability was settled in March 2018 . The total liability relating to those awards, which was included in other current liabilities, was $5.5 million as of December 31, 2017 .

Variable Interest Entities

Variable Interest Entities	9 Months Ended
	Sep. 30, 2018
Variable Interest Entities [Abstract]
Variable Interest Entities	Variable Interest Entities We participate in certain partnership arrangements 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 does not have substantive kick-out or participating rights. The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest in the condensed consolidated balance sheets valued based on a HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in the condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs. The assets and liabilities of the VIEs totaled approximately $1,418 million and $66 million , respectively, at September 30, 2018 . As of December 31, 2017 , the assets and liabilities of VIEs totaled approximately $1,441 million and $185 million , respectively. At September 30, 2018 and December 31, 2017 , the assets and liabilities of the VIEs consisted primarily of property, plant and equipment, equity method investments and TEF liabilities. At September 30, 2018 and December 31, 2017 , equity method investments of VIEs were approximately $101 million and $107 million , respectively. In May 2018, tax equity financing was completed on El Cabo Wind, LLC (El Cabo) through contributions of $213 million from the tax equity investors. In addition to El Cabo, at September 30, 2018 , we consider Aeolus Wind Power II LLC and Aeolus Wind Power IV LLC (collectively, Aeolus) to be VIEs. 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. 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. 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 and El Cabo interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests.

Restructuring and Severance Rel

Restructuring and Severance Related Expenses	9 Months Ended
	Sep. 30, 2018
Restructuring and Related Activities [Abstract]
Restructuring and Severance Related Expenses	Restructuring and Severance Related Expenses In 2017, we announced initial targeted voluntary workforce reductions predominantly within the Networks segment. Those actions primarily include: reducing our workforce through voluntary programs in various areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology (IT) workforce to make increasing use of external services for operations, support, and development of systems. Those decisions and transactions resulted in restructuring charges of $0.9 million and $2.1 million recorded in the three and nine months ended September 30, 2018 , respectively, and of $2.1 million recorded in both the three and nine month periods ended September 30, 2017, for severance expenses, which are included in operations and maintenance in the condensed consolidated statements of income, and approximately $ 0.5 million of accelerated amortization of leasehold improvements recorded in both the three and nine month periods ended September 30, 2017, which are included in depreciation and amortization in the condensed consolidated statements of income. The remaining costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods through December 2018. Accordingly, the Company expects additional costs to be incurred in 2018 related to the remaining employee service periods under the severance plans. In the nine months ended September 30, 2018 , the severance and lease restructuring charges reserves, which are recorded in other current liabilities and other liabilities, consisted of: Nine Months Ended September 30, 2018 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 2 Payments (3 ) Ending Balance $ 4

Assets Held for Sale

Assets Held for Sale	9 Months Ended
	Sep. 30, 2018
Assets Held-for-sale, Not Part of Disposal Group [Abstract]
Assets Held for Sale	Assets Held For Sale In December 2017, our management committed to a plan to sell the gas trading and storage businesses because they represented non-core businesses that were not aligned with our strategic objectives. At that time, we determined that the assets and liabilities associated with our gas trading and storage businesses met the criteria for classification as assets held for sale, but did not meet the criteria for classification as discontinued operations. On March 1, 2018 , the Company closed a transaction to sell Enstor Energy Services, LLC, which operated AVANGRID’s gas trading business, to CCI U.S. Asset Holdings LLC, a subsidiary of Castleton Commodities International, LLC for $66 million , subject to working capital, cash and other adjustments. The transaction price did not differ materially from the estimated fair value of our gas trading business at December 31, 2017 , but is subject to adjustment based on closing and other contract provisions, including certain transition services. On May 1, 2018 , the Company closed a transaction to sell Enstor Gas, LLC, which operated AVANGRID’s gas storage business, to Amphora Gas Storage USA, LLC for $66 million , subject to working capital, cash, and other adjustments. The 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. In connection with the held for sale classification, we recorded a loss from held for sale measurement of $0.5 million and $15.6 million in the three and nine months ended September 30, 2018 , respectively, which is included in Loss from assets held for sale in the condensed consolidated statements of income related to final purchase price negotiations and certain related working capital adjustments. Income (loss) before income tax, adjusted for corporate overhead, attributed to the gas businesses was $(0.3) million and $4.2 million for the three and nine months ended September 30, 2018 , respectively, and $(33.7) million and $(54.6) million for the three and nine months ended September 30, 2017 , respectively. 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 : December 31, As of 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.

Significant Accounting Polici_2

Significant Accounting Policies and New Accounting Pronouncements (Policies)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
New Accounting Pronouncements	Adoption of New Accounting Pronouncements (a) Revenue from contracts with customers In May 2014, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC), Topic 606, Revenue from Contracts with Customers (ASC 606) replacing the existing accounting standard and industry specific guidance for revenue recognition with a five-step model for recognizing and measuring revenue from contracts with customers. The FASB further amended ASC 606 through various updates issued thereafter. The core principle is for an entity to recognize revenue to represent the transfer of promised goods or services to customers in amounts that reflect the consideration to which the entity expects to be entitled in exchange for those goods or services. We adopted ASC 606 effective January 1, 2018, and applied the modified retrospective method, for which we did not have a cumulative effect adjustment to retained earnings for initial application of the guidance. Refer to Note 4 for further details. (b) Clarifying the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets The FASB issued amendments in February 2017 concerning asset derecognition and partial sales of nonfinancial assets. The amendments clarify the scope of asset derecognition guidance and accounting for partial sales of nonfinancial assets, and also define in-substance nonfinancial assets. Those amendments apply to a company that: sells nonfinancial assets (land, buildings, materials and supplies, intangible assets) to noncustomers; sells nonfinancial assets and financial assets (cash, receivables) when the value is concentrated in the nonfinancial assets; or sells partial ownership interests in nonfinancial assets. The amendments do not apply to sales to customers or to sales of businesses. The new guidance in ASC 610-20 on accounting for derecognition of a nonfinancial asset and an in-substance nonfinancial asset applies only when the asset (or asset group) does not meet the definition of a business and is not a not-for-profit activity. An entity must apply the amendments at the same time that it applies the new ASC 606 revenue recognition standard. We adopted ASC 610-20 effective January 1, 2018, and applied the modified retrospective method, which affected the accounting for our tax equity investments. As shown in the table below, we recorded a cumulative adjustment that decreased retained earnings. The cumulative adjustment relates to the reclassification of our tax equity investments to noncontrolling interests. As a result, we recorded our tax equity investments based on the Hypothetical Liquidation at Book Value (HLBV) accounting method and we will record changes in the HLBV at each reporting period within net income/loss attributable to noncontrolling interests. The cumulative effects of the changes to our consolidated balance sheet as of January 1, 2018, for our adoption of ASC 606 and ASC 610-20 were as follows: Balance Sheet Balance at December 31, 2017 Adjustments Due to ASC 606 Adjustments Due to ASC 610-20 Balance at (Millions) Liabilities Tax equity financing arrangements - VIEs $ 98 $ — $ (98 ) $ — Deferred income taxes 1,452 — (40 ) 1,412 Equity Retained earnings 1,475 — (2 ) 1,473 Non-controlling interests $ 19 $ — $ 140 $ 159 We also adopted the following standards as of their effective date of January 1, 2018, none of which had a material effect on our consolidated results of operations, financial position, cash flows, and disclosures. (c) Classifying and measuring financial instruments In January 2016, the FASB issued final guidance on the classification and measurement of financial instruments. As a result of our adoption we reclassified immaterial amounts from AOCI to retained earnings. (d) Certain classifications in the statement of cash flows In August 2016, the FASB issued amendments to address existing diversity in practice concerning the classification of certain cash receipts and payments on the statement of cash flows, which must be applied on a full retrospective basis. Upon adoption, we had no changes to our cash flow classifications and disclosures in our consolidated financial statements. (e) Improving the presentation of net periodic benefit costs In March 2017, the FASB issued amendments to improve the presentation of net periodic pension cost and net periodic postretirement benefit cost in the financial statements. We retrospectively adopted the amendments that require us to present the service cost component separately from the other (non-service) components of net benefit cost, to report the service cost component in the income statement line item where we report the corresponding compensation cost, and to present all non-service components outside of operating cost. As a result, we have reclassified the non-service components – interest cost, expected return on plan assets, amortization of prior service cost (benefit), amortization of net loss, and settlement charge – from Operations and maintenance to Other income/(expense) within the statement of income. Prospectively, from adoption, we will capitalize only the service cost component when applicable (for example, as a cost of a self-constructed asset). We elected to apply the practical expedient that allows us to retrospectively apply the amendments on adoption to net benefit costs for comparative periods by using the amounts disclosed in our notes to financial statements for Post-retirement and Similar Obligations as the basis for those periods. In addition to those amounts, we included amortization of net benefit costs recorded as regulatory deferrals as a result of purchase accounting in a prior year. In connection with applying the practical expedient, in periods after adoption we will continue to include in operating income all legacy net benefit costs previously capitalized as a cost of self-constructed assets and other deferred regulatory costs. Our adoption of the amendments did not affect prior period net income attributable to AVANGRID. Beginning in 2018, non-service cost components incurred by the Networks utilities are no longer eligible for construction capitalization, but such costs can be deferred and included as a component of customer rates if permitted by their regulator. For the three and nine months ended September 30, 2018 , immaterial additional expense has been incurred as a result of the adoption of this standard. The effect of the change in retrospective presentation related to the net periodic cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated statement of income was as follows: Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Statement of Income As Revised As Previously Reported Effect of Change Higher / (Lower) As Revised As Previously Reported Effect of Change Higher / (Lower) (Millions) Operations and maintenance $ 531 $ 560 $ (29 ) $ 1,546 $ 1,633 $ (87 ) Other income / (expense) $ (15 ) $ 14 $ (29 ) $ (52 ) $ 35 $ (87 ) We have also revised the segment information related to our Networks reportable segment provided in Note 13 for the three and nine months ended September 30, 2017 , to reflect the change as a result of the adoption of these amendments. Accounting Pronouncements Issued But Not Yet Adopted The following are new accounting pronouncements issued since December 31, 2017 , that we have evaluated or are evaluating to determine their effect on our consolidated financial statements. (a) Leases, amendments and updates In January 2018, the FASB issued amendments to clarify the application of the new leases guidance to land easements (also commonly called rights of way) and provide relief concerning adoption efforts for existing land easements that are not accounted for as leases under current GAAP. The updated guidance is effective for public entities for fiscal years beginning after December 15, 2018, including interim periods within those fiscal years, and early application is permitted. We are still assessing our election of the land easement practical expedient, which could materially affect our financial position if we do not elect it, primarily because of the volume of existing land contacts not accounted for as leases under current GAAP. In July 2018, the FASB issued a number of technical corrections and improvements to the new leases guidance, which affect narrow aspects of the guidance and are effective as noted above. We continue to assess the corrections and improvements, but do not expect they will have a significant effect upon adoption. Also, in July 2018 the FASB issued amendments to the leases standard to allow entities an additional option for transition. The guidance currently requires a modified retrospective transition method of adoption, under which lessees and lessors are to recognize and measure leases at the beginning of the earliest comparative period presented. The additional, optional transition method allows an entity to initially apply the requirements of the leases standard at the adoption date. If an entity adopts the optional transition method, it would not restate amounts reported for comparative periods presented in the consolidated financial statements, and not provide disclosures required under the new standard for dates and periods before January 1, 2019. We continue to assess the additional transition option to decide which method to adopt based on the outcome of our implementation plan and steps, described below. We continue to review our contracts and continue to execute a broad implementation plan as we prepare for our adoption of the new leases guidance on January 1, 2019. The key components of our implementation plan and steps that have been underway include: 1) uploading complete and pertinent lease contract data into a new accounting system that integrates with existing systems; 2) identifying, evaluating and documenting related technical accounting issues, industry implementation issues, policy considerations and financial reporting implications; 3) identifying and implementing changes to processes and controls to ensure all aspects of the new guidance are effectively addressed; and 4) simulating the effects of the leases standard to assess the expected impact upon adoption and to finalize transition option and practical expedient selections. Through September 2018, we have substantially completed step 1; including our final reviews of information and lease contract data uploaded in the new accounting system database, and validating the simulation and outputs from the new lease accounting system. We have also completed preliminary system configuration and testing is in process, which has allowed us to simulate our lease contracts under the new lease standard using different assumptions with practical expedients and transition options to make appropriate decisions upon adoption. In other respects, we continue to make progress with Steps 2 through 4 and plan to complete them in the fourth quarter of 2018. We expect an increase in assets, the corresponding liabilities and additional disclosures as a result of our adoption of the new leases guidance. However, we do not expect significant changes to our pattern of expense recognition. Also, we do not expect a significant change in our leasing activities between now and adoption. (b) Reclassification of certain tax effects from accumulated other comprehensive income In February 2018, the FASB issued amendments to address a narrow-scope financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) enacted on December 22, 2017, by the U.S. federal government. Under current guidance, the adjustment of deferred taxes for the effect of a change in tax laws or rates is required to be included in income from continuing operations, thus the associated tax effects of items within accumulated OCI (referred to as stranded tax effects) do not reflect the appropriate tax rate. The amendments allow a reclassification from accumulated OCI 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 accumulated OCI to earnings (specific identification or portfolio method). We have not early adopted the amendments as of September 30, 2018 . We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows and disclosures. (c) Changes to the disclosure requirements for fair value measurement and defined benefit plans In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans. The amendments concerning fair value measurement remove, modify and add certain disclosure requirements, in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. The amendments to fair value measurement disclosures are effective for all entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted as specified. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively. We have not early adopted the amendments as of September 30, 2018. We do not expect our adoption of the amendments to materially affect our disclosures. The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. They remove disclosures that are no longer considered cost beneficial, add certain new relevant disclosures and clarify specific requirements of disclosures concerning information for defined benefit pension plans. The amendments to defined benefit plan disclosures are effective for fiscal years ending after December 15, 2020. Early adoption is permitted and application is to be on a retrospective basis. We have not early adopted the amendments as of September 30, 2018. We do not expect our adoption of the amendments to materially affect our disclosures. (d) Customer accounting for implementation costs incurred in a cloud computing arrangement The FASB issued amendments in August 2018 to clarify the accounting for implementation costs of a cloud computing arrangement (also referred to as a hosting arrangement) that is a service contract. Implementation costs, which include implementation, setup and other upfront costs, are either to be deferred or expensed as incurred, in accordance with existing internal-use software guidance for similar costs. The amendments require a customer to expense capitalized implementation costs over the contractual term of the arrangement, including any optional renewal periods the customer is reasonably certain it will exercise. An entity is to present deferred implementation costs on the balance sheet, income statement and cash flows consistent with the subscription fees associated with the arrangement. The amendments enhance disclosures to include certain qualitative and quantitative information about implementation costs for internal-use software and all hosting arrangements, not just hosting arrangements that are service contracts. The amendments are effective for public business entities for fiscal years beginning after December 15, 2019, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued. An entity may apply the amendments either retrospectively or prospectively to all implementation costs incurred after the date of adoption. We have not early adopted the amendments as of September 30, 2018. We expect our adoption of the amendments will not materially affect our consolidated results of operations, financial position, cash flows and disclosures.

