Avangrid (AGR) 10-Q 4 Aug 16 2016 Q2 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	6 Months Ended
	Jun. 30, 2016	Aug. 01, 2016
Document And Entity Information [Abstract]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Jun. 30, 2016
Document Fiscal Year Focus	2,016
Document Fiscal Period Focus	Q2
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	Non-accelerated Filer
Entity Common Stock, Shares Outstanding		309,003,589

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Statement [Abstract]
Operating Revenues	$ 1,439	$ 939	$ 3,109	$ 2,166
Operating Expenses
Purchased power, natural gas and fuel used	221	151	649	543
Operations and maintenance	558	434	1,109	814
Impairment of non-current assets		7		7
Depreciation and amortization	213	187	418	362
Taxes other than income taxes	125	87	262	171
Total Operating Expenses	1,117	866	2,438	1,897
Operating Income	322	73	671	269
Other Income and (Expense)
Other income and (expense)	20	10	69	22
Earnings (losses) from equity method investments		(1)	2
Interest expense, net of capitalization	(68)	(66)	(152)	(127)
Income Before Income Tax	274	16	590	164
Income tax expense	172	5	276	47
Net Income	102	11	314	117
Net Income Attributable to Avangrid, Inc.	$ 102	$ 11	$ 314	$ 117
Earnings Per Common Share, Basic	$ 0.33	$ 0.04	$ 1.01	$ 0.46
Earnings Per Common Share, Diluted	$ 0.33	$ 0.04	$ 1.01	$ 0.46
Weighted-average Number of Common Shares Outstanding:
Basic	309,527,868	252,235,232	309,533,042	252,235,232
Diluted	309,683,965	252,235,232	309,689,138	252,235,232
Cash Dividends Declared Per Common Share	$ 0.432		$ 0.864

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement Of Income And Comprehensive Income [Abstract]
Net Income		$ 102	$ 11	$ 314	$ 117
Other Comprehensive Income, Amounts arising during the year:
Gain (loss) on defined benefit plans, net of income taxes			(1)	4	(2)
Unrealized (loss) gain during the period on derivatives qualifying as cash flow hedges,net of income taxes		(23)	1	(21)	1
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]	1	2	(25)	4
Other Comprehensive (Loss) Income		(22)	2	(42)	3
Comprehensive Income		80	13	272	120
Comprehensive Income Attributable to Avangrid, Inc.		$ 80	$ 13	$ 272	$ 120
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Condensed Consolidated Stateme4

Condensed Consolidated Statements of Comprehensive Income (Parenthetical) (unaudited) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Statement Of Income And Comprehensive Income [Abstract]
Gain (loss) on defined benefit plans, income tax expense (benefit)	$ 0.1	$ (0.1)	$ 2.9	$ (1)
Unrealized (loss) gain during period on derivatives qualified as cash flow hedges, income tax (expense) benefit	(14.2)	0.4	(13)	0.4
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	$ 0.7	$ 1.2	$ (15.9)	$ 2.2

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (Unaudited) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Current Assets
Cash and cash equivalents	$ 396	$ 427
Accounts receivable and unbilled revenues, net	894	974
Accounts receivable from affiliates	66	70
Notes receivable from affiliates	4	6
Derivative assets	88	88
Fuel and gas in storage	230	307
Materials and supplies	106	98
Prepayments and other current assets	179	285
Regulatory assets	272	219
Total Current Assets	2,235	2,474
Property, plant and equipment, at cost	26,187	25,745
Less: accumulated depreciation	(6,722)	(6,372)
Net Property, Plant and Equipment in Service	19,465	19,373
Construction work in progress	1,365	1,338
Total Property, Plant and Equipment	20,830	20,711
Equity method investments	371	385
Other investments	54	64
Regulatory assets	3,141	3,314
Other Assets
Goodwill	3,113	3,115
Intangible assets	547	556
Derivative assets	73	89
Other	47	35
Total Other Assets	3,780	3,795
Total Assets	30,411	30,743
Current Liabilities
Current portion of debt	168	206
Tax equity financing arrangements	107	107
Notes payable	3	163
Interest accrued	60	61
Accounts payable and accrued liabilities	814	830
Accounts payable to affiliates	75	90
Dividends payable	133
Taxes accrued	50	55
Derivative liabilities	87	91
Other current liabilities	242	285
Regulatory liabilities	183	147
Total Current Liabilities	1,922	2,035
Regulatory liabilities	1,723	1,841
Deferred income taxes regulatory	521	519
Other Non-current Liabilities
Deferred income taxes	2,890	2,798
Deferred income	1,518	1,553
Pension and other postretirement	1,190	1,202
Tax equity financing arrangements	132	185
Derivative liabilities	98	94
Asset retirement obligations	165	184
Environmental remediation costs	383	406
Other	297	330
Total Other Non-current Liabilities	6,673	6,752
Non-current Debt	4,507	4,530
Total Non-current Liabilities	13,424	13,642
Total Liabilities	15,346	15,677
Commitments and Contingencies
Stockholders’ Equity:
Common stock	3	3
Additional paid in capital	13,651	13,653
Treasury Stock	(4)
Retained earnings	1,496	1,449
Accumulated other comprehensive loss	(94)	(52)
Total Stockholders’ Equity	15,052	15,053
Non-controlling interests	13	13
Total Equity	15,065	15,066
Total Liabilities and Equity	$ 30,411	$ 30,743

Condensed Consolidated Balance6

Condensed Consolidated Balance Sheets (Unaudited) (Parenthetical) - $ / shares	Jun. 30, 2016		Dec. 31, 2015		Dec. 15, 2015	Jun. 30, 2015	[1]	Dec. 31, 2014	[1]	Nov. 30, 2011
Statement Of Financial Position [Abstract]
Common stock, par value	$ 0.01		$ 0.01
Common stock, authorized	500,000,000		500,000,000
Common stock, issued	309,592,620		309,491,082							243
Common stock, outstanding	309,003,589	[1]	308,864,609	[1]	252,235,232	252,235,232		252,235,232
[1]	Par value of share amounts is $0.01

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Cash Flow from Operating Activities:
Net Income	$ 314	$ 117
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	418	362
Impairment of non-current assets		7
Accretion expenses	4	7
Regulatory assets/liabilities amortization	83	47
Regulatory assets/liabilities carrying cost	13	20
Pension cost	66	54
Earnings from equity method investments	(2)
Amortization of debt cost (premium)	(15)	2
Gain on sale of equity method investment	(34)
Unrealized losses on marked to market derivative contracts	23	50
Deferred taxes	244	(35)
Other non-cash items	(2)
Changes in current operating assets and liabilities:
Decrease in accounts receivable and unbilled revenues	85	91
Decrease in inventories	65	73
(Increase) decrease in other assets/liabilities	(100)	2
Decrease in accounts payable and accrued liabilities	(12)	(131)
(Decrease) increase in taxes accrued	(7)	21
(Increase) decrease in regulatory assets/liabilities	(235)	95
Net Cash Provided by Operating Activities	908	782
Cash Flow from Investing Activities:
Capital expenditures	(674)	(530)
Contributions in aid of construction	41	10
Government grants		13
Proceeds from sale of equity method and other investment	57	3
Proceeds from asset sale	43
Receipts from (payments to) affiliates	2	(5)
Other investments and equity method investments, net	(6)	17
Net Cash Used in Investing Activities	(537)	(492)
Cash Flow from Financing Activities:
Non-current note issuance		350
Repayments of non-current debt	(45)	(69)
Repayments of other short-term debt, net	(160)
Payments on tax equity financing arrangements	(53)	(54)
Repayments of capital leases	(4)	(14)
Repurchase of common stock	(4)
Issuance of common stock	(2)
Dividends paid	(134)
Net Cash (Used in) Provided by Financing Activities	(402)	213
Net (Decrease) Increase in Cash and Cash Equivalents	(31)	503
Cash and Cash Equivalents, Beginning of Period	427	482
Cash and Cash Equivalents, End of Period	396	985
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	114	76
Cash paid for income taxes	$ 7	$ 8

Condensed Consolidated Stateme8

Condensed Consolidated Statements of Changes in Equity (Unaudited) - USD ($) $ in Millions		Total	Common stock	Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Total Stockholders' Equity	Non controlling Interests
Balance at Dec. 31, 2014		$ 12,477	$ 3	$ 11,375		$ 1,182	$ (99)	$ 12,461	$ 16
Balance, shares at Dec. 31, 2014	[1]	252,235,232
Net Income		$ 117				117		117
Other comprehensive income (loss), net of tax		3					3	3
Comprehensive Income Attributable to Avangrid, Inc.		120
Balance at Jun. 30, 2015		$ 12,597	3	11,375		1,299	(96)	12,581	16
Balance, shares at Jun. 30, 2015	[1]	252,235,232
Balance at Dec. 31, 2015		$ 15,066	3	13,653		1,449	(52)	15,053	13
Balance, shares at Dec. 31, 2015	[1]	308,864,609
Net Income		$ 314				314		314
Other comprehensive income (loss), net of tax		(42)					(42)	(42)
Comprehensive Income Attributable to Avangrid, Inc.		272
Dividends declared		$ (267)				(267)		(267)
Reissuance of common stock held in trust, shares	[1]	134,921
Issuance of common stock		$ (2)		(2)				(2)
Issuance of common stock, shares	[1]	101,538
Repurchase of common stock		$ (4)			$ (4)			(4)
Repurchase of common stock, shares	[1]	(97,479)
Balance at Jun. 30, 2016		$ 15,065	$ 3	$ 13,651	$ (4)	$ 1,496	$ (94)	$ 15,052	$ 13
Balance, shares at Jun. 30, 2016	[1]	309,003,589
[1]	Par value of share amounts is $0.01

Condensed Consolidated Stateme9

Condensed Consolidated Statements of Changes in Equity (Unaudited) (Parenthetical) - USD ($) $ in Millions	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015
Statement Of Stockholders Equity [Abstract]
Common Stock, Par or Value Per Share	$ 0.01
Other Comprehensive Income (Loss), Net of Taxes	$ (26)	$ 1.6

Background and Nature of Operat

Background and Nature of Operations	6 Months Ended
	Jun. 30, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Background and Nature of Operations	Note 1. Background and Nature of Operations Avangrid, Inc., formerly Iberdrola USA, Inc. (AVANGRID, we or the Company), is an energy services holding company engaged in the regulated energy distribution business through its principal subsidiary Avangrid Networks, Inc. (Networks). Effective as of April 30, 2016, and its subsidiaries (UIL) were transferred to a wholly-owned subsidiary of Networks During the six months ended June 30, 2016, we completed the sale of our interest in Iroquois Gas Transmission System L.P. (Iroquois) to an unaffiliated third party for proceeds of $53.8 million and an impact to net income of $19.0 million.

Basis of Presentation

Basis of Presentation	6 Months Ended
	Jun. 30, 2016
Organization Consolidation And Presentation Of Financial Statements [Abstract]
Basis of Presentation	Note 2. Basis of Presentation The accompanying notes should be read in conjunction with the notes to the combined and consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2015 and 2014 and for the three years ended December 31, 2015 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015. The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries Networks and ARHI. Consolidated accounts of UIL have been included in the consolidated financial statements of AVANGRID since December 16, 2015, the date of acquisition of UIL. 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 six months ended June 30, 2016, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2016. Revision of estimated useful lives of wind power station assets at Renewables Renewables’ wind power station assets in service less salvage value, if any, are depreciated using the straight-line method over their estimated useful lives. Renewables’ effective depreciation rate, excluding decommissioning, was 4.0% in both 2015 and 2014. Renewables reviews the estimated useful lives of its fixed assets on an ongoing basis. In the first quarter of 2016, this review indicated that the actual lives of certain assets at wind power stations are expected to be longer than the previously estimated useful lives used for depreciation purposes. As a result, effective January 1, 2016, Renewables changed the estimates of the useful lives of certain assets from 25 years to 40 years, capped at the lease term if lower, to better reflect the estimated periods during which these assets are expected to remain in service. The weighted average useful life of our wind farm assets is now approximately 30 years. We are continuing to assess lease extensions with leaseholders to potentially increase the average useful life of our wind farm assets to above 30 years. .

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	6 Months Ended
	Jun. 30, 2016
Accounting Policies [Abstract]
Significant Accounting Policies and New Accounting Pronouncements	Note 3. Significant Accounting Policies and New Accounting Pronouncements As of June 30, 2016, there have been no material changes to any significant accounting policies described in our combined and consolidated financial statements as of December 31, 2015 and 2014 and for the three years ended December 31, 2015. There have been no new accounting pronouncements issued since the filing of the combined and consolidated financial statements as of December 31, 2015 and 2014 and for the three years ended December 31, 2015, that we expect to have a material effect on our condensed consolidated interim financial statements.