Significant Accounting Polici_3

Significant Accounting Policies and New Accounting Pronouncements (Tables)	9 Months Ended
	Sep. 30, 2018
Accounting Policies [Abstract]
Schedule of Cumulative Effects of Changes to Consolidated Balance Sheet	The cumulative effects of the changes to our consolidated balance sheet as of January 1, 2018, for our adoption of ASC 606 and ASC 610-20 were as follows: Balance Sheet Balance at December 31, 2017 Adjustments Due to ASC 606 Adjustments Due to ASC 610-20 Balance at (Millions) Liabilities Tax equity financing arrangements - VIEs $ 98 $ — $ (98 ) $ — Deferred income taxes 1,452 — (40 ) 1,412 Equity Retained earnings 1,475 — (2 ) 1,473 Non-controlling interests $ 19 $ — $ 140 $ 159
Effect of Change in Retrospective Presentation Related to Net Periodic Cost	The effect of the change in retrospective presentation related to the net periodic cost of our defined benefit pension and other postretirement employee benefits plans on our consolidated statement of income was as follows: Three Months Ended September 30, 2017 Nine Months Ended September 30, 2017 Statement of Income As Revised As Previously Reported Effect of Change Higher / (Lower) As Revised As Previously Reported Effect of Change Higher / (Lower) (Millions) Operations and maintenance $ 531 $ 560 $ (29 ) $ 1,546 $ 1,633 $ (87 ) Other income / (expense) $ (15 ) $ 14 $ (29 ) $ (52 ) $ 35 $ (87 )

Revenue (Tables)

Revenue (Tables)	9 Months Ended
	Sep. 30, 2018
Revenue from Contract with Customer [Abstract]
Schedule of Revenues Disaggregated by Major Source for Reportable Segments	Revenues disaggregated by major source for our reportable segments for the three and nine months ended September 30, 2018 are as follows: Three Months Ended September 30, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 1,010 $ — $ — $ 1,010 Regulated operations – natural gas 169 — — 169 Nonregulated operations – wind — 198 — 198 Nonregulated operations – solar — 4 — 4 Nonregulated operations – thermal — 22 — 22 Nonregulated operations – gas storage — — 1 1 Other (a) 14 (25 ) 2 (9 ) Revenue from contracts with customers 1,193 199 3 1,395 Leasing revenue 9 76 — 85 Derivative revenue — 40 — 40 Alternative revenue programs 22 — — 22 Other revenue 4 — — 4 Total operating revenues $ 1,228 $ 315 $ 3 $ 1,546 Nine Months Ended September 30, 2018 Networks Renewables Other (b) Total (Millions) Regulated operations – electricity $ 2,736 $ — $ — $ 2,736 Regulated operations – natural gas 1,007 — — 1,007 Nonregulated operations – wind — 546 — 546 Nonregulated operations – solar — 12 — 12 Nonregulated operations – thermal — 36 — 36 Nonregulated operations – gas storage — — 11 11 Other (a) 45 (58 ) 11 (2 ) Revenue from contracts with customers 3,788 536 22 4,346 Leasing revenue 27 255 — 282 Derivative revenue — 105 10 115 Alternative revenue programs 66 — — 66 Other revenue 4 — — 4 Total operating revenues $ 3,885 $ 896 $ 32 $ 4,813 (a) Primarily includes certain intra-month trading activities, billing, collection, and administrative charges, sundry billings, and other miscellaneous revenue. (b) Does not represent a segment. Includes Corporate, Gas and intersegment eliminations.
Schedule of Aggregate Transaction Price Allocations	As of September 30, 2018 , accounts receivable balances related to contracts with customers were approximately $1,015 million , which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets. As of September 30, 2018 , for contracts with durations greater than one year (1) the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied), and (2) when we expect to recognize the revenue, were as follows: As of September 30, 2018 2019 2020 2021 2022 2023 Thereafter Total (Millions) Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 7 $ 8 $ 9 $ 9 $ 9 $ 25 $ 67 Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 14 8 3 3 3 1 32 Revenue expected to be recognized on multiyear renewable energy credit sale contracts 20 12 9 5 4 12 62 Total operating revenues $ 41 $ 28 $ 21 $ 17 $ 16 $ 38 $ 161

Regulatory Assets and Liabili_2

Regulatory Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2018
Regulated Operations [Abstract]
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 24 $ 24 Pension and other post-retirement benefits 12 7 Storm costs 65 46 Rate adjustment mechanism 17 — Reliability support services 19 27 Revenue decoupling mechanism 10 21 Transmission revenue reconciliation mechanism 7 8 Electric supply reconciliation 7 — Hedges losses — 3 Contracts for differences 8 9 Hardship programs 13 14 Deferred property tax 10 10 Plant decommissioning 6 6 Deferred purchased gas 12 31 Deferred transmission expense 16 37 Environmental remediation costs 14 13 Other 44 51 Total Current Regulatory Assets 284 307 Non-current Pension and other post-retirement benefits cost deferrals 116 110 Pension and other post-retirement benefits 1,035 1,162 Storm costs 296 254 Deferred meter replacement costs 27 29 Unamortized losses on reacquired debt 16 17 Environmental remediation costs 270 283 Unfunded future income taxes 369 376 Asset retirement obligation 19 18 Deferred property tax — 14 Federal tax depreciation normalization adjustment 152 155 Merger capital expense target customer credit 1 2 Debt premium 120 131 Reliability support services — 10 Plant decommissioning 7 9 Contracts for differences 90 84 Hardship programs 9 13 Deferred income taxes regulatory 44 — Other 64 71 Total Non-current Regulatory Assets $ 2,635 $ 2,738
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Current Non by-passable charges $ 6 $ 5 Energy efficiency portfolio standard 56 37 Gas supply charge and deferred natural gas cost 2 4 Transmission revenue reconciliation mechanism 6 14 Pension and other post-retirement benefits — 1 Pension and other post-retirement benefits cost deferrals 14 14 Carrying costs on deferred income tax bonus depreciation 23 21 Carrying costs on deferred income tax - Mixed Services 263(a) 5 5 Yankee DOE Refund — 4 Merger related rate credits — 1 Revenue decoupling mechanism 4 4 Stranded costs 3 17 Hedges gains 7 — Other 68 51 Total Current Regulatory Liabilities 194 178 Non-current Accrued removal obligations 1,145 1,132 2017 Tax Act 1,566 1,515 Asset sale gain account 10 10 Carrying costs on deferred income tax bonus depreciation 55 72 Economic development 28 32 Merger capital expense target customer credit account 6 6 Pension and other post-retirement benefits cost deferrals 63 74 Positive benefit adjustment 37 39 New York state tax rate change 4 6 Theoretical reserve flow thru impact 15 19 Deferred property tax 24 19 Net plant reconciliation 19 10 Variable rate debt 42 33 Carrying costs on deferred income tax - Mixed Services 263(a) 16 20 Rate refund – FERC ROE proceeding 27 27 Transmission congestion contracts 21 19 Merger-related rate credits 18 20 Accumulated deferred investment tax credits 13 13 Asset retirement obligation 12 13 Earning sharing provisions 17 22 Middletown/Norwalk local transmission network service collections 18 19 Excess generation service charge 10 2 Low income programs 35 42 Non-firm margin sharing credits 13 8 Deferred income taxes regulatory — 13 Other 71 67 Total Non-current Regulatory Liabilities $ 3,285 $ 3,252