Acquisition of UIL

Acquisition of UIL	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Acquisition of UIL	Note 4. Acquisition of UIL On December 16, 2015 (acquisition date), we completed our acquisition of UIL, a diversified energy company with its portfolio of regulated utility companies in Connecticut and Massachusetts that is expected to provide us with a greater flexibility to grow the combined regulated businesses through project development and create an enhanced platform to develop transmission and distribution projects in the Northeastern United States. In connection with the acquisition, we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share and 57,255,850 shares (including those held in trust as Treasury Stock) were issued to UIL shareowners in addition to payment of $595 million in cash. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares. The acquisition was accounted for as a business combination. This method requires, among other things, that assets acquired and liabilities assumed in a business combination, with certain exceptions, be recognized at their fair values as of the acquisition date. As UIL’s common stock was publicly traded in an active market until the acquisition date, we determined that UIL’s common stock is more reliably measurable than the common stock of AVANGRID to determine the fair value of the consideration transferred in the transaction. The purchase consideration for UIL under the acquisition method is based on the stock price of UIL on the acquisition date multiplied by the number of shares issued by AVANGRID to the UIL shareowners after applying an equity exchange factor to the shares of vested restricted common stock of UIL (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other shares awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The “equity exchange factor” is the sum of one plus a fraction, (i) the numerator of which is the cash consideration and (ii) the denominator of which is the average of the volume weighted averages of the trading prices of UIL common stock on each of the ten consecutive trading days ending on (and including) the trading day that immediately precedes the closing date of the acquisition minus $10.50. The determination of the purchase price is based on a UIL stock price of $50.10 per share, which represents the closing stock price on the acquisition date. The fair value of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business combination, which was computed as follows: (millions, except share and unit data) Common shares (1) 56,629,377 Price per share of UIL common stock as of the acquisition date $ 50.10 Subtotal value of common shares $ 2,837 Restricted stock units (2) 476,198 Other shares (3) 12,999 Equity exchange factor 1.2806 Total restricted and other shares (3) an equity exchange factor 626,473 Price per share used (5) $ 39.60 Subtotal value of restricted and other shares $ 25 Total shares of AVANGRID common stock issued to UIL shareowners (including held in trust as Treasury Stock) 57,255,850 Performance shares (4) 211,904 Equity exchange factor 1.2806 Total performance shares after applying an equity exchange factor 271,368 Price per share used (5) $ 39.60 Subtotal value of performance shares $ 11 Total consideration $ 2,873 (1) Based on UIL’s common shares outstanding on December 16, 2015 (2) Based on UIL’s shares of vested restricted stock. (3) Based on UIL’s restricted shares vested upon the change in control. (4) Based on UIL’s vested performance shares award. (5) Based on the closing share price of UIL common stock on December 16, 2015 less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The following is a summary of the components of the consideration transferred to UIL’s shareowners: (millions, except share data) Cash ($10.50 x number of UIL common shares outstanding at the acquisition date - 56,629,377) $ 595 Equity 2,278 Total consideration $ 2,873 UIL’s financial results have been included in our consolidated financial results for the periods subsequent to the December 16, 2015 acquisition date. The following table represents summarized unaudited pro forma financial information as if UIL had been included in our financial results for the six months ended June 30, 2015. The unaudited pro forma results include: (i) elimination of accrued transaction costs representing non-recurring expenses directly related to the transaction, and (ii) the associated tax impact on this unaudited pro forma adjustment. The unaudited pro forma results do not reflect any cost saving synergies from operating efficiencies or the effect of the incremental costs incurred in integrating the two companies. Accordingly, these unaudited pro forma results are presented for informational purpose only and are not necessarily indicative of what the actual results of operations of the combined company would have been if the acquisition had occurred at the beginning of the periods presented, nor are they indicative of future results of operations: Three Months Ended Six Months Ended June 30, 2015 (millions) Revenue $ 1,251 $ 3,062 Net income $ 31 $ 203 The fair value of assets acquired and liabilities assumed from our acquisition of UIL was based on a preliminary valuation and our estimates and assumptions are subject to change within the measurement period. For the majority of UIL’s assets and liabilities, primarily property, plant and equipment, fair value was determined to be the respective carrying amounts of the predecessor entity. UIL’s operations are conducted in a regulated environment where the regulatory authority allows an approved rate of return on the carrying amount of the regulated asset base. Management is in the process of finalizing our detailed analysis of various items, predominantly non-rate regulated activities, to reflect the fair value of certain assets and liabilities. The primary areas of the purchase price that are not yet finalized include, but are not limited to the allocation of the purchase price to the following: equity method investments; debt; contingent liabilities, including those related to certain environmental sites; income taxes; non-regulated property, plant and equipment and goodwill. We will finalize these amounts no later than December 16, 2016. Under U.S. GAAP, the measurement period shall not exceed one year from the acquisition date. Measurement period adjustments that we determine to be material will be recognized in future periods in our consolidated financial statements. The following is a summary of the preliminary allocation of the purchase price as of the acquisition date: (millions) Current assets, including cash of $48 million $ 500 Other investments 114 Property, plant and equipment, net 3,552 Regulatory assets 966 Other assets 52 Current liabilities (493 ) Regulatory liabilities (493 ) Non-current debt (1,878 ) Other liabilities (1,201 ) Total net assets acquired at fair value 1,119 Goodwill – consideration transferred in excess of fair value assigned 1,754 Total estimated consideration $ 2,873 Goodwill generated from the acquisition of UIL has been assigned to the reporting units under the Networks reportable segment and is primarily attributable to expected future growth of the combined regulated businesses and enhanced platform to develop transmission and distribution projects in the Northeastern United States. The goodwill generated from this acquisition is not deductible for tax purposes. As part of the preliminary allocation of the purchase price we have determined a fair value of contingent liabilities of approximately $44.0 million relating to certain environmental sites.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	6 Months Ended
	Jun. 30, 2016
Regulated Operations [Abstract]
Regulatory Assets and Liabilities	Note 5. Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. Substantially all assets or liabilities for which funds have been expended or received are either included in the rate base or are accruing a carrying cost until they will be included in the rate base. The primary items that are not included in the rate base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses, debt premium, environmental remediation costs which is primarily the offset of accrued liabilities for future spending, unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded , Regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment. On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal (Proposal) in connection with a three-year rate plan for electric and gas service at New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RGE) effective May 1, 2016. Following the approval of the Proposal most of these items related to NYSEG are amortized over a five-year period, except the portion of storm costs to be recovered over ten years, 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. RGE 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 RGE, which net to a regulatory liability, remains deferred and will not be amortized until future proceedings or will be used to recover costs of the Ginna Reliability Support Services Agreement (Ginna RSSA). In the approved Proposal the allowed rate of return on common equity is 9.0% for all companies. The equity ratio for each company is 48%; however the equity ratio is set at 50% for earnings sharing purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% ROE, respectively, in the first year. The rate plans also include the implementation of a rate adjustment mechanism designed to return or collect certain defined reconciled revenues and costs; new depreciation rates; and continuation of the existing revenue decoupling mechanisms for each business. Following the approval of the Proposal by the NYPSC, unfunded future income taxes were adjusted for the amount of $126 million to reflect the change from a flow through to normalization method, which has been recorded as an increase to income tax expense and an offsetting increase to revenue, for the three and six month periods ended June 30, 2016. The amounts will be collected over a period of fifty years. On July 1, 2016, the United Illuminating Company (UI) filed an application with the Connecticut Public Utilities Regulatory Authority (PURA) requesting approval of a three-year rate plan commencing January 1, 2017, and extending through December 31, 2019. We expect PURA to rule on UI’s rate request in December 2016. UI’s application requests an increase of $65.6 million in 2017, an additional $21.1 million in 2018, and an additional $13.4 million in 2019. The application includes a rate levelization proposal to moderate the customer impact of the necessary revenue increases. The proposal defers a portion of the first and second year increases and spreads recovery of the overall increase by approximately equivalent amounts over the three years of the rate plan with carrying charges included. The proposal results in levelized revenue requirement increases of $40.7 million in 2017, $47.4 million in 2018 and $39.1 million in 2019, followed by an offset of $25.6 million at the end of the three year rate plan to equate the levelized recovery to the non-levelized revenue requirement increase. UI’s rate request is attributable primarily to the amount of capital expenditures devoted to the company’s electric distribution system for the purpose of reliability and system resiliency, both in relation to routine operations and during major storm events. UI’s application also proposes continuation of its revenue decoupling mechanism and proposes a new earnings sharing mechanism (ESM). Under the proposed ESM, 50% of UI’s earnings in excess of the allowed ROE, plus a deadband above the allowed ROE, would be flowed through to the benefit of customers. The proposed ESM includes a 20-basis point deadband in 2017 above the authorized ROE, within which there would be no sharing. This deadband would be 30 basis points in 2018 and 40 basis points in 2019. UI proposes to continue applying any dollars due to customers to reduce the storm regulatory asset, if one exists. If none exists, then the customer share would be provided through a bill credit. Current and non-current regulatory assets as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 22 $ 8 Pension and other post-retirement benefits 7 13 Storm costs 40 8 Temporary supplemental assessment surcharge 5 7 Reliability support services 18 — Revenue decoupling mechanism 17 6 Hedges losses 4 37 Contracts for differences 18 18 Hardship programs 16 13 Deferred property tax 10 — Plant decommissioning 7 — Deferred purchased gas 1 12 Deferred transmission expense 23 12 Environmental remediation costs 17 37 Other 67 48 Total Current Regulatory Assets 272 219 Non-current Pension and other post-retirement benefits cost deferrals 147 151 Pension and other post-retirement benefits 1,449 1,509 Storm costs 207 251 Deferred meter replacement costs 33 34 Unamortized losses on reacquired debt 21 23 Environmental remediation costs 273 271 Unfunded future income taxes 494 549 Asset retirement obligation 19 24 Deferred property tax 40 45 Federal tax depreciation normalization adjustment 163 158 Merger capital expense target customer credit 12 15 Debt premium 129 141 Contracts for differences 71 50 Hardship programs 21 29 Other 62 64 Total Non-current Regulatory Assets $ 3,141 $ 3,314 “Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings. “Storm costs” for Central Maine Power (CMP), NYSEG and RGE are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. The portion of storm costs for the amount of $123 million is being recovered over ten-year period and the remaining portion is being amortized over five years following the approval of the Proposal by the NYPSC. 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 June 30, 2016. “Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. Following the approval of the Proposal by the NYPSC, these amounts will be collected over a period of fifty years. “Asset retirement obligations” (ARO) represent the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability. “Deferred property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The New York (NY) amount is being amortized over a five year period following the approval of the Proposal by the NYPSC. “Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rates years covering 2011 forward. The recovery period in NY is from 27 to 39 years and for CMP this will be determined in future Maine Public Utility Commission (MPUC) rate proceedings. “Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates. “Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates. “Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base. “Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts. The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability. “Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments. “Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements. Current and non-current regulatory liabilities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Current Reliability support services (Cayuga) $ 10 $ 16 Non by-passable charges 6 7 Energy efficiency portfolio standard 40 33 Gas supply charge and deferred natural gas cost 12 6 Transmission revenue reconciliation mechanism 13 16 Pension and other post-retirement benefits 17 3 Carrying costs on deferred income tax bonus depreciation 15 — Yankee DOE Refund — 5 Merger related rate credits — 20 Revenue decoupling mechanism 22 14 Other 48 27 Total Current Regulatory Liabilities 183 147 Non-current Accrued removal obligations 1,107 1,084 Asset sale gain account 9 8 Carrying costs on deferred income tax bonus depreciation 101 116 Economic development 36 36 Merger capital expense target customer credit account 15 17 Pension and other post-retirement benefits 78 90 Positive benefit adjustment 43 51 New York state tax rate change 10 17 Post term amortization 3 25 Theoretical reserve flow thru impact 27 31 Deferred property tax 18 15 Net plant reconciliation 10 10 Variable rate debt 30 32 Carrying costs on deferred income tax - Mixed Services 263(a) 28 31 Rate refund – FERC ROE proceeding 21 21 Merger-related rate credits 24 24 Accumulated deferred investment tax credits 12 10 Asset retirement obligation 13 13 Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge — 21 Low income programs 45 42 Unfunded future income taxes — 27 Non-firm margin sharing credits 11 8 Deferred income taxes regulatory 521 519 Other 63 93 Total Non-current Regulatory Liabilities $ 2,244 $ 2,360 “Reliability support services (Cayuga)” represents the difference between actual expenses for reliability support services and the amount provided for in rates. This will be refunded to customers within the next year. “Non by-passable charges” represent the non by-passable charge paid by all customers. An asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered. This liability will be refunded to customers within the next year. “Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year. “Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five years following the approval of the Proposal by the NYPSC. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is five years following the approval of the Proposal by the NYPSC “Economic development” represents the economic development program which enables NYSEG and RGE to foster economic development through attraction, expansion, and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RGE varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is five years following the approval of the Proposal by the NYPSC. “Merger capital expense target customer credit” account was created as a result of NYSEG and RGE not meeting certain capital expenditure requirements established in the order approving the purchase of Energy East by Iberdrola. The amortization period is five years following the approval of the Proposal by the NYPSC. “Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this a regulatory liability is not reflected within rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Energy East. This is being used to moderate increases in rates. The amortization period is five years following the approval of the Proposal by the NYPSC and included in the Ginna RSSA settlement. “New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from 7.1% to 6.5%. The amortization period is five years following the approval of the Proposal by the NYPSC. “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five years following the approval of the Proposal by the NYPSC. “Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is five years following the approval of the Proposal by the NYPSC. “Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the three and six month period ended June 30, 2016, respectively, $0 and $20 million of rate credits was applied against customer bills. “Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred. “Low Income Programs” represent various hardship and payment plan programs approved for recovery. “Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Fair Value of Financial Instruments and Fair Value Measurements	Note 6. 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 RGE enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the New York Independent System Operator (NYISO). RGE hedges all its electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value RGE’s open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. NYSEG has a combination of Level 1 and Level 2 fair values for its electric energy derivative contracts. A portion of its electric load obligations are exchange traded contracts in a NYISO location where an active market exists. The forward market prices used to value NYSEG’s open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. A portion of NYSEG’s electric energy derivative contracts are non-exchange traded contracts that are valued using inputs that are directly observable for the asset or liability, or indirectly observable through corroboration with observable market data and therefore we include the fair value in Level 2. · NYSEG and RGE enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). Because we use prices quoted in an active market we include the fair value measurements in Level 1. · NYSEG, RGE and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used but because an unobservable basis adjustment is added to the forward prices we include the fair value measurement for these contracts in Level 3. · Contracts for differences (CfDs) entered into by The United Illuminating Company (UI) are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion on CfDs). We determine the fair value of our derivative assets and liabilities associated with Renewables and Gas activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical product with no adjustment are included in the Level 1 fair value. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in Level 2 fair value. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in Level 3 fair value. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists. The financial instruments measured at fair value as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 19 48 52 (54 ) 65 Derivative financial instruments - gas 138 26 99 (191 ) 72 Contracts for differences — — 24 — 24 Total 157 74 175 (245 ) 161 Derivative liabilities Derivative financial instruments - power (26 ) (22 ) (5 ) 42 (11 ) Derivative financial instruments - gas (172 ) (35 ) (55 ) 201 (61 ) Contracts for differences — — (112 ) — (112 ) Derivative financial instruments - other — — (1 ) — (1 ) Total $ (198 ) $ (57 ) $ (173 ) $ 243 $ (185 ) As of December 31, 2015 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 39 $ — $ — $ — $ 39 Derivative assets Derivative financial instruments - power 10 81 48 (71 ) 68 Derivative financial instruments - gas 267 25 68 (280 ) 80 Contracts for differences — — 29 — 29 Total 277 106 145 (351 ) 177 Derivative liabilities Derivative financial instruments - power (43 ) (12 ) (14 ) 55 (14 ) Derivative financial instruments - gas (193 ) (40 ) (51 ) 212 (72 ) Contracts for differences — — (96 ) — (96 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (236 ) $ (52 ) $ (164 ) $ 267 $ (185 ) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and six months ended June 30, 2016 and 2015, respectively, is as follows: Three Months Ended Six Months Ended June 30, June 30, (Millions) 2016 2015 2016 2015 Fair Value Beginning of Period, $ (45 ) $ 54 $ (19 ) $ 57 Gains recognized in operating revenues 40 31 44 42 (Losses) recognized in operating revenues — (4 ) (1 ) (5 ) Total gains (losses) recognized in operating revenues 40 27 43 37 Gains recognized in OCI — 2 1 3 (Losses) recognized in OCI — — — (1 ) Total Gains (Losses) Recognized in OCI — 2 1 2 Net change recognized in regulatory assets and liabilities 3 — (22 ) — Purchases (1 ) 22 (1 ) 21 Settlements (2 ) (4 ) (7 ) (7 ) Transfers out of Level 3(a) 7 2 7 (7 ) Fair Value as of June 30, $ 2 $ 103 $ 2 $ 103 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 $ 40 $ 27 $ 43 $ 37 (a) 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. They represent the variability in prices for those transactions that fall into the illiquid period (beyond 2 years), using past and current views of prices for those future periods. As of June 30, 2016 Variability Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions delivery Transactions valued forward market Observable extrapolated forward power not can NYMEX $ 4.24 $ 7.37 $ 1.64 with delivery exceeding two on a corroborated by SP15 $ 44.09 $ 80.28 $ 14.25 period > two years discounted market data for Mid C $ 35.32 $ 83.93 $ 3.60 years basis identical or Cinergy $ 36.29 $ 77.49 $ 18.53 similar Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are traded at liquid hubs in the West and Midwest and are used to hedge merchant wind production in those regions. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs and concluded that no material change to the financial statements is expected given the following: (i) any changes in the fair value of the gas swaps hedging inventory would be expected to be largely offset by changes in the value of the inventory; (ii) any changes in the fair value of the gas swaps hedging merchant generation would be expected to be significantly offset by changes in the value of future power generation. Future commodity prices are the significant unobservable inputs to fair value. Any significant increases in prices would result in a lower fair value of derivatives. Conversely, significant reductions in prices would result in a higher fair value of derivatives. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models themselves. 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. Transaction models 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 models are applied to the full duration of transactional models to a maximum of approximately thirty years. The carrying amounts for cash and cash equivalents, accounts receivable, accounts payable, notes payable and interest accrued approximate their estimated fair values and are considered as Level 1. The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input June 30, 2016 Risk of non-performance 0.05% - 0.77% Discount rate 0.71% - 1.49% Forward pricing ($ per MW) $3.15 - $9.55 Fair Value of Debt As of June 30, 2016 and December 31, 2015 debt consisted of first mortgage bonds, fixed and variable unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $5,252 million and $4,985 million as of June 30, 2016 and December 31, 2015, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy pertaining to the fair value of debt is considered as Level 2, except for unsecured pollution control notes-variable with a fair value of $204 million as of both June 30, 2016 and December 31, 2015, which are considered Level 3. The fair value of these unsecured pollution control notes-variable are determined using unobservable interest rates as the market for these notes is inactive.