Fair Value of Financial Instr_2

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2018
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 12 15 76 (33 ) 70 Derivative financial instruments - gas — 7 42 (49 ) — Contracts for differences — — 7 — 7 Derivative financial instruments – other — 4 — — 4 Total 12 26 125 (82 ) 81 Derivative liabilities Derivative financial instruments - power (8 ) (16 ) (22 ) 40 (6 ) Derivative financial instruments - gas — (8 ) (9 ) 12 (5 ) Contracts for differences — — (105 ) — (105 ) Derivative financial instruments – other — (3 ) — — (3 ) Total $ (8 ) $ (27 ) $ (136 ) $ 52 $ (119 ) 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 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input September 30, 2018 Risk of non-performance 0% - 0.59% Discount rate 2.59% - 3.05% Forward pricing ($ per KW-month) $4.30 - $9.55 Included in the derivative financial instruments – gas are derivative assets and liabilities of the Gas segment classified as held for sale on the condensed consolidated balance sheet as of December 31, 2017 . See Note 20 – Assets Held For Sale for further discussion. The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2018 and 2017 , respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2018 2017 2018 2017 Fair Value Beginning of Period, $ (1 ) $ 32 $ 6 $ 31 Gains recognized in operating revenues — 9 11 20 (Losses) recognized in operating revenues (5 ) — (8 ) (3 ) Total (losses) gains recognized in operating revenues (5 ) 9 3 17 Gains recognized in OCI — 1 — 2 (Losses) recognized in OCI (1 ) — (1 ) (1 ) Total (losses) gains recognized in OCI (1 ) 1 (1 ) 1 Net change recognized in regulatory assets and liabilities 2 2 (6 ) 4 Purchases (3 ) 5 (6 ) 3 Settlements (3 ) (3 ) (7 ) (10 ) Fair Value as of September 30, $ (11 ) $ 46 $ (11 ) $ 46 Gains (losses) for the period included in operating revenues attributable to the change in unrealized gains (losses) relating to financial instruments still held at the reporting date $ (5 ) $ 9 $ 3 $ 17
Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques	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 September 30, 2018 Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power Transactions with Transactions are Observable and NYMEX ($/MMBtu) $ 2.94 $ 3.93 $ 2.44 with delivery exceeding two on a corroborated by Indiana hub ($/MWh) $ 30.62 $ 53.90 $ 19.10 period > two years discounted market data for identical or Mid C ($/MWh) $ 23.31 $ 57.00 $ (0.50 ) years basis similar products Minn hub ($/MWh) $ 25.18 $ 49.85 $ 12.51

Derivative Instruments and He_2

Derivative Instruments and Hedging (Tables)	9 Months Ended
	Sep. 30, 2018
Derivative Instruments and Hedging Activities Disclosure [Abstract]
Summary of Unrealized Gains and Losses from Fair Value Adjustments	The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three and nine months ended September 30, 2018 and 2017 , respectively, were as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Derivative assets $ (1 ) $ (2 ) $ (5 ) $ (6 ) Derivative liabilities $ 2 $ 4 $ (1 ) $ 10
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (MWh/Dth in millions) Wholesale electricity purchase contracts 3 4 Wholesale electricity sales contracts 5 6 Natural gas and other fuel purchase contracts 22 285 Financial power contracts 10 12 Basis swaps – purchases 33 68 Basis swaps – sales 1 62 The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts (MWh) 4.0 3.9 Natural gas purchase contracts (Dth) 7.7 6.1 Fleet fuel purchase contracts (Gallons) 2.0 2.1
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts	The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Renewables and Gas activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 17 $ 96 $ 12 $ 8 Derivative liabilities (2 ) (4 ) (23 ) (18 ) 15 92 (11 ) (10 ) Designated as hedging instruments Derivative assets 1 2 1 4 Derivative liabilities — — (3 ) (5 ) 1 2 (2 ) (1 ) Total derivatives before offset of cash collateral 16 94 (13 ) (11 ) Cash collateral (payable) receivable (9 ) (37 ) 5 8 Total derivatives as presented in the balance sheet $ 7 $ 57 $ (8 ) $ (3 ) 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 (payable) receivable (17 ) (39 ) 3 3 Total derivatives as presented in the balance sheet, including assets and liabilities held for sale $ 36 $ 58 $ (20 ) $ (4 ) The offsetting of derivatives, location in the condensed consolidated balance sheet and amounts of derivatives associated with Networks activities as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 16 $ 3 $ 5 $ 1 Derivative liabilities (5 ) (1 ) (18 ) (95 ) 11 2 (13 ) (94 ) Designated as hedging instruments Derivative assets — — — — Derivative liabilities — — — — — — — — Total derivatives before offset of cash collateral 11 2 (13 ) (94 ) Cash collateral receivable — — — 2 Total derivatives as presented in the balance sheet $ 11 $ 2 $ (13 ) $ (92 ) 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 )
Schedule of Derivative Instruments, Effect of Cash flow Hedging on Other Comprehensive Income and Income	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses — Total $ — $ 2 2017 Interest rate contracts $ — Interest expense $ 2 Commodity contracts — Operating expenses 1 Total $ — $ 3 Nine Months Ended September 30, (Loss) Recognized in OCI on Derivatives Location of Loss Reclassified from Accumulated OCI into Income Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Interest rate contracts $ — Interest expense $ 6 Commodity contracts — Operating expenses — Total $ — $ 6 2017 Interest rate contracts $ — Interest expense $ 6 Commodity contracts (1 ) Operating expenses 1 Total $ (1 ) $ 7 _________________________ (a) Changes in accumulated OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchased power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income. The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives Location of Loss (Gain) Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Commodity contracts $ (3 ) Operating revenues $ (1 ) Total $ (3 ) $ (1 ) 2017 Commodity contracts $ 8 Operating revenues $ 1 Total $ 8 $ 1 Nine Months Ended September 30, (Loss) Gain Recognized in OCI on Derivatives Location of Loss (Gain) Reclassified from Accumulated OCI into Income (Gain) Loss Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2018 Commodity contracts $ (4 ) Operating revenues $ (21 ) Total $ (4 ) $ (21 ) 2017 Commodity contracts $ 12 Operating revenues $ 31 Total $ 12 $ 31 _____________________ (a) Changes in accumulated 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 September 30, 2018 and December 31, 2017 , respectively, consisted of: September 30, December 31, As of 2018 2017 (Millions) Wholesale electricity purchase contracts $ 4 $ (3 ) Wholesale electricity sales contracts — 8 Natural gas and other fuel purchase contracts (1 ) 19 Financial power contracts 54 55 Basis swaps – purchases (4 ) (13 ) Basis swaps – sales — 4 Total $ 53 $ 70
Effect of Derivatives Associated with Renewables and Gas Activities	The effect of trading derivatives associated with Renewables and Gas activities for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Wholesale electricity purchase contracts $ (3 ) $ — $ 3 $ (2 ) Wholesale electricity sales contracts 1 1 — 4 Financial power contracts — (2 ) (2 ) (2 ) Financial and natural gas contracts — — 3 4 Total (Loss) Gain $ (2 ) $ (1 ) $ 4 $ 4 The effect of non-trading derivatives associated with Renewables and Gas activities for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Wholesale electricity purchase contracts $ 1 $ — $ 5 $ (2 ) Wholesale electricity sales contracts — (4 ) (7 ) 2 Financial power contracts (12 ) 2 (11 ) 8 Financial and natural gas contracts 4 (1 ) 8 (6 ) Total (Loss) Gain $ (7 ) $ (3 ) $ (5 ) $ 2

Post-retirement and Similar O_2

Post-retirement and Similar Obligations (Tables)	9 Months Ended
	Sep. 30, 2018
Retirement Benefits [Abstract]
Components of Net Periodic Pension and Postretirement Benefits	The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Service cost $ 11 $ 10 $ 33 $ 32 Interest cost 32 35 96 104 Expected return on plan assets (50 ) (49 ) (150 ) (148 ) Amortization of: Prior service costs — — 1 1 Actuarial loss 38 32 113 95 Net Periodic Benefit Cost $ 31 $ 28 $ 93 $ 84 The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Service cost $ 1 $ 2 $ 3 $ 4 Interest cost 4 5 13 15 Expected return on plan assets (2 ) (2 ) (6 ) (6 ) Amortization of: Prior service costs (2 ) (3 ) (6 ) (7 ) Actuarial loss 1 1 4 3 Net Periodic Benefit Cost $ 2 $ 3 $ 8 $ 9

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2018
Equity [Abstract]
Accumulated Other Comprehensive Gain (Loss)	Accumulated Other Comprehensive (Loss) Gain for the three months ended September 30, 2018 and 2017 , respectively, consisted of: As of June, Adoption of Three Months Ended September 30, As of September 30, As of June 30, Three Months Ended September 30, As of September 30, 2018 standard 2018 2018 2017 2017 2017 (Millions) Gain on revaluation of defined benefit plans $ (13 ) $ — $ — $ (13 ) $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans (7 ) — — (7 ) (7 ) — (7 ) Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $1.5 for 2018 and $3.0 for 2017 25 — 5 30 7 5 12 Reclassification to net income of losses on cash flow hedges, net of income tax expense of $0.4 for 2018 $1.3 for 2017(a) (66 ) — 1 (65 ) (48 ) 3 (45 ) Gain on derivatives qualifying as cash flow hedges (41 ) — 6 (35 ) (41 ) 8 (33 ) Accumulated Other Comprehensive (Loss) Gain $ (61 ) $ — $ 6 $ (55 ) $ (62 ) $ 8 $ (54 ) Accumulated Other Comprehensive (Loss) Gain for the nine months ended September 30, 2018 and 2017 , respectively, consisted of: As of December 31, Adoption of Nine Months Ended September 30, As of September 30, As of December 31, Nine Months Ended September 30, As of September 30, 2017 standard 2018 2018 2016 2017 2017 (Millions) Gain on revaluation of defined benefit plans net of tax expense of $0.2 for 2018 $ (14 ) $ — $ 1 $ (13 ) $ (14 ) $ — $ (14 ) Loss for nonqualified pension plans (6 ) (1 ) — (7 ) (7 ) — (7 ) Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $4.1 for 2017 30 — — 30 5 7 12 Reclassification to net income of (gains) losses on cash flow hedges, net of income tax (benefit) expense of $(6.8) for 2018 and $14.8 for 2017(a) (56 ) — (9 ) (65 ) (70 ) 25 (45 ) (Loss) gain on derivatives qualifying as cash flow hedges (26 ) — (9 ) (35 ) (65 ) 32 (33 ) Accumulated Other Comprehensive (Loss) Gain $ (46 ) $ (1 ) $ (8 ) $ (55 ) $ (86 ) $ 32 $ (54 ) ________________________ (a)Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income.

Earnings Per Share (Tables)

Earnings Per Share (Tables)	9 Months Ended
	Sep. 30, 2018
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 125 $ 99 $ 476 $ 458 Denominator: Weighted average number of shares outstanding - basic 309,491,082 309,491,082 309,507,443 309,506,831 Weighted average number of shares outstanding - diluted 309,689,890 309,801,903 309,705,788 309,785,639 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.40 $ 0.32 $ 1.54 $ 1.48 Earnings Per Common Share, Diluted $ 0.40 $ 0.32 $ 1.54 $ 1.48