Derivative Instruments and Hedg

Derivative Instruments and Hedging	6 Months Ended
	Jun. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Derivative Instruments and Hedging	Note 7. 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 RGE have an electric commodity charge that passes through rates costs for the market price of electricity. They use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. The amount recognized in regulatory assets for electricity derivatives was a loss of $7.3 million as of June 30, 2016, and $34.3 million as of December 31, 2015. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a loss of $13.1 million and $9.4 million, and a loss of $47.9 million and $12.0 million for the three and six months ended June 30, 2016 and 2015, respectively. NYSEG and RGE have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RGE use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities in accordance with the accounting requirements for regulated operations. The amount recognized in regulatory assets for natural gas hedges was a gain of $2.8 million as of June 30, 2016, and a loss of $3.1 million as of December 31, 2015. The amount reclassified from regulatory assets into income, which is included in natural gas purchased, was a loss of $0 and $1.4 million, and a loss of $3.4 million and $3.0 million for the three and six months ended June 30, 2016 and 2015, respectively. Contracts for Differences Pursuant to PURA, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers. PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability). For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of June 30, 2016, UI has recorded a gross derivative asset of $24 million ($0.1 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $88 million, a gross derivative liability of $112 million ($83 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $1 million. As of December 31, 2015, UI had recorded a gross derivative asset of $29 million ($1 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $68 million, a gross derivative liability of $96 million ($61 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $1 million. The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three and six months ended June 30, 2016, respectively, were as follows: Three Months Ended Six Months Ended June 30, 2016 (Millions) Regulatory Assets - Derivative liabilities $ (2 ) $ (5 ) Regulatory Liabilities - Derivative assets $ 6 $ (16 ) The net notional volumes of the outstanding derivative instruments associated with Networks activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Wholesale electricity purchase contracts (MWh) 6.8 6.7 Natural gas purchase contracts (Dth) 5.1 4.8 Fleet fuel purchase contracts (Gallons) 3.0 3.8 The offsetting of derivatives, location and amounts of derivatives designated as hedging instruments associated with Networks activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 10 $ 14 $ — $ — Derivative liabilities — — (28 ) (84 ) 10 14 (28 ) (84 ) Designated as hedging instruments Derivative assets 16 5 14 5 Derivative liabilities (13 ) (5 ) (20 ) (8 ) 3 — (6 ) (3 ) Total derivatives before offset of cash collateral 13 14 (34 ) (87 ) Cash collateral receivable (payable) — — 4 3 Total derivatives as presented in the balance sheet $ 13 $ 14 $ (30 ) $ (84 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 11 $ 18 $ (28 ) $ (68 ) Derivative liabilities — — — — 11 18 (28 ) (68 ) Designated as hedging instruments Derivative assets 3 6 3 6 Derivative liabilities (3 ) (6 ) (42 ) (7 ) — — (39 ) (1 ) Total derivatives before offset of cash collateral 11 18 (67 ) (69 ) Cash collateral receivable (payable) — — 37 — Total derivatives as presented in the balance sheet $ 11 $ 18 $ (30 ) $ (69 ) The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended June 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) 2016 Interest rate contracts $ — Interest expense $ (2 ) Commodity contracts — Operating expenses — Total $ — $ (2 ) 2015 Interest rate contracts $ — Interest expense $ (2 ) Commodity contracts — Operating expenses (1 ) Total $ — $ (3 ) Six Months Ended June 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) 2016 Interest rate contracts $ — Interest expense $ (4 ) Commodity contracts — Operating expenses (1 ) Total $ — $ (5 ) 2015 Interest rate contracts $ — Interest expense $ (4 ) Commodity contracts (1 ) Operating expenses (2 ) Total $ (1 ) $ (6 ) (a) The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $80.8 million and $84.9 million as of June 30, 2016 and December 31, 2015, respectively. We recorded $2.0 million and $2.2 million in net derivative losses related to discontinued cash flow hedges for the three months ended June 30, 2016 and 2015, respectively. We recorded $4.0 million and $4.4 million in net derivative losses related to discontinued cash flow hedges for the six months ended June 30, 2016 and 2015, respectively We will amortize approximately $8.0 million of discontinued cash flow hedges in 2016. During the three and six months ended June 30, 2016 and 2015, there was no ineffective portion for cash flow hedges. The unrealized loss of $1.4 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable as of June 30, 2016. We expect that $1.1 million of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is eighteen months. (b) Renewables and Gas activities We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities. Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also enter into basis swaps to hedge the value of our contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and delivery point of the contracted transport in future periods. Both Renewables and Gas have proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future power sales and gas purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and AECO basis swaps that hedge the fuel requirements of its Klamath facility. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms. Gas also periodically designates NYMEX fixed price derivative contracts as cash flow hedges related to its firm storage trading activities. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future gas sales and purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. Derivative contracts entered into to hedge the gas transport trading activities are not designated as cash flow hedges, with all changes in fair value of such derivative contracts recorded in current period earnings. The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (MWh/Dth in millions) Wholesale electricity purchase contracts 3 3 Wholesale electricity sales contracts 6 6 Foreign exchange forward purchase contracts — 4 Natural gas and other fuel purchase contracts 331 332 Financial power contracts 6 7 Basis swaps – purchases 68 67 Basis swaps – sales 69 80 The fair values of derivative contracts associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Wholesale electricity purchase contracts $ (1 ) $ (13 ) Wholesale electricity sales contracts 11 35 Foreign exchange forward purchase contracts — (1 ) Natural gas and other fuel purchase contracts 18 10 Financial power contracts 44 32 Basis swaps – purchases (5 ) 1 Basis swaps – sales (4 ) (2 ) Total $ 63 $ 62 The effect of trading and non-trading derivatives, respectively, associated with Renewables and Gas activities for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Wholesale electricity purchase contracts $ 5 $ 3 $ 5 $ 10 Wholesale electricity sales contracts (6 ) (13 ) (7 ) (18 ) Financial power contracts 1 11 2 10 Financial and natural gas contracts (1 ) 7 (31 ) (48 ) Total (Loss) Gain $ (1 ) $ 8 $ (31 ) $ (46 ) Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Wholesale electricity purchase contracts $ 11 $ 6 $ 8 $ 5 Wholesale electricity sales contracts (20 ) (19 ) (14 ) (22 ) Financial power contracts (17 ) (1 ) (16 ) 4 Financial and natural gas contracts 35 6 26 12 Total Gain (Loss) $ 9 $ (8 ) $ 4 $ (1 ) Such gains and losses are included in 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 and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 112 $ 103 $ 124 $ 4 Derivative liabilities (29 ) (10 ) (186 ) (17 ) 83 93 (62 ) (13 ) Designated as hedging instruments Derivative assets 8 8 — — Derivative liabilities — — (34 ) (10 ) 8 8 (34 ) (10 ) Total derivatives before offset of cash collateral 91 101 (96 ) (23 ) Cash collateral receivable (payable) (16 ) (42 ) 39 9 Total derivatives as presented in the balance sheet $ 75 $ 59 $ (57 ) $ (14 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 186 $ 113 $ 117 $ 4 Derivative liabilities (85 ) (14 ) (169 ) (29 ) 101 99 (52 ) (25 ) Designated as hedging instruments Derivative assets 56 13 — — Derivative liabilities — — (9 ) — 56 13 (9 ) — Total derivatives before offset of cash collateral 157 112 (61 ) (25 ) Cash collateral receivable (payable) (80 ) (41 ) — — Total derivatives as presented in the balance sheet $ 77 $ 71 $ (61 ) $ (25 ) The effect of derivatives in cash flow hedging relationships on OCI and income for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended June 30, (Loss) Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Gain Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2016 Commodity contracts $ (38 ) Revenues $ (2 ) Total $ (38 ) $ (2 ) 2015 Commodity contracts $ — Revenues $ — Total $ — $ — Six Months Ended June 30, (Loss) Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Gain Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2016 Commodity contracts $ (35 ) Revenues $ (48 ) Total $ (35 ) $ (48 ) 2015 Commodity contracts $ 1 Revenues $ — Total $ 1 $ — (a) Changes in OCI are reported on a pre-tax basis. Amounts will be reclassified from accumulated OCI into income in the period(s) during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $25.9 million of losses included in accumulated OCI at June 30, 2016, is expected to be reclassified into earnings within the next 12 months. During the three months ended June 30, 2016 and 2015, we recorded a net loss of $0.4 million and $1.4 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges. During the six months ended June 30, 2016 and 2015, we recorded a net loss of $4.8 million and $1.4 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges. (c) Counterparty credit risk management NYSEG and RGE face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are dependent on the counterparty’s or the counterparty’s guarantor’s applicable credit rating, normally Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold. The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of June 30, 2016, UI would have had to post an aggregate of approximately $10.2 million in collateral. We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amounts of cash collateral under master netting arrangements that have not been offset against net derivative positions were $1 million and $11 million as of June 30, 2016 and December 31, 2015, respectively. Derivative instruments settlements and collateral payments are included in “Other assets” and “Other 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 June 30, 2016 is $7 million, for which we have posted collateral.