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2018
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information for the three months ended September 30, 2018 , consisted of: Three Months Ended September 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,232 $ 315 $ (1 ) $ 1,546 Revenue - intersegment (4 ) — 4 — Loss from assets held for sale — — 1 1 Depreciation and amortization 128 98 — 226 Operating income 207 40 6 253 Earnings (losses) from equity method investments 4 (3 ) — 1 Interest expense, net of capitalization 64 13 (2 ) 75 Income tax expense (benefit) 31 2 (4 ) 29 Adjusted net income 96 33 10 139 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Segment information for the three months ended September 30, 2017 , consisted of: Three Months Ended September 30, 2017 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,126 $ 241 $ (26 ) $ 1,341 Revenue - intersegment (1 ) — 1 — Depreciation and amortization 119 80 6 205 Operating income (loss) 236 2 (20 ) 218 Earnings (losses) from equity method investments 5 (5 ) — — Interest expense, net of capitalization 62 7 2 71 Income tax expense (benefit) 57 (23 ) (2 ) 32 Adjusted net income 106 17 1 125 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Segment information as of and for the nine months ended September 30, 2018 , consisted of: Nine Months Ended September 30, 2018 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 3,884 $ 894 $ 35 $ 4,813 Revenue - intersegment 1 2 (3 ) — Loss from assets held for sale — — 16 16 Depreciation and amortization 374 270 — 644 Operating income 734 139 5 878 Earnings (losses) from equity method investments 10 (2 ) — 8 Interest expense, net of capitalization 189 28 2 219 Income tax expense (benefit) 118 (30 ) 40 128 Adjusted net income (loss) 376 147 (13 ) 511 Capital expenditures 873 300 — 1,173 As of September 30, 2018 Property, plant and equipment 14,385 8,732 8 23,125 Equity method investments 142 209 — 351 Total assets $ 21,674 $ 10,516 $ (435 ) $ 31,755 _________________________ (a) Includes Corporate, Gas and intersegment eliminations. Segment information for the nine months ended September 30, 2017 , consisted of: Nine Months Ended September 30, 2017 Networks Renewables Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 3,651 $ 789 $ (10 ) $ 4,430 Revenue - intersegment — 4 (4 ) — Depreciation and amortization 352 238 18 608 Operating income (loss) 826 108 (37 ) 897 Earnings (losses) from equity method investments 12 (9 ) — 3 Interest expense, net of capitalization 183 23 4 210 Income tax expense (benefit) 229 (38 ) (12 ) 179 Adjusted net income 374 114 6 494 Capital expenditures 842 855 7 1,704 As of December 31, 2017 Property, plant and equipment 13,876 8,786 7 22,669 Equity method investments 147 205 — 352 Total assets $ 21,411 $ 11,308 $ (1,048 ) $ 31,671 _________________________ (a) Includes Corporate, Gas and intersegment eliminations.
Schedule of Reconciliation of Adjusted Net Income to Net Income	Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and nine months ended September 30, 2018 and 2017 , respectively, is as follows: Three Months Ended September 30, Nine Months Ended September 30, 2018 2017 2018 2017 (Millions) Adjusted Net Income Attributable to Avangrid, Inc. $ 139 $ 125 $ 511 $ 494 Adjustments: Loss from assets held for sale (1) (1 ) — (16 ) — Mark-to-market adjustments - Renewables (2) (10 ) (4 ) (9 ) 2 Restructuring charges (3) (1 ) (3 ) (2 ) (3 ) Income from release of collateral - Renewables (4) (7 ) — — — Impact of the Tax Act (5) — — (7 ) — Income tax impact of adjustments 5 2 (11 ) — Gas Storage, net of tax (6) — (21 ) 10 (35 ) Net Income Attributable to Avangrid, Inc. $ 125 $ 99 $ 476 $ 458 (1) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses (See Note 20 - Assets Held for Sale – for further details). (2) Mark-to-market adjustments relate to changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity and gas. (3) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment (See Note 19 - Restructuring and Severance Related Expenses – for further details). (4) Relates to cash collateral released in excess of outstanding receivables from a bankruptcy proceeding with a Renewables customer regarding two power purchase agreements. (5) Represents the impact from measurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. (6) Removal of the impact from Gas activity in the reconciliation to the AVANGRID Net Income.

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2018
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three and nine months ended September 30, 2018 and 2017 , respectively, consisted of: Three Months Ended September 30, 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ — $ — $ (8 ) Iberdrola Renovables Energía, S.L. — (3 ) — (2 ) Iberdrola, S.A. — (10 ) 1 (10 ) Iberdrola Energia Monterrey, S.A. de C.V. — — 14 — Other 3 (2 ) 1 — Nine Months Ended September 30, 2018 2017 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (4 ) $ — $ (28 ) Iberdrola Renovables Energía, S.L. — (10 ) — (7 ) Iberdrola, S.A. — (36 ) 1 (28 ) Iberdrola Energia Monterrey, S.A. de C.V. 3 — 43 — Other 4 (3 ) 2 (2 )
Schedule of Related Party Balances	Related party balances as of September 30, 2018 and December 31, 2017 , respectively, consisted of: As of September 30, 2018 December 31, 2017 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ — $ (1 ) $ — $ (31 ) Siemens-Gamesa — (11 ) 2 (51 ) Iberdrola, S.A. — (36 ) 1 (32 ) Iberdrola Renovables Energía, S.L. — (10 ) — — Iberdrola Energia Monterrey, S.A. de C.V. — — 1 — Other 3 (2 ) 6 (4 )

Supplemental Balance Sheet In_2

Supplemental Balance Sheet Information (Tables)	9 Months Ended
	Sep. 30, 2018
Balance Sheet Related Disclosures [Abstract]
Schedule of Accumulated Depreciation and Amortization	The accumulated depreciation and amortization as of September 30, 2018 and December 31, 2017 , respectively, were as follows: September 30, December 31, As of 2018 2017 (Millions) Property, plant and equipment Accumulated depreciation $ 8,238 $ 7,497 Intangible assets Accumulated amortization $ 287 $ 276

Restructuring and Severance R_2

Restructuring and Severance Related Expenses (Tables)	9 Months Ended
	Sep. 30, 2018
Restructuring and Related Activities [Abstract]
Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities	In the nine months ended September 30, 2018 , the severance and lease restructuring charges reserves, which are recorded in other current liabilities and other liabilities, consisted of: Nine Months Ended September 30, 2018 (Millions) Beginning Balance $ 5 Restructuring and severance related expenses 2 Payments (3 ) Ending Balance $ 4

Assets Held for Sale (Tables)

Assets Held for Sale (Tables)	9 Months Ended
	Sep. 30, 2018
Assets Held-for-sale, Not Part of Disposal Group [Abstract]
Summary of Current Assets and Current Liabilities Held for Sale	The current assets and current liabilities held for sale relating to our gas trading and storage businesses consisted of the following as of December 31, 2017 : December 31, As of 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

Background and Nature Of Oper_2

Background and Nature Of Operations (Detail)	9 Months Ended
	Sep. 30, 2018
Avangrid | Iberdrola S.A.
Nature Of Business [Line Items]
Ownership percentage held by parent	81.50%

Significant Accounting Polici_4

Significant Accounting Policies and New Accounting Pronouncements - Schedule of Cumulative Effects of Changes to Consolidated Balance Sheet (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Jan. 01, 2018	Dec. 31, 2017
Liabilities
Tax equity financing arrangements - VIEs	$ 0	$ 0	$ 60
Deferred income taxes	1,572	1,412	1,452
Equity
Retained earnings	1,536	1,473	1,475
Non-controlling interests	$ 327	159	19
Calculated Under Revenue and Other Income Guidance in Effect (Before Topic 606 and 610-20)
Liabilities
Tax equity financing arrangements - VIEs			98
Deferred income taxes			1,452
Equity
Retained earnings			1,475
Non-controlling interests			$ 19
Adjustments Due to ASC 606 | Accounting Standards Update 2014-09
Liabilities
Tax equity financing arrangements - VIEs		0
Deferred income taxes		0
Equity
Retained earnings		0
Non-controlling interests		0
Adjustments Due to ASC 610-20 | Accounting Standards Update 2017-05
Liabilities
Tax equity financing arrangements - VIEs		(98)
Deferred income taxes		(40)
Equity
Retained earnings		(2)
Non-controlling interests		$ 140

Significant Accounting Polici_5

Significant Accounting Policies and New Accounting Pronouncements - Effect of Change in Retrospective Presentation Related to Net Periodic Cost (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operations and maintenance	$ 574	$ 531	$ 1,634	$ 1,546
Other income / (expense)	$ (16)	(15)	$ (57)	(52)
Accounting Standards Update 2017-07
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operations and maintenance		531		1,546
Other income / (expense)		(15)		(52)
Accounting Standards Update 2017-07 | As Previously Reported
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operations and maintenance		560		1,633
Other income / (expense)		14		35
Accounting Standards Update 2017-07 | Restatement Adjustment
New Accounting Pronouncements or Change in Accounting Principle [Line Items]
Operations and maintenance		(29)		(87)
Other income / (expense)		$ (29)		$ (87)

Revenue - Narrative (Detail)

Revenue - Narrative (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2018USD ($)
Utility Revenue [Line Items]
Accounts receivable related to contracts with customers	$ 1,015
Networks
Utility Revenue [Line Items]
Revenue performance obligation, timing	P1Y
Renewables | Minimum
Utility Revenue [Line Items]
Capitalized contract cost amortization term	3 years
Renewables | Maximum
Utility Revenue [Line Items]
Capitalized contract cost amortization term	20 years

Revenue - Schedule of Revenues

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Segment Reporting Information [Line Items]
Operating Revenues	$ 1,395		$ 4,346
Leasing revenue	85		282
Derivative revenue	40		115
Alternative revenue programs	22		66
Other revenue	4		4
Revenues	1,546	$ 1,341	4,813	$ 4,430
Electricity
Segment Reporting Information [Line Items]
Operating Revenues	1,010		2,736
Natural Gas
Segment Reporting Information [Line Items]
Operating Revenues	169		1,007
Wind
Segment Reporting Information [Line Items]
Operating Revenues	198		546
Solar
Segment Reporting Information [Line Items]
Operating Revenues	4		12
Thermal
Segment Reporting Information [Line Items]
Operating Revenues	22		36
Gas Storage
Segment Reporting Information [Line Items]
Operating Revenues	1		11
Other
Segment Reporting Information [Line Items]
Operating Revenues	(9)		(2)
Networks
Segment Reporting Information [Line Items]
Operating Revenues	1,193		3,788
Leasing revenue	9		27
Alternative revenue programs	22		66
Other revenue	4		4
Revenues	1,228		3,885
Networks | Electricity
Segment Reporting Information [Line Items]
Operating Revenues	1,010		2,736
Revenues	1,038	941	2,857	2,683
Networks | Natural Gas
Segment Reporting Information [Line Items]
Operating Revenues	169		1,007
Revenues	188	$ 181	1,030	$ 966
Networks | Other
Segment Reporting Information [Line Items]
Operating Revenues	14		45
Renewables
Segment Reporting Information [Line Items]
Operating Revenues	199		536
Leasing revenue	76		255
Derivative revenue	40		105
Revenues	315		896
Renewables | Wind
Segment Reporting Information [Line Items]
Operating Revenues	198		546
Renewables | Solar
Segment Reporting Information [Line Items]
Operating Revenues	4		12
Renewables | Thermal
Segment Reporting Information [Line Items]
Operating Revenues	22		36
Renewables | Other
Segment Reporting Information [Line Items]
Operating Revenues	(25)		(58)
Other
Segment Reporting Information [Line Items]
Operating Revenues	3		22
Derivative revenue			10
Revenues	3		32
Other | Gas Storage
Segment Reporting Information [Line Items]
Operating Revenues	1		11
Other | Other
Segment Reporting Information [Line Items]
Operating Revenues	$ 2		$ 11

Revenue - Schedule of Aggregate

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Detail) $ in Millions	Sep. 30, 2018USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 41
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Retail Energy Sales Contracts In Place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 7
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Capacity And Carbon Free Energy Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2019-01-01 | Renewable Energy Credit Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 20
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 28
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Retail Energy Sales Contracts In Place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 8
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Capacity And Carbon Free Energy Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 8
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2020-01-01 | Renewable Energy Credit Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 21
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Retail Energy Sales Contracts In Place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 9
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Capacity And Carbon Free Energy Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 3
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2021-01-01 | Renewable Energy Credit Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 9
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 17
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Retail Energy Sales Contracts In Place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 9
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Capacity And Carbon Free Energy Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 3
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Renewable Energy Credit Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 5
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 16
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Retail Energy Sales Contracts In Place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 9
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Capacity And Carbon Free Energy Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 3
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Renewable Energy Credit Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 4
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 38
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Retail Energy Sales Contracts In Place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 25
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Capacity And Carbon Free Energy Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Renewable Energy Credit Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 161
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Retail Energy Sales Contracts In Place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	67
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Capacity And Carbon Free Energy Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	32
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: (nil) | Renewable Energy Credit Sale Contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 62