Contingencies

Contingencies	6 Months Ended
	Jun. 30, 2016
Commitments And Contingencies Disclosure [Abstract]
Contingencies	Note 8. Contingencies We are party to various legal disputes arising as part of our normal business activities. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency. MNG Rate Case On March 5, 2015, MNG filed a rate case in order to further recover future investments and provide safe and adequate service. MNG requested a 10.0% ROE and 50.0% equity ratio. The MPUC Staff recommended a separate revenue requirement for MNG’s Augusta customers and MNG’s non-Augusta customers. The Staff also recommended a $19.95 million disallowance of the Augusta Expansion investment based upon the Staff’s conclusion that MNG’s management of the Augusta Expansion Project was imprudent. On November 6, 2015, a stipulation was filed with the MPUC, which was executed by MNG, the Office of Public Advocate and the City of Augusta. The stipulation contained a combined revenue requirement for Augusta and Non-Augusta based on a 9.55% ROE and 50% equity ratio. The stipulation also provided for an initial Augusta investment disallowance of $6 million and an investment phase-in of $10 million. On December 22, 2015, the MPUC rejected the proposed stipulation as not in the public interest. In January 2016, the Administrative Law Judge established a new litigation schedule. The litigation was suspended at the end of January 2016 for settlement discussions. We reserved $6 million for this case at the end of 2015. On May 3, 2016, all active parties to the case filed a stipulation which settled all matters at issue in the case and reflected a 10-year rate plan through April 30, 2026. The MPUC approved the stipulation on May 17, 2016, for new rates effective June 1, 2016. The settlement structure for non-Augusta customers includes a 34.6% delivery revenue increase over five years with an allowed 9.55% ROE and 50% common equity ratio. The settlement structure for Augusta customers includes a 10-year rate plan with existing Augusta customers being charged rates equal to non-Augusta customers plus a surcharge which increases annually for five years. New Augusta customers will have rates set based on an alternate fuel market model. In year seven of the rate plan MNG will submit a cost of service filing for the Augusta area to determine if the rate plan should continue. This cost of service filing will exclude $15 million of initial 2012/2013 gross plant investment, however the stipulation allows for accelerated depreciation of these assets. If the Augusta area’s cost of service filing illustrates results above a 14.55% ROE then the rate plan may cease, otherwise the rate plan would continue. A disallowance for the initial 2012/2013 gross plant investment is not part of the approved stipulation. The reserve of $6 million for this case was reversed in May 2016. Transmission - ROE Complaint – CMP and UI On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a complaint (Complaint I) with the FERC pursuant to sections 206 and 306 of the Federal Power Act. The filing parties seek an order from the FERC reducing the 11.14% base return on equity used in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) to 9.2%. CMP and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint. On June 19, 2014, the FERC issued its initial decision in this first complaint, establishing a methodology and setting an issue for a paper hearing. On October 16, 2014, FERC issued its final decision in the first complaint (Complaint I) setting the base ROE at 10.57% and a maximum total ROE of 11.74% (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 a refund report. On March 3, 2015, the FERC issued an order on requests for rehearing of its October 16, 2014 decision. The March order upheld the FERC’s initial decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average return. In June 2015 the NETOs filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. The appeal is currently pending, and we cannot predict the outcome of this appeal. On December 26, 2012, a second, ROE complaint (Complaint II) for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On June 19, 2014, FERC accepted the second complaint, established a 15-month refund effective date of December 27, 2012, and set the matter for hearing using the methodology established in the first complaint. On July 31, 2014, the Complainants filed a third ROE complaint (Complaint III) for a subsequent rate period requesting the ROE be reduced to 8.84%. On November 24, 2014, FERC accepted the third complaint, established a 15-month refund effective date of July 31, 2014, and set this matter, consolidated with Complaint II, for hearing in June 2015. Hearings were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge, relating to the refund periods and going forward period. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the New England transmission owners filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The FERC Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that, 1) for the 15-month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and 2) for the 15-month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The Initial Decision is the Administrative Law Judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in late 2016 or early 2017. CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final Complaint I decision. The CMP and UI total reserve associated with Complaints I, II and III is $21.2 million and $4.2 million, respectively, as of June 30, 2016. If adopted as final, the impact of the initial decision would be an additional aggregate reserve for Complaints II and III of $10.2 million, net of tax, which is based upon currently available information for these proceedings. We cannot predict the outcome of the Complaint II and III proceeding. On April 29, 2016, the Complainants filed a fourth ROE complaint (Complaint IV) for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%. The NETOs filed a response to the Complaint IV on June 3, 2016.We cannot predict the outcome of the Complaint IV proceeding. Yankee Nuclear Spent Fuel Disposal Claim CMP has an ownership interest in Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company, and Yankee Atomic Electric Company, (the Yankee Companies), three New England single-unit decommissioned nuclear reactor sites, and UI has an ownership interest in Connecticut Yankee Atomic Power Company. Every six years, pursuant to the statute of limitations, the Yankee Companies file a lawsuit to recover damages from the Department of Energy (DOE or Government) for breach of the Nuclear Spent Fuel Disposal Contract to remove Spent Nuclear Fuel (SNF) and Greater than Class C Waste (GTCC) as required by contract and the Nuclear Waste Policy Act beginning in 1998. The damages are the incremental costs for the Government’s failure to take the spent nuclear fuel. In 2012, the U.S. Court of Appeals issued a favorable decision in the Yankee Companies’ claim for the first six year period (Phase I). Total damages awarded to the Yankee Companies were nearly $160 million. The Yankee Companies won on all appellate points in the U.S. Court of Appeals for the Federal Circuit’s unanimous decision. The Federal Appeals Court affirmed the September 2010 U.S. Court of Federal Claims award of $39.7 million to Connecticut Yankee Atomic Power Company; affirmed the Court of Federal Claims award of $81.7 million to Maine Yankee Atomic Power Company; and increased Yankee Atomic Electric Company’s damages award from $21.4 million to $38.3 million. The Phase I damage award became final on December 4, 2012. The Yankee Companies received payment from the DOE in January 2013. CMP’s share of the award was approximately $36.5 million which was credited back to customers. UI’s share of the award was $3.8 million which was credited back to customers. In November 2013 the U.S. Court of Claims issued its decision in the Phase II case (the second 6-year period). The court’s decision awarded the Yankee Companies a combined $235.4 million (Connecticut Yankee $126.3 million, Maine Yankee $37.7 million, and Yankee Atomic $73.3 million). The Phase II period covers January 1, 2002, through December 31, 2008, for Connecticut Yankee and Yankee Atomic, and January 1, 2003, through December 31, 2008, for Maine Yankee. Maine Yankee’s damage award was lower because it recovered a larger amount in the Phase I case ($82 million) and its decommissioning was both less expensive and completed sooner than the other Yankee Companies. The damage awards flow through the Yankee Companies to shareholders (including CMP and UI) to reduce retail customer charges. In January 2014 the Government informed the Yankee Companies it would not appeal the court’s decision. As a result the Yankee Companies received full payment in April 2014. CMP’s share of the award was approximately $28.2 million which was credited back to customers. UI received approximately $12 million of such award which was applied, in part, against its remaining storm regulatory asset balance. The remaining regulatory liability balance was applied to UI’s generation service charge (GSC) “working capital allowance” and was returned to customers through the non-by-passable federally mandated congestion charge. In August 2013, the Yankee Companies filed a third round of claims against the Government seeking damages for the years 2009-2014 (Phase III). The Phase III trial was completed in July 2015 and the court issued its decision on March 25, 2016, awarding the Yankee Companies a combined $76.8 million (Connecticut Yankee $32.6 million, Maine Yankee $24.6 million and Yankee Atomic $19.6 million). The damage awards, less any amount retained to reduce future customer charges, will potentially flow through the Yankee Companies to shareholders, including CMP and UI, upon FERC approval, and will reduce retail customer charges or otherwise as specified by law. CMP and UI will receive their proportionate share of the awards that flow through based on percentage ownership. On July 18, 2016, the notice of appeal period expired and the Phase III trial award became final. We cannot predict the timing or amount of damage awards that may ultimately flow through to customers. NYPSC Staff Review of Earnings Sharing Calculations and Other Regulatory Deferrals In December 2012, the NYPSC Staff (Staff) informed NYSEG and RGE that the Staff had conducted an audit of the companies’ annual compliance filings (ACF) for 2009 through August 31, 2010, and the first rate year of the current rate plan, September 1, 2010 through August 31, 2011. The Staff’s preliminary findings indicated adjustments to deferred balances primarily associated with storm costs and the treatment of certain incentive compensation costs for purposes of the 2011 ACF. The Staff’s findings approximate $9.8 million of adjustments to deferral balances and customer earnings sharing accruals. NYSEG and RGE reviewed the Staff’s adjustments and work papers and provided a response in early 2013. NYSEG and RGE disagreed with certain Staff conclusions and as a result recorded a $3.4 million reserve in December 2012 in anticipation of settling the Staff issues. In the Proposal approved by the NYPSC (see Note 5) the parties agreed that in full and final resolution of all years through 2012, and in full and final resolution of storm-related deferrals through 2014, the companies will add $2.4 million to the customer share of earnings sharing. California Energy Crisis Litigation Two California agencies brought a complaint against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed FERC's dismissal of Renewables. Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014 FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC Trial Staff recommended that the complaint against Renewables be dismissed. A hearing was held before an administrative law judge of FERC in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market contract that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed 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 to FERC briefs on exceptions to the administrative law judge’s proposed ruling. There is no specific timetable to FERC’s ruling, but we presently expect it to be issued in late 2016. We cannot predict the outcome of this proceeding. Guarantee Commitments to Third Parties As of June 30, 2016, we had approximately $2.5 billion of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of the company and its subsidiaries in their normal course of business. The instruments only represent liabilities if the company or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of June 30, 2016, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Environmental Liability

Environmental Liability	6 Months Ended
	Jun. 30, 2016
Environmental Remediation Obligations [Abstract]
Environmental Liabilities	Note 9. 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-four waste sites, which do not include sites where gas was manufactured in the past. Fifteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six sites are included in Maine’s Uncontrolled Sites Program and one site is included on the Massachusetts Non- Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, nine of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and severable for certain sites. We have recorded an estimated liability of $6 million related to ten of the twenty-four sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another ten sites where we believe it is probable that we will incur remediation costs and or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the portion of remediation attributed to us. Manufactured Gas Plants We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Eight sites are included in the New York State Registry; eleven sites are included in the New York Voluntary Cleanup Program; three sites are part of Maine’s Voluntary Response Action Program with two of such sites being part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and where necessary remediate forty-seven of the fifty-three sites. Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $235 million to $468 million as of June 30, 2016. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives, and changes to current laws and regulations. As of June 30, 2016 and December 31, 2015, the liability associated with MGP sites in Connecticut, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $99 million. The liability to investigate and perform remediation at the known inactive MGP sites was $388 million and $397 million as of June 30, 2016 and December 31, 2015, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2048. 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 in respect of these sites as of June 30, 2016 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former manufactured gas sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor. Based on past and future clean-up costs at the sixteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the decision were upheld on appeal. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-judgment interest of $3 million. FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million, excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean up expenses at nine MPG sites. In January 2015, NYSEG sent FirstEnergy a demand for $16 million representing FirstEnergy’s share of clean-up expenses incurred by NYSEG at the nine sites from January 2010 to November 2014 while the District Court appeal was pending. Nearly all of this amount has been paid by FirstEnergy. FirstEnergy would also be liable for a share of post 2014 costs, which, based on current projections, would be $26 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Century Indemnity and OneBeacon On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share 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. Any recovery will be flowed through to NYSEG ratepayers. Century and One Beacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. We cannot predict the outcome of this matter. English Station In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. In December 2013, Evergreen and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the property; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages. On April 8, 2013, the Connecticut Department of Energy and Environmental Protection (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. Action in the administrative proceeding has been suspended until a status conference scheduled for September 1, 2016. On September 16, 2015, UI signed a Proposed Partial Consent Order that, when issued by the Commissioner of DEEP, and subject to its terms and conditions, would require UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the Proposed Partial Consent Order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut, and the Commissioner of DEEP. Pursuant to the Proposed Partial Consent Order, upon its issuance and subject to its terms and conditions, UI would be obligated to comply with the Proposed Partial Consent Order, even if the cost of such compliance exceeds $30 million. The State will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties, however it is not bound to agree to or support any means of recovery or funding. On July 18, 2016, Evergreen Power, Asnat, and certain related parties signed a proposed Consent Order that, when issued by the Commissioner of DEEP, will provide UI access to investigate and remediate the English Station site consistent with the Proposed Partial Consent Order. The Attorney General filed the Evergreen Power and Asnat Consent Order and the Proposed Partial Consent Order with DEEP on July 22, 2016, and requested the Commissioner of DEEP issue the Consent and Partial Consent Orders as final orders. Upon issuance of the final UI Partial Consent Order and availability of access to the English Station site, UI will begin to investigate and remediate certain environmental conditions within the perimeter of the English Station site consistent with the Proposed Partial Consent Order. As of December 31, 2015 we reserved $20.5 million for this case and have accrued the remaining $9.5 million in accordance with the settlement with PURA approving the acquisition. As of June 30, 2016 the reserve amount remained unchanged. We cannot predict the outcome of this matter.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	6 Months Ended
	Jun. 30, 2016
Compensation And Retirement Disclosure [Abstract]
Post-retirement and Similar Obligations	Note 10. Post-retirement and Similar Obligations We made $15 million of pension contributions for the three and six months ended June 30, 2016. We expect to make $28 million of contributions for the remainder of 2016. The components of net periodic benefit cost for pension benefits for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Service cost $ 11 $ 9 $ 22 $ 18 Interest cost 35 24 70 48 Expected return on plan assets (51 ) (39 ) (102 ) (78 ) Amortization of: Prior service costs 1 1 1 2 Actuarial loss 37 32 75 64 Net Periodic Benefit Cost $ 33 $ 27 $ 66 $ 54 The components of net periodic benefit cost for postretirement benefits for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Service cost $ 1 $ 1 $ 2 $ 2 Interest cost 6 4 12 8 Expected return on plan assets (3 ) (2 ) (6 ) (4 ) Amortization of: Prior service costs (2 ) (2 ) (4 ) (4 ) Actuarial loss 2 2 4 4 Net Periodic Benefit Cost $ 4 $ 3 $ 8 $ 6

Equity

Equity	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Equity	Note 11. Equity As of June 30, 2016, our share capital consisted of 500,000,000 shares of common stock authorized, 309,592,620 shares issued and 309,003,589 shares outstanding, 81.5% owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,651 million. As of December 31, 2015, our share capital consisted of 500,000,000 shares of common stock authorized, 309,491,082 shares issued and 308,864,609 shares outstanding, 81.5% 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 491,552 and 626,473 shares of common stock held in trust and no convertible preferred shares outstanding as of June 30, 2016 and December 31, 2015, respectively. During the six months ended June 30, 2016, we issued 101,538 shares of common stock and released 134,921 shares of common stock held in trust each having a par value of $0.01. On April 28, 2016, we entered into a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage of Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. 97,479 shares of common stock of AVANGRID in the open market. The total cost of repurchase, including commissions, was $4 million. On December 15, 2015, the Board of Directors approved our common stock dividend, accounted for as a stock split. The stock split, effected through a stock dividend, resulted in the issuance of 252,234,989 shares, which in addition to the 243 previously existing shares increased the total shares outstanding to 252,235,232. The stock dividend was effective upon the Board’s approval. All share and per share information included in the condensed consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend. Accumulated Other Comprehensive Income (Loss) Accumulated OCI for the three months ended June 30, 2016 and 2015, respectively, consisted of: As of March 31 Three Months Ended June 30, As of June 30, As of March 31 Three Months Ended June 30, As of June 30, Accumulated Other Comprehensive Income (Loss) 2015 2015 2015 2016 2016 2016 (Millions) Loss on revaluation of defined benefit plans, net of income tax expense (benefit) of $(0.1) for 2015 and $0.1 for 2016 $ (26 ) $ (1 ) $ (27 ) $ (17 ) $ — $ (17 ) Loss for nonqualified pension plans (11 ) — (11 ) (8 ) — (8 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $0.4 for 2015 and $(14.2) for 2016 (2 ) 1 (1 ) 33 (23 ) 10 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense of $1.2 for 2015 and $0.7 for 2016(a) (59 ) 2 (57 ) (80 ) 1 (79 ) Gain (loss) on derivatives qualifying as cash flow hedges (61 ) 3 (58 ) (47 ) (22 ) (69 ) Accumulated Other Comprehensive (Loss) Income $ (98 ) $ 2 $ (96 ) $ (72 ) $ (22 ) $ (94 ) Accumulated OCI for the six months ended June 30, 2016 and 2015, respectively, consisted of: As of December 31, Six Months Ended June 30, As of June 30, As of December 31, Six Months Ended June 30, As of June 30, Accumulated Other Comprehensive Income (Loss) 2014 2015 2015 2015 2016 2016 (Millions) Gain (loss) on revaluation of defined benefit plans, net of income tax expense (benefit) of $(1.0) for 2015 and $2.9 for 2016 $ (25 ) $ (2 ) $ (27 ) $ (21 ) $ 4 $ (17 ) Loss for nonqualified pension plans (11 ) — (11 ) (8 ) — (8 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $0.4 for 2015 and $(13.0) for 2016 (2 ) 1 (1 ) 31 (21 ) 10 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $2.2 for 2015 and $(15.9) for 2016(a) (61 ) 4 (57 ) (54 ) (25 ) (79 ) Gain (loss) on derivatives qualifying as cash flow hedges (63 ) 5 (58 ) (23 ) (46 ) (69 ) Accumulated Other Comprehensive (Loss) Income $ (99 ) $ 3 $ (96 ) $ (52 ) $ (42 ) $ (94 ) (a) Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Earnings Per Share

Earnings Per Share	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Net Income Per Share	Note 12. 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 six months ended June 30, 2016, while we did have securities that were dilutive, these securities did not result in a change on our earnings per share calculation result for the three and six months ended June 30, 2016. We did not have any potentially-dilutive securities for the three and six months ended June 30, 2015. In accordance with Accounting Standards Codification (ASC) Topic 260, Earnings per Share, we retroactively applied the stock split to prior period. The calculations of basic and diluted earnings per share attributable to AVANGRID, including a reconciliation of the numerators and denominators for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 102 $ 11 $ 314 $ 117 Denominator: Weighted average number of shares outstanding - basic 309,527,868 252,235,232 309,533,042 252,235,232 Weighted average number of shares outstanding - diluted 309,683,965 252,235,232 309,689,138 252,235,232 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.33 $ 0.04 $ 1.01 $ 0.46 Earnings Per Common Share, Diluted $ 0.33 $ 0.04 $ 1.01 $ 0.46

Segment Information

Segment Information	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Segment Information	Note 13. Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following three reportable segments: · Networks: including all the energy transmission and distribution activities, and any other regulated activity originating in New York and Maine, and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. · Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. · Gas: including gas trading and storage businesses carried on by the AVANGRID Group. Products and services are sold between reportable segments and affiliate companies at cost. The chief operating decision maker evaluates segment performance based on segment adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) defined as net income adding back net income attributable to other noncontrolling interests, income tax expense, depreciation and amortization, impairment of non-current assets and interest expense net of capitalization, and then subtracting other income and (expense) and earnings from equity method investments per segment. Segment income, expense, and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the condensed consolidated financial statements. Segment information for the three months ended June 30, 2016, consisted of: Three Months Ended June 30, 2016 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,211 $ 242 $ (14 ) $ — $ 1,439 Revenue - intersegment 2 2 3 (7 ) — Depreciation and amortization 126 81 6 — 213 Operating income (loss) 299 58 (28 ) (7 ) 322 Adjusted EBITDA 425 139 (22 ) (7 ) 535 Earnings (losses) from equity method investments $ 3 $ (3 ) $ — $ — $ — (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the three months ended June 30, 2016, are: $949 million from regulated electric operations, $263 million from regulated gas operations and $(1) million amounts from other operations of Networks; $242 million from renewable energy generation of Renewables; $5 million from gas storage services and $(19) million from gas trading operations of Gas. Segment information for the three months ended June 30, 2015, consisted of: Three Months Ended June 30, 2015 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 715 $ 243 $ (19 ) $ — $ 939 Revenue – intersegment — 8 9 (17 ) — Impairment of non-current assets — 7 — — 7 Depreciation and amortization 94 89 4 — 187 Operating income (loss) 100 8 (26 ) (9 ) 73 Adjusted EBITDA 194 104 (22 ) (9 ) 267 Earnings (losses) from equity method investments $ — $ (3 ) $ — $ 2 $ (1 ) (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the three months ended June 30, 2015, are: $608 million from regulated electric operations, $110 million from regulated gas operations and $(3) million amounts from other operations of Networks; $243 million from renewable energy generation of Renewables; $4 million from gas storage services and $(23) million from gas trading operations of Gas. Segment information as of and for the six months ended June 30, 2016, consisted of: Six Months Ended June 30, 2016 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,601 $ 518 $ (11 ) $ 1 $ 3,109 Revenue - intersegment 2 4 12 (18 ) — Depreciation and amortization 244 161 13 — 418 Operating income (loss) 611 107 (38 ) (9 ) 671 Adjusted EBITDA 855 268 (25 ) (9 ) 1,089 Earnings (losses) from equity method investments 6 (4 ) — — 2 Capital expenditures $ 470 $ 203 $ 1 $ — $ 674 As of June 30, 2016 Property, plant and equipment 12,525 7,800 505 — 20,830 Equity method investments 131 240 — — 371 Total assets $ 19,871 $ 10,437 $ 1,034 $ (931 ) $ 30,411 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the six months ended June 30, 2016, are: $1,862 million from regulated electric operations, $740 million from regulated gas operations and $(1) million amounts from other operations of Networks; $518 million from renewable energy generation of Renewables; $12 million from gas storage services and $(23) million from gas trading operations of Gas. Segment information for the six months ended June 30, 2015, consisted of: Six Months Ended June 30, 2015 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,713 $ 482 $ (29 ) $ — $ 2,166 Revenue – intersegment — 9 18 (27 ) — Impairment of non-current assets — 7 — — 7 Depreciation and amortization 180 172 9 1 362 Operating income (loss) 289 34 (41 ) (13 ) 269 Adjusted EBITDA 469 213 (32 ) (12 ) 638 Earnings (losses) from equity method investments — (2 ) — 2 — Capital expenditures $ 355 $ 172 $ 3 $ — $ 530 As of December 31, 2015 Property, plant and equipment 12,363 7,835 513 — 20,711 Equity method investments 110 253 — 22 385 Total assets $ 20,126 $ 10,685 $ 1,265 $ (1,333 ) $ 30,743 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the six months ended June 30, 2015, are: $1,336 million from regulated electric operations, $382 million from regulated gas operations and $(5) million from other operations of Networks; $482 million from renewable energy generation of Renewables; $6 million from gas storage services and $(35) million from gas trading operations of Gas. Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three and six months ended June 30, 2016 and 2015, respectively, is as follows: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Consolidated Adjusted EBITDA $ 535 $ 267 $ 1,089 $ 638 Less: Impairment of non-current assets — 7 — 7 Depreciation and amortization 213 187 418 362 Interest expense, net of capitalization 68 66 152 127 Income tax expense 172 5 276 47 Add: Other income and (expense) 20 10 69 22 Earnings (losses) from equity method investments — (1 ) 2 — Consolidated Net Income $ 102 $ 11 $ 314 $ 117

Related Party Transactions

Related Party Transactions	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Related Party Transactions	Note 14. Related Party Transactions We engage in related party transactions which are generally billed at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended June 30, 2016 2015 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (14 ) $ 1 $ (19 ) Iberdrola Renovables Energía, S.L. — (2 ) — (3 ) Iberdrola, S.A. — (10 ) — (12 ) Other 1 (1 ) — (3 ) Related party transactions for the six months ended June 30, 2016 and 2015, respectively, consisted of: Six Months Ended June 30, 2016 2015 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (19 ) $ 1 $ (31 ) Iberdrola Renovables Energía, S.L. — (5 ) — (5 ) Iberdrola, S.A. — (18 ) — (18 ) Other 2 (1 ) — (4 ) In addition to the statements of income items above, we made purchases of turbines for wind farms from Gamesa Corporación Tecnológica, S.A. (Gamesa), in which our ultimate parent Iberdrola has a 20% ownership. The amounts capitalized for these transactions were $57 million and $70 million as of June 30, 2016 and December 31, 2015, respectively. In June 2016, Siemens AG and Gamesa signed binding agreement to merge wind power business. After completion of the merger, which is expected in the first quarter of 2017, Iberdrola will have 8.1% ownership of the new combined company. Related party balances as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 December 31, 2015 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ 4 $ (4 ) $ 7 $ (5 ) Gamesa Corporación Tecnológica, S.A. 61 (48 ) 68 (77 ) Iberdrola, S.A. — (17 ) — (3 ) Iberdrola Energy Projects, Inc. 1 — 1 (3 ) Iberdrola Renovables Energía, S.L. — (5 ) — — Other 4 (1 ) — (2 ) Transactions with our parent company, Iberdrola, relate predominantly to allocation of corporate services and management fees. Also included within the Purchases From category are charges for credit support relating to guarantees Iberdrola has provided to third parties guaranteeing our performance. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID any costs remaining after direct charge are allocated using agreed upon cost allocation methods designed to allocate those costs. We believe that the allocation method used is reasonable. Transactions with Iberdrola Canada Energy Services predominantly relate to the purchase of gas for ARHI’s gas-fired generation facility at Klamath. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances, other than a $7 million write-off related to an arrangement to purchase turbines from Gamesa during the three months ended June 30, 2015, which was recorded in impairment of non-current assets in the statements of income. The collectability of amounts receivable from Gamesa are contingent upon other related parties fulfilling certain payments to Gamesa. 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. In the second quarter of 2016, Networks has increased its equity method investment in the New York TransCo by approximately $21 million (included in “Other investments and equity method investments, net” of investing activities in the condensed consolidated statements of cash flows) for a total equity method investment of $22 million. Additionally, in the second quarter of 2016, Networks has received approximately $67 million from the New York TransCo in the form of $43 million for assets constructed and transferred to the New York TransCo (included in “Proceeds from asset sale” of investing activities in the condensed consolidated statements of cash flows), $22 million in contributions in aid of construction and approximately $2 million in advanced lease payments for a 99 year lease of land and attachment rights. AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a notional cash pooling agreement with Bank Mendes Gans, N.V., similar to other Iberdrola subsidiaries. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited in the cash pooling account where such funds are available to meet the liquidity needs of other affiliates within the Iberdrola Group. Under the cash pooling agreement, affiliates with credit balances have pledged those balances to cover the debit balances of the other affiliated parties to the agreement.