Regulatory Assets and Liabili_3

Regulatory Assets and Liabilities - Additional Information (Detail) $ in Thousands

Oct. 15, 2018

Aug. 30, 2018USD ($)

Jun. 29, 2018USD ($)

May 17, 2018USD ($)

Oct. 16, 2017

Oct. 06, 2017

Aug. 25, 2014USD ($)

Jul. 01, 2014

Dec. 31, 2016

Sep. 30, 2018USD ($)

Sep. 30, 2017USD ($)

Sep. 30, 2018USD ($)Station

Sep. 30, 2017USD ($)

Apr. 30, 2019

Apr. 30, 2018

Apr. 30, 2017

Dec. 31, 2017USD ($)

Regulatory Assets And Liabilities [Line Items]

Unrecorded regulatory assets

$ 1,754,000

$ 1,754,000

Equity ratio

50.00%

Public utilities regulatory authority distribution rate

9.10%

Return on equity

9.20%

Rate increase agreement, term

3 years

Unfunded future Income tax expense collection period

50 years

NEW YORK

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

NEW YORK | Prior tax rate

Regulatory Assets And Liabilities [Line Items]

Statutory income tax rate, state

7.10%

NEW YORK | Revised tax rate

Regulatory Assets And Liabilities [Line Items]

Statutory income tax rate, state

6.50%

NEW YORK | Oswego

Regulatory Assets And Liabilities [Line Items]

Number of nuclear generating stations | Station

2

Asset sale gain account

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Carrying costs on deferred income tax bonus depreciation

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Economic development

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Merger capital expense target customer credit account

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Positive benefit adjustment

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Post Term Amortization

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Theoretical reserve flow thru impact

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

UIL Holdings

Regulatory Assets And Liabilities [Line Items]

Business combination merger related rate credits

$ 1,000

$ 0

$ 3,000

$ 2,000

Maximum

Regulatory Assets And Liabilities [Line Items]

Approved return on equity

11.74%

Return on equity

11.14%

Maximum | NEW YORK

Regulatory Assets And Liabilities [Line Items]

Deferred income tax recovery period

39 years

Minimum | NEW YORK

Regulatory Assets And Liabilities [Line Items]

Deferred income tax recovery period

27 years

Electric and Gas Service Rate Plan Year One

Regulatory Assets And Liabilities [Line Items]

Customer receiving percentage

50.00%

Return on equity

9.65%

9.50%

Electric and Gas Service Rate Plan Year One | Forecast

Regulatory Assets And Liabilities [Line Items]

Return on equity

9.75%

Electric and Gas Service Rate Plan Year Two

Regulatory Assets And Liabilities [Line Items]

Customer receiving percentage

75.00%

Return on equity

10.15%

10.00%

Electric and Gas Service Rate Plan Year Two | Forecast

Regulatory Assets And Liabilities [Line Items]

Return on equity

10.25%

Electric and Gas Service Rate Plan Year Three

Regulatory Assets And Liabilities [Line Items]

Customer receiving percentage

90.00%

Return on equity

10.65%

10.50%

Electric and Gas Service Rate Plan Year Three | Forecast

Regulatory Assets And Liabilities [Line Items]

Return on equity

10.75%

Central Maine Power

Regulatory Assets And Liabilities [Line Items]

Annual distribution tariff increase

$ 24,300

Distribution tariff rate increased based on ROE

9.45%

Distribution tariff rate increased based on equity capital

50.00%

Recovery of deferred storm costs

$ 123,000

Central Maine Power | Storm costs

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

10 years

Central Maine Power | Regulatory Items Other Than Storm Costs

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]

Regulatory items amortization period

3 years

Annual amortization of regulatory items

$ 16,500

Approved return on equity

9.00%

Equity ratio

48.00%

48.00%

New York State Electric And Gas Corporation | Maximum

Regulatory Assets And Liabilities [Line Items]

Equity ratio for earnings sharing

50.00%

50.00%

New York State Electric And Gas Corporation | Storm costs

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

10 years

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

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

New York State Electric And Gas Corporation | Deferred Income Tax Charge

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

50 years

RG&E

Regulatory Assets And Liabilities [Line Items]

Approved return on equity

9.00%

Equity ratio

48.00%

48.00%

RG&E | Deferred property tax

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

RG&E | Maximum

Regulatory Assets And Liabilities [Line Items]

Equity ratio for earnings sharing

50.00%

50.00%

RG&E | Deferred Income Tax Charge

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

50 years

Southern Connecticut Gas Company S C G

Regulatory Assets And Liabilities [Line Items]

Equity ratio

52.00%

Public utilities regulatory authority distribution rate

9.25%

Amount of approved ROE for the year 2018

$ 1,500

Amount of approved ROE for the year 2019

4,700

Amount of approved ROE for the year 2020

5,000

Berkshire Gas Company

Regulatory Assets And Liabilities [Line Items]

Department of public utilities gas distribution rate increase over base distribution rate revenue

$ 4,540

Public utilities requested rate decrease amount offsets in other factors

1,430

Net changes in operating revenue

$ 3,110

Return on equity

10.35%

Proposed alternative ratemaking mechanism term

5 years

Connecticut Natural Gas Corporation

Regulatory Assets And Liabilities [Line Items]

Amount of proposed ROE for the year 2019

$ 9,900

$ 16,600

Amount of proposed ROE for the year 2020

4,600

10,100

Amount of proposed ROE for the year 2021

5,200

1,100

Amount of proposed ROE, total

$ 19,700

Connecticut Natural Gas Corporation | UIL Holdings

Regulatory Assets And Liabilities [Line Items]

Business combination merger related rate credits

$ 1,250

UI

Regulatory Assets And Liabilities [Line Items]

Regulatory assets

$ 98,000

98,000

$ 93,000

UI | Storm costs

Regulatory Assets And Liabilities [Line Items]

Deferred costs

1,000

1,000

Regulatory assets

$ 0

$ 0

NYSEG | Deferred property tax

Regulatory Assets And Liabilities [Line Items]

Regulatory items amortization period

5 years

Subsequent Event | Central Maine Power

Regulatory Assets And Liabilities [Line Items]

Equity ratio

55.00%

Public utilities regulatory authority distribution rate

10.00%

Regulatory Assets and Liabili_4

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory Assets [Line Items]
Current Regulatory Assets	$ 284	$ 307
Non-current Regulatory Assets	2,591	2,738
Deferred income taxes regulatory	44	0
Total Non-current Regulatory Assets	2,635	2,738
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Current Regulatory Assets	24	24
Non-current Regulatory Assets	116	110
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Current Regulatory Assets	12	7
Non-current Regulatory Assets	1,035	1,162
Storm costs
Regulatory Assets [Line Items]
Current Regulatory Assets	65	46
Non-current Regulatory Assets	296	254
Rate adjustment mechanism
Regulatory Assets [Line Items]
Current Regulatory Assets	17	0
Reliability support services
Regulatory Assets [Line Items]
Current Regulatory Assets	19	27
Non-current Regulatory Assets	0	10
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Current Regulatory Assets	10	21
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Current Regulatory Assets	7	8
Electric supply reconciliation
Regulatory Assets [Line Items]
Current Regulatory Assets	7	0
Hedges losses
Regulatory Assets [Line Items]
Current Regulatory Assets	0	3
Contracts for differences
Regulatory Assets [Line Items]
Current Regulatory Assets	8	9
Non-current Regulatory Assets	90	84
Hardship programs
Regulatory Assets [Line Items]
Current Regulatory Assets	13	14
Non-current Regulatory Assets	9	13
Deferred property tax
Regulatory Assets [Line Items]
Current Regulatory Assets	10	10
Non-current Regulatory Assets	0	14
Plant decommissioning
Regulatory Assets [Line Items]
Current Regulatory Assets	6	6
Non-current Regulatory Assets	7	9
Deferred purchased gas
Regulatory Assets [Line Items]
Current Regulatory Assets	12	31
Deferred transmission expense
Regulatory Assets [Line Items]
Current Regulatory Assets	16	37
Environmental remediation costs
Regulatory Assets [Line Items]
Current Regulatory Assets	14	13
Non-current Regulatory Assets	270	283
Other
Regulatory Assets [Line Items]
Current Regulatory Assets	44	51
Non-current Regulatory Assets	64	71
Deferred meter replacement costs
Regulatory Assets [Line Items]
Non-current Regulatory Assets	27	29
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Non-current Regulatory Assets	16	17
Unfunded future income taxes
Regulatory Assets [Line Items]
Non-current Regulatory Assets	369	376
Asset retirement obligation
Regulatory Assets [Line Items]
Non-current Regulatory Assets	19	18
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Non-current Regulatory Assets	152	155
Merger capital expense target customer credit account
Regulatory Assets [Line Items]
Non-current Regulatory Assets	1	2
Debt premium
Regulatory Assets [Line Items]
Non-current Regulatory Assets	$ 120	$ 131

Regulatory Assets and Liabili_5

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	$ 194	$ 178
Non-current Regulatory Liabilities	3,285	3,239
Deferred income taxes regulatory	0	13
Total Non-current Regulatory Liabilities	3,285	3,252
Non by-passable charges
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	6	5
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	56	37
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	2	4
Transmission revenue reconciliation mechanism
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	6	14
Pension and other post-retirement benefits
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	0	1
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	14	14
Non-current Regulatory Liabilities	63	74
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	23	21
Non-current Regulatory Liabilities	55	72
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	5	5
Non-current Regulatory Liabilities	16	20
Yankee DOE Refund
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	0	4
Merger related rate credits
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	0	1
Non-current Regulatory Liabilities	18	20
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	4	4
Stranded costs
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	3	17
Hedges gains
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	7	0
Other
Regulatory Liabilities [Line Items]
Current Regulatory Liabilities	68	51
Non-current Regulatory Liabilities	71	67
Accrued removal obligations
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	1,145	1,132
2017 Tax Act
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	1,566	1,515
Asset sale gain account
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	10	10
Economic development
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	28	32
Merger capital expense target customer credit account
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	6	6
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	37	39
New York state tax rate change
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	4	6
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	15	19
Deferred property tax
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	24	19
Net plant reconciliation
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	19	10
Variable rate debt
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	42	33
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	27	27
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	21	19
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	13	13
Asset retirement obligation
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	12	13
Earning sharing provisions
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	17	22
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	18	19
Excess generation service charge
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	10	2
Low income programs
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	35	42
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Non-current Regulatory Liabilities	$ 13	$ 8

Fair Value of Financial Instr_3

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($)	1 Months Ended		3 Months Ended	9 Months Ended
	Jan. 31, 2019	Sep. 30, 2018	Jun. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Oct. 04, 2018	Oct. 02, 2018	Jun. 29, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash		$ 105,000,000		$ 105,000,000					$ 71,000,000
Fair value of debt		5,781,000,000		5,781,000,000					5,799,000,000
Repayment of debt				$ 65,000,000	$ 65,000,000
Proceeds from issuance of private placement		295,000,000
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Fair value of debt									61,000,000
Repayment of debt			$ 61,000,000
1994 Series Pollution Control Revenue Bonds and 2004 Series Pollution Revenue Bonds | New York State Energy Research and Development Authority [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument principal amount								$ 326,000,000
Minimum
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
Minimum | 1994 Series Pollution Control Revenue Bonds and 2004 Series Pollution Revenue Bonds | New York State Energy Research and Development Authority [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument, variable interest rate								2.625%
Maximum | 1994 Series Pollution Control Revenue Bonds and 2004 Series Pollution Revenue Bonds | New York State Energy Research and Development Authority [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument, variable interest rate								3.50%
Restricted Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash		$ 8,000,000		$ 8,000,000					$ 5,000,000
RG&E
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%
Subsequent Event | 1994 Series Pollution Control Revenue Bonds and 2004 Series Pollution Revenue Bonds
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument principal amount							$ 64,500,000
Debt instrument, variable interest rate							2.80%
Subsequent Event | Unsecured Debt
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Debt instrument principal amount						$ 100,000,000
Debt instrument, variable interest rate						4.07%
Subsequent Event | Forecast | Unsecured Debt
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Aggregate amount of notes to be issued	$ 195,000,000