Accounts Receivable

Accounts Receivable	6 Months Ended
	Jun. 30, 2016
Receivables [Abstract]
Accounts Receivable	Note 15. Accounts Receivable Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. The utility company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as current. We establish provisions for uncollectible accounts for DPA’s 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 $61 million and $62 million at June 30, 2016 and December 31, 2015, respectively. The allowance for doubtful accounts for DPAs at June 30, 2016 and December 31, 2015, were $34 million and $35 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for the three months ended June 30, 2016 and 2015 were $0 and $(5) million, respectively, and for the six months ended June 30, 2016 and 2015 approximated $(1) million and $(4) million, respectively.

Income Tax Expense

Income Tax Expense	6 Months Ended
	Jun. 30, 2016
Income Tax Disclosure [Abstract]
Income Tax Expense	Note 16. Income Tax Expense The effective tax rates for the three and six months ended June 30, 2016, were 62.9% and 46.8% due to impact of adjustment of $126 million to unfunded future income tax to reflect the change from a flow through to normalization method following the approval of the Proposal by the NYPSC, which has been recorded as an increase to income tax expense and an offsetting increase to revenue, and sale of the Iroquois equity investment. After elimination of the effect of the adjustment to unfunded future income tax and sale of the Iroquois equity investment, the effective tax rate for the three and six month period ended June 30, 2016 would be 31.7% and 31.9%, respectively, compared to 31.2% and 28.6% effective tax rates for the three and six months ended June 30, 2015, respectively. The rates in both periods are lower than the 35% statutory federal income tax rate predominately due to the recognition of production tax credits associated with wind production.

Subsequent Events

Subsequent Events	6 Months Ended
	Jun. 30, 2016
Subsequent Events [Abstract]
Subsequent Events	Note 17. Subsequent Events Quarterly Dividends On July 14, 2016, the Board of Directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable on October 3, 2016, to shareholders of record at the close of business on September 9, 2016. Performance Stock Unit Grant Agreement On July 14, 2016, the Board of Directors of AVANGRID approved the form of performance stock unit grant agreement, pursuant to which performance stock units (PSUs) will be granted under the Avangrid, Inc. Omnibus Incentive Plan for certain officers and employees of AVANGRID. Officers and employees of AVANGRID may be granted up to 2.5 million PSUs in the aggregate, which will vest upon achievement of certain performance and market metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020, 2021 and 2022.

Acquisition of UIL (Tables)

Acquisition of UIL (Tables)	6 Months Ended
	Jun. 30, 2016
Business Combinations [Abstract]
Summary of Fair Value of Purchase Consideration	The fair value of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business combination, which was computed as follows: (millions, except share and unit data) Common shares (1) 56,629,377 Price per share of UIL common stock as of the acquisition date $ 50.10 Subtotal value of common shares $ 2,837 Restricted stock units (2) 476,198 Other shares (3) 12,999 Equity exchange factor 1.2806 Total restricted and other shares (3) an equity exchange factor 626,473 Price per share used (5) $ 39.60 Subtotal value of restricted and other shares $ 25 Total shares of AVANGRID common stock issued to UIL shareowners (including held in trust as Treasury Stock) 57,255,850 Performance shares (4) 211,904 Equity exchange factor 1.2806 Total performance shares after applying an equity exchange factor 271,368 Price per share used (5) $ 39.60 Subtotal value of performance shares $ 11 Total consideration $ 2,873 (1) Based on UIL’s common shares outstanding on December 16, 2015 (2) Based on UIL’s shares of vested restricted stock. (3) Based on UIL’s restricted shares vested upon the change in control. (4) Based on UIL’s vested performance shares award. (5) Based on the closing share price of UIL common stock on December 16, 2015 less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.
Summary of Components of Estimated Consideration Transferred	The following is a summary of the components of the consideration transferred to UIL’s shareowners: (millions, except share data) Cash ($10.50 x number of UIL common shares outstanding at the acquisition date - 56,629,377) $ 595 Equity 2,278 Total consideration $ 2,873
Schedule of Unaudited Pro Forma Results	Accordingly, these unaudited pro forma results are presented for informational purpose only and are not necessarily indicative of what the actual results of operations of the combined company would have been if the acquisition had occurred at the beginning of the periods presented, nor are they indicative of future results of operations: Three Months Ended Six Months Ended June 30, 2015 (millions) Revenue $ 1,251 $ 3,062 Net income $ 31 $ 203
Summary of Preliminary Allocation of Purchase Price	The following is a summary of the preliminary allocation of the purchase price as of the acquisition date: (millions) Current assets, including cash of $48 million $ 500 Other investments 114 Property, plant and equipment, net 3,552 Regulatory assets 966 Other assets 52 Current liabilities (493 ) Regulatory liabilities (493 ) Non-current debt (1,878 ) Other liabilities (1,201 ) Total net assets acquired at fair value 1,119 Goodwill – consideration transferred in excess of fair value assigned 1,754 Total estimated consideration $ 2,873

Regulatory Assets and Liabili28

Regulatory Assets and Liabilities (Tables)	6 Months Ended
	Jun. 30, 2016
Regulated Operations [Abstract]
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Current Pension and other post-retirement benefits cost deferrals $ 22 $ 8 Pension and other post-retirement benefits 7 13 Storm costs 40 8 Temporary supplemental assessment surcharge 5 7 Reliability support services 18 — Revenue decoupling mechanism 17 6 Hedges losses 4 37 Contracts for differences 18 18 Hardship programs 16 13 Deferred property tax 10 — Plant decommissioning 7 — Deferred purchased gas 1 12 Deferred transmission expense 23 12 Environmental remediation costs 17 37 Other 67 48 Total Current Regulatory Assets 272 219 Non-current Pension and other post-retirement benefits cost deferrals 147 151 Pension and other post-retirement benefits 1,449 1,509 Storm costs 207 251 Deferred meter replacement costs 33 34 Unamortized losses on reacquired debt 21 23 Environmental remediation costs 273 271 Unfunded future income taxes 494 549 Asset retirement obligation 19 24 Deferred property tax 40 45 Federal tax depreciation normalization adjustment 163 158 Merger capital expense target customer credit 12 15 Debt premium 129 141 Contracts for differences 71 50 Hardship programs 21 29 Other 62 64 Total Non-current Regulatory Assets $ 3,141 $ 3,314
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Current Reliability support services (Cayuga) $ 10 $ 16 Non by-passable charges 6 7 Energy efficiency portfolio standard 40 33 Gas supply charge and deferred natural gas cost 12 6 Transmission revenue reconciliation mechanism 13 16 Pension and other post-retirement benefits 17 3 Carrying costs on deferred income tax bonus depreciation 15 — Yankee DOE Refund — 5 Merger related rate credits — 20 Revenue decoupling mechanism 22 14 Other 48 27 Total Current Regulatory Liabilities 183 147 Non-current Accrued removal obligations 1,107 1,084 Asset sale gain account 9 8 Carrying costs on deferred income tax bonus depreciation 101 116 Economic development 36 36 Merger capital expense target customer credit account 15 17 Pension and other post-retirement benefits 78 90 Positive benefit adjustment 43 51 New York state tax rate change 10 17 Post term amortization 3 25 Theoretical reserve flow thru impact 27 31 Deferred property tax 18 15 Net plant reconciliation 10 10 Variable rate debt 30 32 Carrying costs on deferred income tax - Mixed Services 263(a) 28 31 Rate refund – FERC ROE proceeding 21 21 Merger-related rate credits 24 24 Accumulated deferred investment tax credits 12 10 Asset retirement obligation 13 13 Middletown/Norwalk local transmission network service collections 19 19 Excess generation service charge — 21 Low income programs 45 42 Unfunded future income taxes — 27 Non-firm margin sharing credits 11 8 Deferred income taxes regulatory 521 519 Other 63 93 Total Non-current Regulatory Liabilities $ 2,244 $ 2,360

Fair Value of Financial Instr29

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	6 Months Ended
	Jun. 30, 2016
Fair Value Disclosures [Abstract]
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 41 $ — $ — $ — $ 41 Derivative assets Derivative financial instruments - power 19 48 52 (54 ) 65 Derivative financial instruments - gas 138 26 99 (191 ) 72 Contracts for differences — — 24 — 24 Total 157 74 175 (245 ) 161 Derivative liabilities Derivative financial instruments - power (26 ) (22 ) (5 ) 42 (11 ) Derivative financial instruments - gas (172 ) (35 ) (55 ) 201 (61 ) Contracts for differences — — (112 ) — (112 ) Derivative financial instruments - other — — (1 ) — (1 ) Total $ (198 ) $ (57 ) $ (173 ) $ 243 $ (185 ) As of December 31, 2015 Level 1 Level 2 Level 3 Netting Total (Millions) Securities portfolio (available for sale) $ 39 $ — $ — $ — $ 39 Derivative assets Derivative financial instruments - power 10 81 48 (71 ) 68 Derivative financial instruments - gas 267 25 68 (280 ) 80 Contracts for differences — — 29 — 29 Total 277 106 145 (351 ) 177 Derivative liabilities Derivative financial instruments - power (43 ) (12 ) (14 ) 55 (14 ) Derivative financial instruments - gas (193 ) (40 ) (51 ) 212 (72 ) Contracts for differences — — (96 ) — (96 ) Derivative financial instruments - other — — (3 ) — (3 ) Total $ (236 ) $ (52 ) $ (164 ) $ 267 $ (185 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and six months ended June 30, 2016 and 2015, respectively, is as follows: Three Months Ended Six Months Ended June 30, June 30, (Millions) 2016 2015 2016 2015 Fair Value Beginning of Period, $ (45 ) $ 54 $ (19 ) $ 57 Gains recognized in operating revenues 40 31 44 42 (Losses) recognized in operating revenues — (4 ) (1 ) (5 ) Total gains (losses) recognized in operating revenues 40 27 43 37 Gains recognized in OCI — 2 1 3 (Losses) recognized in OCI — — — (1 ) Total Gains (Losses) Recognized in OCI — 2 1 2 Net change recognized in regulatory assets and liabilities 3 — (22 ) — Purchases (1 ) 22 (1 ) 21 Settlements (2 ) (4 ) (7 ) (7 ) Transfers out of Level 3(a) 7 2 7 (7 ) Fair Value as of June 30, $ 2 $ 103 $ 2 $ 103 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 $ 40 $ 27 $ 43 $ 37 (a) Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows: Range at Unobservable Input June 30, 2016 Risk of non-performance 0.05% - 0.77% Discount rate 0.71% - 1.49% Forward pricing ($ per MW) $3.15 - $9.55
Fair Value, Assets and Liabilities Level 3 Measurement , Valuation Techniques	They represent the variability in prices for those transactions that fall into the illiquid period (beyond 2 years), using past and current views of prices for those future periods As of June 30, 2016 Variability Instruments Instrument Description Valuation Technique Valuation Inputs Index Avg. Max. Min. Fixed price power and gas swaps Transactions delivery Transactions valued forward market Observable extrapolated forward power not can NYMEX $ 4.24 $ 7.37 $ 1.64 with delivery exceeding two on a corroborated by SP15 $ 44.09 $ 80.28 $ 14.25 period > two years discounted market data for Mid C $ 35.32 $ 83.93 $ 3.60 years basis identical or Cinergy $ 36.29 $ 77.49 $ 18.53 similar

Derivative Instruments and He30

Derivative Instruments and Hedging (Tables)	6 Months Ended
	Jun. 30, 2016
Derivative Instruments And Hedging Activities Disclosure [Abstract]
Summary of Unrealized Gains and Losses from Fair Value Adjustments	The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three and six months ended June 30, 2016, respectively, were as follows: Three Months Ended Six Months Ended June 30, 2016 (Millions) Regulatory Assets - Derivative liabilities $ (2 ) $ (5 ) Regulatory Liabilities - Derivative assets $ 6 $ (16 )
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Wholesale electricity purchase contracts (MWh) 6.8 6.7 Natural gas purchase contracts (Dth) 5.1 4.8 Fleet fuel purchase contracts (Gallons) 3.0 3.8 The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (MWh/Dth in millions) Wholesale electricity purchase contracts 3 3 Wholesale electricity sales contracts 6 6 Foreign exchange forward purchase contracts — 4 Natural gas and other fuel purchase contracts 331 332 Financial power contracts 6 7 Basis swaps – purchases 68 67 Basis swaps – sales 69 80
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location and Amount	The offsetting of derivatives, location and amounts of derivatives designated as hedging instruments associated with Networks activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 10 $ 14 $ — $ — Derivative liabilities — — (28 ) (84 ) 10 14 (28 ) (84 ) Designated as hedging instruments Derivative assets 16 5 14 5 Derivative liabilities (13 ) (5 ) (20 ) (8 ) 3 — (6 ) (3 ) Total derivatives before offset of cash collateral 13 14 (34 ) (87 ) Cash collateral receivable (payable) — — 4 3 Total derivatives as presented in the balance sheet $ 13 $ 14 $ (30 ) $ (84 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 11 $ 18 $ (28 ) $ (68 ) Derivative liabilities — — — — 11 18 (28 ) (68 ) Designated as hedging instruments Derivative assets 3 6 3 6 Derivative liabilities (3 ) (6 ) (42 ) (7 ) — — (39 ) (1 ) Total derivatives before offset of cash collateral 11 18 (67 ) (69 ) Cash collateral receivable (payable) — — 37 — Total derivatives as presented in the balance sheet $ 11 $ 18 $ (30 ) $ (69 ) The offsetting of derivatives, location and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 112 $ 103 $ 124 $ 4 Derivative liabilities (29 ) (10 ) (186 ) (17 ) 83 93 (62 ) (13 ) Designated as hedging instruments Derivative assets 8 8 — — Derivative liabilities — — (34 ) (10 ) 8 8 (34 ) (10 ) Total derivatives before offset of cash collateral 91 101 (96 ) (23 ) Cash collateral receivable (payable) (16 ) (42 ) 39 9 Total derivatives as presented in the balance sheet $ 75 $ 59 $ (57 ) $ (14 ) As of December 31, 2015 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities (Millions) Not designated as hedging instruments Derivative assets $ 186 $ 113 $ 117 $ 4 Derivative liabilities (85 ) (14 ) (169 ) (29 ) 101 99 (52 ) (25 ) Designated as hedging instruments Derivative assets 56 13 — — Derivative liabilities — — (9 ) — 56 13 (9 ) — Total derivatives before offset of cash collateral 157 112 (61 ) (25 ) Cash collateral receivable (payable) (80 ) (41 ) — — Total derivatives as presented in the balance sheet $ 77 $ 71 $ (61 ) $ (25 )
Schedule of Derivative Instruments, Effect of Cash flow Hedging on Other Comprehensive Income and Income	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended June 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) 2016 Interest rate contracts $ — Interest expense $ (2 ) Commodity contracts — Operating expenses — Total $ — $ (2 ) 2015 Interest rate contracts $ — Interest expense $ (2 ) Commodity contracts — Operating expenses (1 ) Total $ — $ (3 ) Six Months Ended June 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) 2016 Interest rate contracts $ — Interest expense $ (4 ) Commodity contracts — Operating expenses (1 ) Total $ — $ (5 ) 2015 Interest rate contracts $ — Interest expense $ (4 ) Commodity contracts (1 ) Operating expenses (2 ) Total $ (1 ) $ (6 ) (a) The effect of derivatives in cash flow hedging relationships on OCI and income for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended June 30, (Loss) Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Gain Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2016 Commodity contracts $ (38 ) Revenues $ (2 ) Total $ (38 ) $ (2 ) 2015 Commodity contracts $ — Revenues $ — Total $ — $ — Six Months Ended June 30, (Loss) Recognized in OCI on Derivatives Location of Gain Reclassified from Accumulated OCI into Income Gain Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2016 Commodity contracts $ (35 ) Revenues $ (48 ) Total $ (35 ) $ (48 ) 2015 Commodity contracts $ 1 Revenues $ — Total $ 1 $ — (a) Changes in OCI are reported on a pre-tax basis.
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of: June 30, December 31, As of 2016 2015 (Millions) Wholesale electricity purchase contracts $ (1 ) $ (13 ) Wholesale electricity sales contracts 11 35 Foreign exchange forward purchase contracts — (1 ) Natural gas and other fuel purchase contracts 18 10 Financial power contracts 44 32 Basis swaps – purchases (5 ) 1 Basis swaps – sales (4 ) (2 ) Total $ 63 $ 62
Effect of Trading and Non-trading Derivatives Associated with Renewables and Gas Activities	The effect of trading and non-trading derivatives, respectively, associated with Renewables and Gas activities for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Wholesale electricity purchase contracts $ 5 $ 3 $ 5 $ 10 Wholesale electricity sales contracts (6 ) (13 ) (7 ) (18 ) Financial power contracts 1 11 2 10 Financial and natural gas contracts (1 ) 7 (31 ) (48 ) Total (Loss) Gain $ (1 ) $ 8 $ (31 ) $ (46 ) Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Wholesale electricity purchase contracts $ 11 $ 6 $ 8 $ 5 Wholesale electricity sales contracts (20 ) (19 ) (14 ) (22 ) Financial power contracts (17 ) (1 ) (16 ) 4 Financial and natural gas contracts 35 6 26 12 Total Gain (Loss) $ 9 $ (8 ) $ 4 $ (1 )

Post-retirement and Similar O31

Post-retirement and Similar Obligations (Tables)	6 Months Ended
	Jun. 30, 2016
Compensation And Retirement Disclosure [Abstract]
Components of Net Periodic Pension and Postretirement Benefits	The components of net periodic benefit cost for pension benefits for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Service cost $ 11 $ 9 $ 22 $ 18 Interest cost 35 24 70 48 Expected return on plan assets (51 ) (39 ) (102 ) (78 ) Amortization of: Prior service costs 1 1 1 2 Actuarial loss 37 32 75 64 Net Periodic Benefit Cost $ 33 $ 27 $ 66 $ 54 The components of net periodic benefit cost for postretirement benefits for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Service cost $ 1 $ 1 $ 2 $ 2 Interest cost 6 4 12 8 Expected return on plan assets (3 ) (2 ) (6 ) (4 ) Amortization of: Prior service costs (2 ) (2 ) (4 ) (4 ) Actuarial loss 2 2 4 4 Net Periodic Benefit Cost $ 4 $ 3 $ 8 $ 6

Equity (Tables)

Equity (Tables)	6 Months Ended
	Jun. 30, 2016
Equity [Abstract]
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Accumulated OCI for the three months ended June 30, 2016 and 2015, respectively, consisted of: As of March 31 Three Months Ended June 30, As of June 30, As of March 31 Three Months Ended June 30, As of June 30, Accumulated Other Comprehensive Income (Loss) 2015 2015 2015 2016 2016 2016 (Millions) Loss on revaluation of defined benefit plans, net of income tax expense (benefit) of $(0.1) for 2015 and $0.1 for 2016 $ (26 ) $ (1 ) $ (27 ) $ (17 ) $ — $ (17 ) Loss for nonqualified pension plans (11 ) — (11 ) (8 ) — (8 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $0.4 for 2015 and $(14.2) for 2016 (2 ) 1 (1 ) 33 (23 ) 10 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense of $1.2 for 2015 and $0.7 for 2016(a) (59 ) 2 (57 ) (80 ) 1 (79 ) Gain (loss) on derivatives qualifying as cash flow hedges (61 ) 3 (58 ) (47 ) (22 ) (69 ) Accumulated Other Comprehensive (Loss) Income $ (98 ) $ 2 $ (96 ) $ (72 ) $ (22 ) $ (94 ) Accumulated OCI for the six months ended June 30, 2016 and 2015, respectively, consisted of: As of December 31, Six Months Ended June 30, As of June 30, As of December 31, Six Months Ended June 30, As of June 30, Accumulated Other Comprehensive Income (Loss) 2014 2015 2015 2015 2016 2016 (Millions) Gain (loss) on revaluation of defined benefit plans, net of income tax expense (benefit) of $(1.0) for 2015 and $2.9 for 2016 $ (25 ) $ (2 ) $ (27 ) $ (21 ) $ 4 $ (17 ) Loss for nonqualified pension plans (11 ) — (11 ) (8 ) — (8 ) Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $0.4 for 2015 and $(13.0) for 2016 (2 ) 1 (1 ) 31 (21 ) 10 Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $2.2 for 2015 and $(15.9) for 2016(a) (61 ) 4 (57 ) (54 ) (25 ) (79 ) Gain (loss) on derivatives qualifying as cash flow hedges (63 ) 5 (58 ) (23 ) (46 ) (69 ) Accumulated Other Comprehensive (Loss) Income $ (99 ) $ 3 $ (96 ) $ (52 ) $ (42 ) $ (94 ) (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)	6 Months Ended
	Jun. 30, 2016
Earnings Per Share [Abstract]
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to AVANGRID, including a reconciliation of the numerators and denominators for the three and six months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions, except for number of shares and per share data) Numerator: Net income attributable to AVANGRID $ 102 $ 11 $ 314 $ 117 Denominator: Weighted average number of shares outstanding - basic 309,527,868 252,235,232 309,533,042 252,235,232 Weighted average number of shares outstanding - diluted 309,683,965 252,235,232 309,689,138 252,235,232 Earnings per share attributable to AVANGRID Earnings Per Common Share, Basic $ 0.33 $ 0.04 $ 1.01 $ 0.46 Earnings Per Common Share, Diluted $ 0.33 $ 0.04 $ 1.01 $ 0.46

Segment Information (Tables)

Segment Information (Tables)	6 Months Ended
	Jun. 30, 2016
Segment Reporting [Abstract]
Schedule of Segment Information	Segment information for the three months ended June 30, 2016, consisted of: Three Months Ended June 30, 2016 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,211 $ 242 $ (14 ) $ — $ 1,439 Revenue - intersegment 2 2 3 (7 ) — Depreciation and amortization 126 81 6 — 213 Operating income (loss) 299 58 (28 ) (7 ) 322 Adjusted EBITDA 425 139 (22 ) (7 ) 535 Earnings (losses) from equity method investments $ 3 $ (3 ) $ — $ — $ — (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Segment information for the three months ended June 30, 2015, consisted of: Three Months Ended June 30, 2015 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 715 $ 243 $ (19 ) $ — $ 939 Revenue – intersegment — 8 9 (17 ) — Impairment of non-current assets — 7 — — 7 Depreciation and amortization 94 89 4 — 187 Operating income (loss) 100 8 (26 ) (9 ) 73 Adjusted EBITDA 194 104 (22 ) (9 ) 267 Earnings (losses) from equity method investments $ — $ (3 ) $ — $ 2 $ (1 ) (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Segment information as of and for the six months ended June 30, 2016, consisted of: Six Months Ended June 30, 2016 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 2,601 $ 518 $ (11 ) $ 1 $ 3,109 Revenue - intersegment 2 4 12 (18 ) — Depreciation and amortization 244 161 13 — 418 Operating income (loss) 611 107 (38 ) (9 ) 671 Adjusted EBITDA 855 268 (25 ) (9 ) 1,089 Earnings (losses) from equity method investments 6 (4 ) — — 2 Capital expenditures $ 470 $ 203 $ 1 $ — $ 674 As of June 30, 2016 Property, plant and equipment 12,525 7,800 505 — 20,830 Equity method investments 131 240 — — 371 Total assets $ 19,871 $ 10,437 $ 1,034 $ (931 ) $ 30,411 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Segment information for the six months ended June 30, 2015, consisted of: Six Months Ended June 30, 2015 Networks Renewables Gas Other (a) AVANGRID Consolidated (Millions) Revenue - external $ 1,713 $ 482 $ (29 ) $ — $ 2,166 Revenue – intersegment — 9 18 (27 ) — Impairment of non-current assets — 7 — — 7 Depreciation and amortization 180 172 9 1 362 Operating income (loss) 289 34 (41 ) (13 ) 269 Adjusted EBITDA 469 213 (32 ) (12 ) 638 Earnings (losses) from equity method investments — (2 ) — 2 — Capital expenditures $ 355 $ 172 $ 3 $ — $ 530 As of December 31, 2015 Property, plant and equipment 12,363 7,835 513 — 20,711 Equity method investments 110 253 — 22 385 Total assets $ 20,126 $ 10,685 $ 1,265 $ (1,333 ) $ 30,743 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations.
Schedule of Reconciliation of Consolidated EBITDA to Consolidated Income Before Income Tax	Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three and six months ended June 30, 2016 and 2015, respectively, is as follows: Three Months Ended Six Months Ended June 30, June 30, 2016 2015 2016 2015 (Millions) Consolidated Adjusted EBITDA $ 535 $ 267 $ 1,089 $ 638 Less: Impairment of non-current assets — 7 — 7 Depreciation and amortization 213 187 418 362 Interest expense, net of capitalization 68 66 152 127 Income tax expense 172 5 276 47 Add: Other income and (expense) 20 10 69 22 Earnings (losses) from equity method investments — (1 ) 2 — Consolidated Net Income $ 102 $ 11 $ 314 $ 117

Related Party Transactions (Tab

Related Party Transactions (Tables)	6 Months Ended
	Jun. 30, 2016
Related Party Transactions [Abstract]
Schedule of Related Party Transactions	Related party transactions for the three months ended June 30, 2016 and 2015, respectively, consisted of: Three Months Ended June 30, 2016 2015 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (14 ) $ 1 $ (19 ) Iberdrola Renovables Energía, S.L. — (2 ) — (3 ) Iberdrola, S.A. — (10 ) — (12 ) Other 1 (1 ) — (3 ) Related party transactions for the six months ended June 30, 2016 and 2015, respectively, consisted of: Six Months Ended June 30, 2016 2015 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ (19 ) $ 1 $ (31 ) Iberdrola Renovables Energía, S.L. — (5 ) — (5 ) Iberdrola, S.A. — (18 ) — (18 ) Other 2 (1 ) — (4 )
Schedule of Related Party Balances	Related party balances as of June 30, 2016 and December 31, 2015, respectively, consisted of: As of June 30, 2016 December 31, 2015 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ 4 $ (4 ) $ 7 $ (5 ) Gamesa Corporación Tecnológica, S.A. 61 (48 ) 68 (77 ) Iberdrola, S.A. — (17 ) — (3 ) Iberdrola Energy Projects, Inc. 1 — 1 (3 ) Iberdrola Renovables Energía, S.L. — (5 ) — — Other 4 (1 ) — (2 )