Fair Value of Financial Instr_4

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	$ 81	$ 106
Derivative liabilities	(119)	(128)
Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(82)	(195)
Derivative liabilities	52	147
Securities portfolio (available for sale)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	41	41
Securities portfolio (available for sale) | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	0	0
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	70	69
Derivative liabilities	(6)	(9)
Derivative financial instruments - power | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(33)	(49)
Derivative liabilities	40	37
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	25
Derivative liabilities	(5)	(15)
Derivative financial instruments - gas | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	(49)	(146)
Derivative liabilities	12	110
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	7	12
Derivative liabilities	(105)	(104)
Contracts for differences | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4
Derivative liabilities	(3)
Derivative financial instruments – other | Netting
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	0
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	12	103
Derivative liabilities	(8)	(94)
Level 1 | Securities portfolio (available for sale)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	41	41
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	12	14
Derivative liabilities	(8)	(14)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	89
Derivative liabilities	0	(80)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 1 | Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	26	48
Derivative liabilities	(27)	(37)
Level 2 | Securities portfolio (available for sale)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	0	0
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	15	30
Derivative liabilities	(16)	(17)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	7	18
Derivative liabilities	(8)	(20)
Level 2 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Level 2 | Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	4
Derivative liabilities	(3)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	125	150
Derivative liabilities	(136)	(144)
Level 3 | Securities portfolio (available for sale)
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Financial instruments, assets	0	0
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	76	74
Derivative liabilities	(22)	(15)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	42	64
Derivative liabilities	(9)	(25)
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	7	12
Derivative liabilities	(105)	$ (104)
Level 3 | Derivative financial instruments – other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets	0
Derivative liabilities	$ 0

Fair Value of Financial Instr_5

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Fair Value, Instruments Classified in Shareholders' Equity Measured on Recurring Basis, Unobservable Input Reconciliation, Calculation [Roll Forward]
Fair Value Beginning of Period,	$ (1)	$ 32	$ 6	$ 31
Gains recognized in operating revenues	0	9	11	20
(Losses) recognized in operating revenues	(5)	0	(8)	(3)
Total (losses) gains recognized in operating revenues	(5)	9	3	17
Gains recognized in OCI	0	1	0	2
(Losses) recognized in OCI	(1)	0	(1)	(1)
Total (losses) gains recognized in OCI	(1)	1	(1)	1
Net change recognized in regulatory assets and liabilities	2	2	(6)	4
Purchases	(3)	5	(6)	3
Settlements	(3)	(3)	(7)	(10)
Fair Value as of September 30,	(11)	46	(11)	46
Gains (losses) for the period included in operating revenues attributable to the change in unrealized gains (losses) relating to financial instruments still held at the reporting date	$ (5)	$ 9	$ 3	$ 17

Fair Value of Financial Instr_6

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	9 Months Ended
	Sep. 30, 2018$ / MMBTU$ / MWh
NYMEX ($/MMBtu) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	2.94
NYMEX ($/MMBtu) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	3.93
NYMEX ($/MMBtu) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	2.44
Indiana hub ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	30.62
Indiana hub ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	53.9
Indiana hub ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	19.1
Mid C ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	23.31
Mid C ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	57
Mid C ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	(0.5)
Minn hub ($/MWh) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	25.18
Minn hub ($/MWh) | Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	49.85
Minn hub ($/MWh) | Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	12.51

Fair Value of Financial Instr_7

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Detail) - Contracts for differences - Level 3	9 Months Ended
	Sep. 30, 2018$ / MWh
Minimum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.00%
Forward pricing ($ per MWh)	4.30
Minimum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Discount rate	0.0259
Maximum
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.59%
Forward pricing ($ per MWh)	9.55
Maximum | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Discount rate	0.0305

Derivative Instruments and He_3

Derivative Instruments and Hedging - Additional Information (Detail)	3 Months Ended		6 Months Ended	9 Months Ended		12 Months Ended
	Sep. 30, 2018USD ($)Swap	Sep. 30, 2017USD ($)	Dec. 31, 2018USD ($)	Sep. 30, 2018USD ($)Swap	Sep. 30, 2017USD ($)	Jun. 30, 2019USD ($)	Dec. 31, 2017USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities				$ (18,000,000)	$ (43,000,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income	$ (2,000,000)	$ (1,000,000)		4,000,000	4,000,000
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes of $0.4 and $1.3 for the three months ended and $(6.8) and $14.8, for the nine months ended, respectively	1,000,000	3,000,000		(9,000,000)	25,000,000
Derivative assets	22,000,000			22,000,000			$ 18,000,000
UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross derivative asset	7,000,000			7,000,000			12,000,000
Regulatory Assets	98,000,000			98,000,000			93,000,000
Gross amounts of recognized liabilities	105,000,000			105,000,000			104,000,000
Regulatory liabilities	0			$ 0			0
Contracts for differences | UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers				20.00%
Contracts for differences | CL&P
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers				80.00%
Gross derivative asset	0			$ 0			0
Gross amounts of recognized liabilities	$ 97,000,000			$ 97,000,000			90,000,000
Forward Interest Rate Swaps | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of forward interest rate swaps | Swap	2			2
Notional amount	$ 500,000,000			$ 500,000,000
Pre-tax gains recognized in accumulated OCI from changes in fair value of interest rate swap derivative instruments	8,100,000			3,700,000
Ineffective portion of cash flow hedge	0			0
Derivative assets	3,700,000			3,700,000
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain (loss) from hedging activities reported in accumulated OCI	0	0		0	(1,000,000)
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	2,000,000	2,000,000		6,000,000	6,000,000
Ineffective portion of cash flow hedge	0	0		0	0
Unrealized gain (loss) from hedging activities reported in accumulated OCI				$ (200,000)
Maximum period of time of cash flow hedges				12 months
Net derivative losses related to discontinued cash flow hedges	(2,000,000)	(2,000,000)		$ (6,000,000)	(6,000,000)
Networks | Cash Flow Hedging | Forecast
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes of $0.4 and $1.3 for the three months ended and $(6.8) and $14.8, for the nine months ended, respectively			$ 2,000,000
Derivative instruments, losses expected to be reclassified into earnings in the next 12 months						$ 200,000
Networks | Swap | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	62,800,000			62,800,000			68,800,000
Networks | Electricity Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory liabilitiess				6,700,000
Gain (Loss) recognized in regulatory assets				(2,200,000)
Gain (Loss) recognized in regulatory assets and liabilities							(200,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income	4,100,000	(7,900,000)		8,700,000	(29,200,000)
Networks | Natural Gas Hedges
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets and liabilities				100,000			(2,500,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income	0	0		$ (1,700,000)	600,000
Networks | Fuel Derivatives | Cash Flow Hedging | Maximum
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges				12 months
Renewables and Gas Activities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain (loss) from hedging activities reported in accumulated OCI	(3,000,000)	8,000,000		$ (4,000,000)	12,000,000
Renewables and Gas Activities | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	0			100,000
Ineffective portion of cash flow hedge	200,000	$ 500,000		0	$ 1,000,000
Unrealized gain (loss) from hedging activities reported in accumulated OCI				(700,000)
Net loss in accumulated OCI related to discontinued cash flow hedge				400,000
Net derivative losses related to discontinued cash flow hedges	0			(100,000)
Counter Party
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross amounts of recognized liabilities	2,200,000			2,200,000
Cash Collateral Pledged	11,000,000			11,000,000			$ 30,000,000
Counter Party | UI
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative collateral obligation to be paid in decrease in credit rating below investment grade	$ 14,000,000			$ 14,000,000

Derivative Instruments and He_4

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities)	$ (1)	$ (2)	$ (5)	$ (6)
Derivative Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities)	$ 2	$ 4	$ (1)	$ 10

Derivative Instruments and He_5

Derivative Instruments and Hedging - Net Notional Volume (Detail) gal in Millions, MWh in Millions	9 Months Ended	12 Months Ended
	Sep. 30, 2018DTHMWhgal	Dec. 31, 2017DTHMWhgal
Networks | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure (MWh) | MWh	4	3.9
Networks | Natural Gas Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	7,700,000	6,100,000
Networks | Fleet Fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, volume (Gallons) | gal	2	2.1
Renewables and Gas Activities | Long | Basis Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	32,995,000	68,490,000
Renewables and Gas Activities | Short | Basis Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	542,500	62,337,500.0000015
Renewables and Gas Activities | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure (MWh) | MWh	3	4
Renewables and Gas Activities | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure (MWh) | MWh	5	6
Renewables and Gas Activities | Natural Gas and Other fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	22,080,951	285,139,702.483338
Renewables and Gas Activities | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount	10,276,814	11,789,605

Derivative Instruments and He_6

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 81	$ 106
Derivative Liability	(119)	(128)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	11	7
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	11	7
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	16	20
Derivative liabilities	(5)	(13)
Derivative Asset	11	7
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	2	5
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	2	5
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	3	5
Derivative liabilities	(1)	0
Derivative Asset	2	5
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(13)	(19)
Cash collateral (payable) receivable, Liability	0	3
Total derivatives as presented in the balance sheet, Liability	(13)	(16)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	13
Derivative liabilities	(18)	(32)
Derivative Liability	(13)	(19)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Liability	0	0
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(94)	(88)
Cash collateral (payable) receivable, Liability	2	0
Total derivatives as presented in the balance sheet, Liability	(92)	(88)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	0
Derivative liabilities	(95)	(88)
Derivative Liability	(94)	(88)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Liability	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	16	53
Cash collateral (payable) receivable, Asset	(9)	(17)
Total derivatives as presented in the balance sheet, Asset	7	36
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	17	111
Derivative liabilities	(2)	(82)
Derivative Asset	15	29
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	24
Derivative liabilities	0	0
Derivative Asset	1	24
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	94	97
Cash collateral (payable) receivable, Asset	(37)	(39)
Total derivatives as presented in the balance sheet, Asset	57	58
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	96	99
Derivative liabilities	(4)	(5)
Derivative Asset	92	94
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	4
Derivative liabilities	0	(1)
Derivative Asset	2	3
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(13)	(23)
Cash collateral (payable) receivable, Liability	5	3
Total derivatives as presented in the balance sheet, Liability	(8)	(20)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	12	31
Derivative liabilities	(23)	(51)
Derivative Liability	(11)	(20)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	0
Derivative liabilities	(3)	(3)
Derivative Liability	(2)	(3)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(11)	(7)
Cash collateral (payable) receivable, Liability	8	3
Total derivatives as presented in the balance sheet, Liability	(3)	(4)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	8	4
Derivative liabilities	(18)	(10)
Derivative Liability	(10)	(6)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	2
Derivative liabilities	(5)	(3)
Derivative Liability	$ (1)	$ (1)

Derivative Instruments and He_7

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	$ 0	$ 0	$ 0	$ (1)
(Gain) Loss Reclassified from Accumulated OCI into Income	2	3	6	7
Renewables and Gas Activities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	(3)	8	(4)	12
(Gain) Loss Reclassified from Accumulated OCI into Income	(1)	1	(21)	31
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	0	0	0	0
(Gain) Loss Reclassified from Accumulated OCI into Income	2	2	6	6
Commodity contracts | Networks | Operating expenses
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	0	0	0	(1)
(Gain) Loss Reclassified from Accumulated OCI into Income	0	1	0	1
Commodity contracts | Renewables and Gas Activities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	(3)	8	(4)	12
Commodity contracts | Renewables and Gas Activities | Operating revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) Loss Reclassified from Accumulated OCI into Income	$ (1)	$ 1	$ (21)	$ 31

Derivative Instruments and He_8

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 53	$ 70
Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	54	55
Long | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	4	(3)
Long | Natural Gas and Other fuel Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(1)	19
Long | Basis Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(4)	(13)
Short | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	0	8
Short | Basis Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 0	$ 4

Derivative Instruments and He_9

Derivative Instruments and Hedging - Effect of Trading Derivatives (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (2)	$ (1)	$ 4	$ 4
Renewables and Gas Activities | Trading Derivatives | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(3)	0	3	(2)
Renewables and Gas Activities | Trading Derivatives | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	1	1	0	4
Renewables and Gas Activities | Trading Derivatives | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	0	(2)	(2)	(2)
Renewables and Gas Activities | Trading Derivatives | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 0	$ 0	$ 3	$ 4

Derivative Instruments and H_10

Derivative Instruments and Hedging - Effect of Non-Trading Derivatives (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ (2)	$ (1)	$ 4	$ 4
Renewables and Gas Activities | Non-Trading Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(7)	(3)	(5)	2
Renewables and Gas Activities | Non-Trading Derivatives | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	1	0	5	(2)
Renewables and Gas Activities | Non-Trading Derivatives | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	0	(4)	(7)	2
Renewables and Gas Activities | Non-Trading Derivatives | Financial Power Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	(12)	2	(11)	8
Renewables and Gas Activities | Non-Trading Derivatives | Financial and Natural Gas Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain on Derivative, Net	$ 4	$ (1)	$ 8	$ (6)

Contingencies - Additional Info

Contingencies - Additional Information (Detail) $ in Millions

May 18, 2018USD ($)

Apr. 30, 2018

Mar. 27, 2018

Oct. 06, 2017

Oct. 05, 2017Lawsuit

Apr. 14, 2017

Apr. 29, 2016

Mar. 22, 2016

Jul. 31, 2014

Dec. 26, 2012

Oct. 31, 2018

Sep. 30, 2018USD ($)

Mar. 31, 2018CustomerStorm

Dec. 31, 2017USD ($)

Mar. 11, 2017Customer

Loss Contingencies [Line Items]

Requested return on equity base percentage

9.20%

Midpoint of base return on equity warranted percentage

9.39%

Refund period

15 months

Regulatory liabilities

$ 3,285

$ 3,239

Number of complaints dismissed | Lawsuit

4

Price of the power purchase agreements

259

Requested renewables delay from preliminary proposed ruling period

2 years

Standby letters of credit

$ 2,600

March 2017 Windstorm

Loss Contingencies [Line Items]

Number of affected customers | Customer

219,000

Investments to increase resiliency and improve emergency response in the areas impacted by the storm

$ 3.9

March 2018 Windstorm

Loss Contingencies [Line Items]

Number of affected customers | Customer

520,000

Number of severe winter storm | Storm

2

Maximum

Loss Contingencies [Line Items]

Approved return on equity

11.74%

Requested return on equity base percentage

11.14%

Complaint II

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.70%

Requested effective return on equity base percentage

11.14%

Regulatory liabilities

$ 23.2

Complaint II | Maximum

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Complaint III

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 | Maximum

Loss Contingencies [Line Items]

Approved return on equity

12.19%

Complaint II and III

Loss Contingencies [Line Items]

Reasonably possible loss, in additional reserve, pre tax

$ 17.1

Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Approved return on equity

10.57%

Unfavorable Regulatory Action | Complaint II

Loss Contingencies [Line Items]

Approved return on equity

9.59%

Unfavorable Regulatory Action | Complaint III

Loss Contingencies [Line Items]

Approved return on equity

10.90%

Unfavorable Regulatory Action | Complaint IV

Loss Contingencies [Line Items]

Approved return on equity

8.61%

Requested existing base return on equity base percentage

10.57%

Rejected currently-filed base return on equity percentage

10.57%

Unfavorable Regulatory Action | Complaint IV | Maximum

Loss Contingencies [Line Items]

Approved return on equity

11.74%

11.24%

Before Amendment

Loss Contingencies [Line Items]

Approved return on equity

11.14%

Subsequent Event | Unfavorable Regulatory Action | Complaint I

Loss Contingencies [Line Items]

Approved return on equity

9.60%

Requested existing base return on equity base percentage

10.41%

Subsequent Event | Unfavorable Regulatory Action | Complaint I | Maximum

Loss Contingencies [Line Items]

Approved return on equity

10.99%

Requested existing base return on equity base percentage

13.08%

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 ($)	Jul. 31, 2011USD ($)site	Sep. 30, 2018USD ($)siteLocation	Dec. 31, 2017USD ($)	Aug. 04, 2016USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							25
Number of sites where gas was manufactured in the past | site							53
Number of sites for which we have entered into consent orders to investigate and remediate | site							49
Costs related to investigation and remediation							$ 374	$ 389
Accrual for environmental loss contingencies		$ 27					$ 22
Number of sites with modified decision | site							9
Damages for incurred costs payment amount		$ 22
Refund of environmental remediation cost paid					$ 5
First Energy
Environmental Exit Cost [Line Items]
Former Manufactured Gas Sites | site						16
Reasonably possible loss, in additional reserve, net of tax						$ 60
Environmental costs paid				$ 30
First Energy | Past Costs
Environmental Exit Cost [Line Items]
Accrual for environmental loss contingencies				27
First Energy | Pre-judgment Interest
Environmental Exit Cost [Line Items]
Environmental costs paid				$ 3
Century Indemnity and OneBeacon
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax			$ 89
Number of hazardous waste sites | Location							22
Asnat | Environmental Remediation Activities
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							$ 20	25	$ 30
Maximum | Century Indemnity and OneBeacon
Environmental Exit Cost [Line Items]
Reasonably possible loss, in additional reserve, net of tax			$ 282
New York State Registry
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
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
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site							9
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 5
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability							8
Another Ten Sites | Minimum
Environmental Exit Cost [Line Items]
Estimated environmental liability							12
Another Ten Sites | Maximum
Environmental Exit Cost [Line Items]
Estimated environmental liability							$ 21
New York Voluntary Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site							12
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site							3
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 99	$ 100
Manufactured Gas Plants | Minimum
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							213
Manufactured Gas Plants | Maximum
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation							$ 442

Post-Retirement and Similar O_3

Post-Retirement and Similar Obligations - Additional Information (Detail) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2018USD ($)
Retirement Benefits [Abstract]
Defined benefit, pension contributions	$ 32	$ 40
Additional contributions for remainder of fiscal year	$ 8	$ 8

Post-Retirement and Similar O_4

Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 11	$ 10	$ 33	$ 32
Interest cost	32	35	96	104
Expected return on plan assets	(50)	(49)	(150)	(148)
Amortization of prior service costs	0	0	1	1
Amortization of actuarial loss	38	32	113	95
Net Periodic Benefit Cost	31	28	93	84
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	2	3	4
Interest cost	4	5	13	15
Expected return on plan assets	(2)	(2)	(6)	(6)
Amortization of prior service costs	(2)	(3)	(6)	(7)
Amortization of actuarial loss	1	1	4	3
Net Periodic Benefit Cost	$ 2	$ 3	$ 8	$ 9

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended	9 Months Ended		12 Months Ended
	May 31, 2018	May 31, 2017	Sep. 30, 2018	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2016	Dec. 31, 2017
Class of Stock [Line Items]
Common stock, authorized (in shares)			500,000,000	500,000,000			500,000,000
Common stock, issued (in shares)			309,752,140	309,752,140			309,670,932
Common stock, outstanding (in shares)			309,005,272	309,005,272			309,005,272
Common stock, par value (in usd per share)			$ 0.01	$ 0.01	$ 0.01		$ 0.01
Common stock, issued			$ 3	$ 3			$ 3
Additional paid-in capital			$ 13,656	$ 13,656			$ 13,653
Treasury stock, shares (in shares)			485,810	485,810			485,810
Convertible preferred stock, shares outstanding (in shares)			0	0			0
Issuances of common stock (in shares)			0	81,208	70,493
Release of common stock held in trust (in shares)				0	5,649
Treasury shares of common stock (in shares)			261,058	261,058
Repurchases of common stock (in shares)	81,208	64,019				115,831
Repurchases of common stock			$ 12	$ 12			$ 8
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent			81.50%	81.50%			81.50%

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Gain (Loss) (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Jun. 30, 2018	Dec. 31, 2017
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start			$ 15,077
Adoption of accounting standards					$ 0	$ 136
Other comprehensive income (loss), net of tax	$ 6	$ 8	(8)	$ 32
Period End	15,128		15,128
Other comprehensive income (loss) taxes	1.9	4.3	(6.6)	18.9
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(61)	(62)	(46)	(86)
Adoption of accounting standards						(1)
Other comprehensive income (loss), net of tax	6	8	(8)	32
Period End	(55)	(54)	(55)	(54)
Gain on revaluation of defined benefit plans net of tax expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(13)	(14)	(14)	(14)
Other comprehensive income (loss), net of tax	0	0	1	0
Period End	(13)	(14)	(13)	(14)
Other comprehensive income (loss) taxes	0	0	(0.2)	0
Loss for nonqualified pension plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(7)	(7)	(6)	(7)
Adoption of accounting standards					$ 0	$ (1)
Period End	(7)	(7)	(7)	(7)
(Loss) gain on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(41)	(41)	(26)	(65)
Other comprehensive income (loss), net of tax	6	8	(9)	32
Period End	(35)	(33)	(35)	(33)
Unrealized gain during period on derivatives qualifying as cash flow hedges, net of income tax expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	25	7	30	5
Other comprehensive income (loss), net of tax	5	5	0	7
Period End	30	12	30	12
Other comprehensive income (loss) taxes	1.5	3	0	4.1
Reclassification to net income of (gains) losses on cash flow hedges, net of income tax (benefit) expense
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Period Start	(66)	(48)	(56)	(70)
Other comprehensive income (loss), net of tax	(1)	(3)	9	(25)
Period End	(65)	(45)	(65)	(45)
Other comprehensive income (loss) taxes	$ 0.4	$ 1.3	$ (6.8)	$ 14.8

Earnings Per Share - Schedule o

Earnings Per Share - Schedule of Earnings Per Share, Basic and Diluted (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Numerator:
Net income attributable to AVANGRID	$ 125	$ 99	$ 476	$ 458
Denominator:
Weighted average number of shares outstanding - basic (in shares)	309,491,082	309,491,082	309,507,443	309,506,831
Weighted average number of shares outstanding - diluted (in shares)	309,689,890	309,801,903	309,705,788	309,785,639
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in usd per share)	$ 0.40	$ 0.32	$ 1.54	$ 1.48
Earnings Per Common Share, Diluted (in usd per share)	$ 0.40	$ 0.32	$ 1.54	$ 1.48

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)Segment	Sep. 30, 2017USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			2
Revenues	$ 1,546	$ 1,341	$ 4,813	$ 4,430
Networks
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			1
Number of operating segments | Segment			8
Revenues	1,228		$ 3,885
Renewables
Segment Reporting Information [Line Items]
Revenues	315		896
Electricity | Networks
Segment Reporting Information [Line Items]
Revenues	1,038	941	2,857	2,683
Natural Gas | Networks
Segment Reporting Information [Line Items]
Revenues	188	181	1,030	966
Other Networks | Networks
Segment Reporting Information [Line Items]
Revenues	6	4	(3)	2
Alternative Energy | Renewables
Segment Reporting Information [Line Items]
Revenues	$ 315	$ 241	$ 894	$ 789

Segment Information - Adjusted

Segment Information - Adjusted Net Income (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Segment Reporting Information [Line Items]
Revenues	$ 1,546	$ 1,341	$ 4,813	$ 4,430
Loss from assets held for sale	1	0	16	0
Depreciation and amortization	226	205	644	608
Operating income	253	218	878	897
Earnings (losses) from equity method investments	1	0	8	3
Interest expense, net of capitalization	75	71	219	210
Income tax expense (benefit)	29	32	128	179
Adjusted net income	139	125	511	494
Capital expenditures			1,173	1,704
Property, plant and equipment	23,125		23,125		$ 22,669
Equity method investments	351		351		352
Total assets	31,755		31,755		31,671
Networks
Segment Reporting Information [Line Items]
Revenues	1,228		3,885
Renewables
Segment Reporting Information [Line Items]
Revenues	315		896
Other
Segment Reporting Information [Line Items]
Revenues	(1)	(26)	35	(10)
Loss from assets held for sale	1		16
Depreciation and amortization	0	6	0	18
Operating income	6	(20)	5	(37)
Earnings (losses) from equity method investments	0	0	0	0
Interest expense, net of capitalization	(2)	2	2	4
Income tax expense (benefit)	(4)	(2)	40	(12)
Adjusted net income	10	1	(13)	6
Capital expenditures			0	7
Property, plant and equipment	8		8		7
Equity method investments	0		0		0
Total assets	(435)		(435)		(1,048)
Operating Segments | Networks
Segment Reporting Information [Line Items]
Revenues	1,232	1,126	3,884	3,651
Loss from assets held for sale	0		0
Depreciation and amortization	128	119	374	352
Operating income	207	236	734	826
Earnings (losses) from equity method investments	4	5	10	12
Interest expense, net of capitalization	64	62	189	183
Income tax expense (benefit)	31	57	118	229
Adjusted net income	96	106	376	374
Capital expenditures			873	842
Property, plant and equipment	14,385		14,385		13,876
Equity method investments	142		142		147
Total assets	21,674		21,674		21,411
Operating Segments | Renewables
Segment Reporting Information [Line Items]
Revenues	315	241	894	789
Loss from assets held for sale	0		0
Depreciation and amortization	98	80	270	238
Operating income	40	2	139	108
Earnings (losses) from equity method investments	(3)	(5)	(2)	(9)
Interest expense, net of capitalization	13	7	28	23
Income tax expense (benefit)	2	(23)	(30)	(38)
Adjusted net income	33	17	147	114
Capital expenditures			300	855
Property, plant and equipment	8,732		8,732		8,786
Equity method investments	209		209		205
Total assets	10,516		10,516		$ 11,308
Intersegment Eliminations | Networks
Segment Reporting Information [Line Items]
Revenues	(4)	(1)	1	0
Intersegment Eliminations | Renewables
Segment Reporting Information [Line Items]
Revenues	0	0	2	4
Intersegment Eliminations | Other
Segment Reporting Information [Line Items]
Revenues	$ 4	$ 1	$ (3)	$ (4)

Segment Information - Reconcili

Segment Information - Reconciliation of Adjusted Net Income to Net Income (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018USD ($)Agreement	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)Agreement	Sep. 30, 2017USD ($)
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 139	$ 125	$ 511	$ 494
Adjustments:
Loss from assets held for sale	(1)	0	(16)	0
Mark-to-market adjustments - Renewables	(10)	(4)	(9)	2
Restructuring charges	(1)	(3)	(2)	(3)
Income from release of collateral - Renewables	(7)	0	0	0
Impact of the Tax Act	0	0	(7)	0
Income tax impact of adjustments	5	2	(11)	0
Gas Storage, net of tax	0	(21)	10	(35)
Net Income Attributable to Avangrid, Inc.	$ 125	$ 99	$ 476	$ 458
Number of power purchase agreements | Agreement	2		2

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Iberdrola Canada Energy Services, Ltd
Related Party Transaction [Line Items]
Purchases From		$ (8)	$ (4)	$ (28)
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Purchases From	$ (3)	(2)	(10)	(7)
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To		1		1
Purchases From	(10)	(10)	(36)	(28)
Iberdrola Energia Monterrey, S.A. de C.V.
Related Party Transaction [Line Items]
Sales To		14	3	43
Other
Related Party Transaction [Line Items]
Sales To	3	1	4	2
Purchases From	$ (2)	$ 0	$ (3)	$ (2)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details)	Jun. 18, 2018USD ($)	Sep. 30, 2018USD ($)Megawatts	Dec. 31, 2017USD ($)
Related Party Transaction [Line Items]
Deposit balance		$ 0	$ 0
Line of credit facility fee basis points	0.105%
Credit facility outstanding amount		0
Siemens-Gamesa
Related Party Transaction [Line Items]
Portion of amount receivable from related parties			2,000,000
Iberdrola Canada Energy Services, Ltd
Related Party Transaction [Line Items]
Notes payable		0	29,000,000
Affiliated Entity
Related Party Transaction [Line Items]
Impairments		$ 0
Vineyard Wind
Related Party Transaction [Line Items]
Leased area transmission capacity (MW) | Megawatts		3,000
Proposed wind farm and electricity transmission project capacity (MW) | Megawatts		800
New electric generation and transmission capacity (MW) | Megawatts		3,200
Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Iberdrola, S.A. | Siemens-Gamesa
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired		8.10%
Related party transaction, amount		$ 2,000,000	266,000,000
Networks | New York Transco
Related Party Transaction [Line Items]
Business combination, equity interest percentage		20.00%
Portion of amount receivable from related parties		$ 1,000,000	6,000,000
Renewables
Related Party Transaction [Line Items]
Portion of amount receivable from related parties		$ 92,000,000
Renewables | Vineyard Wind
Related Party Transaction [Line Items]
Business combination, equity interest percentage		50.00%
Portion of amount receivable from related parties		$ 1,300,000	$ 0
Amount of commitment funded to date		$ 42,000,000

Related Party Transactions - _2

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Iberdrola Canada Energy Services, Ltd
Related Party Transaction [Line Items]
Owed To	$ (1)	$ (31)
Siemens-Gamesa
Related Party Transaction [Line Items]
Owed By		2
Owed To	(11)	(51)
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By		1
Owed To	(36)	(32)
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Owed To	(10)
Iberdrola Energia Monterrey, S.A. de C.V.
Related Party Transaction [Line Items]
Owed By		1
Other
Related Party Transaction [Line Items]
Owed By	3	6
Owed To	$ (2)	$ (4)

Supplemental Balance Sheet In_3

Supplemental Balance Sheet Information - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	Dec. 31, 2017
Supplemental Balance Sheet Information [Line Items]
Prepaid other taxes	$ 210		$ 210		$ 194
Deferred Payment Arrangements
Supplemental Balance Sheet Information [Line Items]
Accounts receivable	66		66		55
Allowance for doubtful accounts, deferred payment arrangement	33		33		$ 30
Provision for doubtful accounts, accounts receivable	$ 1	$ 0	$ 3	$ 3

Supplemental Balance Sheet In_4

Supplemental Balance Sheet Information - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Property, plant and equipment
Accumulated depreciation	$ 8,238	$ 7,497
Intangible assets
Accumulated amortization	$ 287	$ 276

Income Tax Expense - Additional

Income Tax Expense - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Income Taxes [Line Items]
Effective income tax rate	17.80%	24.20%	21.00%	28.10%
Income tax expense due to unfunded future income tax				$ 14
Gas Trading and Storage Businesses
Income Taxes [Line Items]
Income tax expense relating to disposal of gas business			$ 22.1

Stock-Based Compensation Expe_2

Stock-Based Compensation Expense - Additional Information (Detail) $ / shares in Units, $ in Millions	1 Months Ended		3 Months Ended		9 Months Ended
	Jun. 30, 2018$ / sharesshares	Mar. 31, 2018$ / sharesshares	Sep. 30, 2018USD ($)	Sep. 30, 2017USD ($)	Sep. 30, 2018USD ($)Installment	Sep. 30, 2017USD ($)	Dec. 31, 2017USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Stock-based compensation expense | $			$ 0.8	$ 1.4	$ 1.2	$ 5.3
Stock-based compensation other current liabilities | $							$ 5.5
Performance Shares Units | Officers and Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares) | shares	34,361	34,361
Number of installment payments of employee related payables | Installment					3
Share-based payment award options grant date fair value (in usd per share) | $ / shares	$ 31.80	$ 31.80
Restricted Stock Units | CEO
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares) | shares	60,000
Number of installment payments of employee related payables | Installment					1
Share-based payment award options grant date fair value (in usd per share) | $ / shares	$ 50.40

Variable Interest Entities - Ad

Variable Interest Entities - Additional Information (Detail) - USD ($) $ in Millions	1 Months Ended
	May 31, 2018	Sep. 30, 2018	Dec. 31, 2017
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)		$ 1,418	$ 1,441
Liabilities of variable interest entities (VIEs)		66	185
Equity method investments of variable interest entities (VIEs)		351	352
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Equity method investments of variable interest entities (VIEs)		$ 101	$ 107
El Cabo Wind, LLC
Variable Interest Entity [Line Items]
Contributions from tax equity investors	$ 213

Restructuring and Severance R_3

Restructuring and Severance Related Expenses - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Operations and Maintenance
Restructuring and Related Cost [Abstract]
Severance expenses	$ 0.9	$ 2.1	$ 2.1	$ 2.1
Leasehold Improvements
Restructuring and Related Cost [Abstract]
Accelerated depreciation		$ 0.5		$ 0.5

Restructuring and Severance R_4

Restructuring and Severance Related Expenses - Summary of Severance and Lease Restructuring Charges Reserves Recorded in Other Current Liabilities (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Restructuring Reserve [Roll Forward]
Beginning Balance			$ 5
Restructuring and severance related expenses	$ 1	$ 3	2	$ 3
Payments			(3)
Ending Balance	$ 4		$ 4

Assets Held for Sale - Addition

Assets Held for Sale - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017	May 01, 2018	Mar. 01, 2018
Assets Held For Sale Not Discontinued Operations [Line Items]
Loss on assets held for sale	$ 1	$ 0	$ 16	$ 0
(Loss)/income before income tax, adjusted to corporate overhead	163	132	610	638
Assets Held for Sale, Not Discontinued Operations | Gas Trading Business | Enstor Energy Services, LLC
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale, consideration receivable						$ 66
Assets Held for Sale, Not Discontinued Operations | Gas Storage Business | Enstor Gas, LLC
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale, consideration receivable					$ 66
Assets Held for Sale, Not Discontinued Operations | Gas Trading and Storage Businesses
Assets Held For Sale Not Discontinued Operations [Line Items]
Loss on assets held for sale	0.5		15.6
(Loss)/income before income tax, adjusted to corporate overhead	$ (0.3)	$ (33.7)	$ 4.2	$ (54.6)

Assets Held for Sale - Summary

Assets Held for Sale - Summary of Current Assets and Current Liabilities Held for Sale (Detail) - USD ($) $ in Millions	Sep. 30, 2018	Dec. 31, 2017
Assets Held For Sale Not Discontinued Operations [Line Items]
Assets held for sale	$ 0	$ 357
Liabilities held for sale	$ 0	137
Assets Held for Sale, Not Discontinued Operations | Gas Trading and Storage Businesses
Assets Held For Sale Not Discontinued Operations [Line Items]
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

Subsequent Events (Detail)

Subsequent Events (Detail) - $ / shares	3 Months Ended		9 Months Ended
	Sep. 30, 2018	Sep. 30, 2017	Sep. 30, 2018	Sep. 30, 2017
Subsequent Event [Line Items]
Dividends declared (in usd per share)	$ 0.44	$ 0.432	$ 1.304	$ 1.296