Background and Nature Of Oper36

Background and Nature Of Operations - Additional Information (Detail) $ in Millions	6 Months Ended
	Jun. 30, 2016USD ($)
Nature Of Business [Line Items]
Owned Subsidiaries	81.50%
Iroquois [Member]
Nature Of Business [Line Items]
Proceeds from sale of ownership Interest	$ 53.8
Net income on disposition of business	$ 19
NEW YORK
Nature Of Business [Line Items]
Incorporation date of organization	Jan. 1, 1997

Basis of Presentation - Additio

Basis of Presentation - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended	6 Months Ended	12 Months Ended
	Jun. 30, 2016	Jun. 30, 2016	Dec. 31, 2016	Dec. 31, 2015	Dec. 31, 2014
Service Life [Member]
Change In Accounting Estimate [Line Items]
Decrease in depreciation and amortization expense	$ 8	$ 25
Decrease in asset retirement obligation accretion expense	0	1
Increase in earnings from equity method investments	1	2
Estimated increase in net income	$ 6	$ 18
Increase in earnings per share, basic	$ 0.02	$ 0.06
Increase in earnings per share, diluted	$ 0.02	$ 0.06
Scenario, Forecast [Member] | Service Life [Member]
Change In Accounting Estimate [Line Items]
Estimated increase in net income			$ 35
Increase in earnings per share, basic			$ 0.11
Increase in earnings per share, diluted			$ 0.11
Estimated increase in income before income tax			$ 57
Wind Power Stations [Member]
Change In Accounting Estimate [Line Items]
Depreciation rate				4.00%	4.00%
Estimated useful life		40 years
Wind Power Stations [Member] | Scenario, Previously Reported
Change In Accounting Estimate [Line Items]
Estimated useful life				25 years
Wind Power Stations [Member] | Wind Farm Assets [Member]
Change In Accounting Estimate [Line Items]
Estimated useful life		30 years

Acquisition of UIL - Additional

Acquisition of UIL - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Dec. 16, 2015	Jun. 30, 2016	Dec. 31, 2015
Business Acquisition [Line Items]
Common stock, par value		$ 0.01	$ 0.01
Payments to acquire business, cash paid	$ 595
Fair value of contingent liability		$ 44
UIL Holdings [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	57,255,850
Payments to acquire business, cash paid	$ 595
Business combination, date of acquisition		Dec. 16, 2015
Number of Consecutive Trading Period	10 days
Business acquisition, share price	$ 50.10	$ 10.50
UIL Holdings [Member] | AVANGRID [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	309,490,839
Common stock, par value	$ 0.01
Percentage of ownership	18.50%
UIL Holdings [Member] | AVANGRID [Member] | Iberdrola, S.A. [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	252,234,989
UIL Holdings [Member] | AVANGRID [Member] | UIL shareowners [Member]
Business Acquisition [Line Items]
Shares issued in connection with acquisition	57,255,850

Acquisition of UIL - Summary of

Acquisition of UIL - Summary of Fair Value of Purchase Consideration (Detail) - USD ($) $ / shares in Units, $ in Millions		Dec. 16, 2015	Jun. 30, 2016		Dec. 31, 2015	[1]	Dec. 15, 2015	Jun. 30, 2015	[1]	Dec. 31, 2014	[1]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Common shares			309,003,589	[1]	308,864,609		252,235,232	252,235,232		252,235,232
Total consideration		$ 2,873
UIL Holdings [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Common shares	[2]	56,629,377
Business acquisition, share price		$ 50.10	$ 10.50
Subtotal value of common shares		$ 2,837
Other shares	[3]	12,999
Shares issued in connection with acquisition		57,255,850
UIL Holdings [Member] | Restricted Stock Units [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Vesting shares	[4]	476,198
Equity exchange factor		1.2806%
UIL Holdings [Member] | Restricted Stock Units and Other [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Total shares after applying an equity exchange factor	[3]	626,473
Price per share used	[5]	$ 39.60
Subtotal value of shares		$ 25
UIL Holdings [Member] | Performance Shares [Member]
Business Acquisition Equity Interests Issued Or Issuable [Line Items]
Vesting shares	[6]	211,904
Equity exchange factor		1.2806%
Total shares after applying an equity exchange factor		271,368
Price per share used	[5]	$ 39.60
Subtotal value of shares		$ 11
Total consideration		$ 2,873
[1]	Par value of share amounts is $0.01
[2]	Based on UIL’s common shares outstanding on December 16, 2015
[3]	Based on UIL’s restricted shares vested upon the change in control.
[4]	Based on UIL’s shares of vested restricted stock.
[5]	Based on the closing share price of UIL common stock on December 16, 2015 less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.
[6]	Based on UIL’s vested performance shares award.

Acquisition of UIL - Summary 40

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

Acquisition of UIL - Summary 41

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

Acquisition of UIL - Summary 42

Acquisition of UIL - Summary of Components of Estimated Consideration Transferred (Parenthetical) (Detail) - $ / shares		Jun. 30, 2016	[1]	Dec. 31, 2015	[1]	Dec. 16, 2015	Dec. 15, 2015	Jun. 30, 2015	[1]	Dec. 31, 2014	[1]
Business Combination Consideration Transferred [Line Items]
Common shares outstanding		309,003,589		308,864,609			252,235,232	252,235,232		252,235,232
UIL Holdings [Member]
Business Combination Consideration Transferred [Line Items]
Cash paid per common share						$ 10.50
Common shares outstanding	[2]					56,629,377
[1]	Par value of share amounts is $0.01
[2]	Based on UIL’s common shares outstanding on December 16, 2015

Acquisition of UIL - Schedule o

Acquisition of UIL - Schedule of Unaudited Pro Forma Results (Detail) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2015	Jun. 30, 2015
Business Acquisition Pro Forma Information [Abstract]
Revenue	$ 1,251	$ 3,062
Net income	$ 31	$ 203

Acquisition of UIL - Schedule44

Acquisition of UIL - Schedule of Preliminary Allocation of Purchase Price (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015	Dec. 16, 2015
Business Acquisition [Line Items]
Goodwill – consideration transferred in excess of fair value assigned	$ 3,113	$ 3,115
UIL Holdings [Member]
Business Acquisition [Line Items]
Current assets, including cash of $48 million			$ 500
Other investments			114
Property, plant and equipment, net			3,552
Regulatory assets			966
Other assets			52
Current liabilities			(493)
Regulatory liabilities			(493)
Non-current debt			(1,878)
Other liabilities			(1,201)
Total net assets acquired at fair value			1,119
Goodwill – consideration transferred in excess of fair value assigned			1,754
Total estimated consideration			$ 2,873

Regulatory Assets and Liabili45

Regulatory Assets and Liabilities - Additional Information (Detail)	May 03, 2016	Nov. 06, 2015	Mar. 05, 2015	Jul. 31, 2016USD ($)	Jun. 30, 2016USD ($)	Jun. 30, 2016USD ($)Station
Regulatory Assets And Liabilities [Line Items]
Unrecorded Regulatory Assets					$ 2,751,000,000	$ 2,751,000,000
Unfunded future income tax expense					126,000,000	$ 126,000,000
Unfunded future Income tax expense collection period						50 years
Percentage of earnings in excess of allowed ROE	9.55%	9.55%	10.00%			9.20%
Number of nuclear generating stations | Station						2
UIL Holdings [Member]
Regulatory Assets And Liabilities [Line Items]
Business combination merger related rate credits					$ 0	$ 20,000,000
Minimum [Member]
Regulatory Assets And Liabilities [Line Items]
Percentage of earnings in excess of allowed ROE	14.55%
Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Percentage of return on equity						11.74%
NEW YORK
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
NEW YORK | Prior Tax Rate [Member]
Regulatory Assets And Liabilities [Line Items]
Statutory income tax rate, state						7.10%
NEW YORK | Revised Tax Rate [Member]
Regulatory Assets And Liabilities [Line Items]
Statutory income tax rate, state						6.50%
NEW YORK | Minimum [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period						27 years
NEW YORK | Maximum [Member]
Regulatory Assets And Liabilities [Line Items]
Deferred income tax recovery period						39 years
Deferred Property Tax [Member] | NEW YORK
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Asset Sale Gain Account [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Economic Development [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Merger Capital Expense [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Positive Benefit Adjustment [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Post Term Amortization [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
Electric and Gas Service Rate Plan Year One [Member]
Regulatory Assets And Liabilities [Line Items]
Increase in customer earning levels						50.00%
Percentage of return on equity						9.50%
Electric and Gas Service Rate Plan Year Two [Member]
Regulatory Assets And Liabilities [Line Items]
Increase in customer earning levels						75.00%
Percentage of return on equity						10.00%
Electric and Gas Service Rate Plan Year Three [Member]
Regulatory Assets And Liabilities [Line Items]
Increase in customer earning levels						90.00%
Percentage of return on equity						10.50%
NYSEG [Member]
Regulatory Assets And Liabilities [Line Items]
Annual amortization of regulatory items						$ 16,500,000
Regulatory items amortization period						3 years
Approved return on equity						9.00%
Equity ratio					48.00%	48.00%
Equity ratio					50.00%	50.00%
NYSEG [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years
NYSEG [Member] | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						10 years
RGE Electric [Member]
Regulatory Assets And Liabilities [Line Items]
Approved return on equity						9.00%
Equity ratio					48.00%	48.00%
Equity ratio					50.00%	50.00%
United Illuminating Company [Member]
Regulatory Assets And Liabilities [Line Items]
Contract for purchase of electric power, description						On July 1, 2016, the United Illuminating Company (UI) filed an application with the Connecticut Public Utilities Regulatory Authority (PURA) requesting approval of a three-year rate plan commencing January 1, 2017, and extending through December 31, 2019
Contract for purchase of electric power, expiration date				Dec. 31, 2019
Aggregate value of three year rate plan levelized recovery to nonlevelized revenue increase				$ 25,600,000
United Illuminating Company [Member] | Subsequent Event [Member]
Regulatory Assets And Liabilities [Line Items]
Percentage of earnings in excess of allowed ROE				50.00%
United Illuminating Company [Member] | Electric and Gas Service Rate Plan Year One [Member] | Subsequent Event [Member]
Regulatory Assets And Liabilities [Line Items]
Requested revenue increase amount				$ 65,600,000
Levelized revenue increase amount				$ 40,700,000
Proposed deadband under earnings sharing mechanism (ESM)				0.20%
United Illuminating Company [Member] | Electric and Gas Service Rate Plan Year Two [Member] | Subsequent Event [Member]
Regulatory Assets And Liabilities [Line Items]
Requested revenue increase amount				$ 21,100,000
Levelized revenue increase amount				$ 47,400,000
Proposed deadband under earnings sharing mechanism (ESM)				0.30%
United Illuminating Company [Member] | Electric and Gas Service Rate Plan Year Three [Member] | Subsequent Event [Member]
Regulatory Assets And Liabilities [Line Items]
Requested revenue increase amount				$ 13,400,000
Levelized revenue increase amount				$ 39,100,000
Proposed deadband under earnings sharing mechanism (ESM)				0.40%
United Illuminating Company [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Deferred costs					$ 1,000,000	$ 1,000,000
Regulatory assets					$ 0	0
Central Maine Power Company [Member]
Regulatory Assets And Liabilities [Line Items]
Recovery of deferred storm costs						$ 123,000,000
Central Maine Power Company [Member] | Storm Costs
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						10 years
Central Maine Power Company [Member] | Regulatory Items Other Than Storm Costs [ Member]
Regulatory Assets And Liabilities [Line Items]
Regulatory items amortization period						5 years

Regulatory Assets and Liabili46

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Regulatory Asset [Line Items]
Regulatory Assets, current	$ 272	$ 219
Regulatory Assets, noncurrent	3,141	3,314
Pension And Other Post-Retirement Benefits Deferrals [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	22	8
Regulatory Assets, noncurrent	147	151
Pension And Other Post-Retirement Benefits [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	7	13
Regulatory Assets, noncurrent	1,449	1,509
Storm Costs
Regulatory Asset [Line Items]
Regulatory Assets, current	40	8
Regulatory Assets, noncurrent	207	251
Temporary Supplemental Assessment Surcharge [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	5	7
Support Services
Regulatory Asset [Line Items]
Regulatory Assets, current	18
Hedges Loss [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	4	37
Revenue Decoupling Mechanism [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	17	6
Contracts For Differences [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	18	18
Regulatory Assets, noncurrent	71	50
Hardship Programs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	16	13
Regulatory Assets, noncurrent	21	29
Deferred Purchased Gas [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	1	12
Deferred Transmission Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	23	12
Deferred Property Tax [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	10
Regulatory Assets, noncurrent	40	45
Environmental Restoration Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	17	37
Regulatory Assets, noncurrent	273	271
Plant Decommissioning [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	7
Other [Member]
Regulatory Asset [Line Items]
Regulatory Assets, current	67	48
Regulatory Assets, noncurrent	62	64
Deferred Meter Replacement Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	33	34
Unamortized Loss On Reacquired Debt [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	21	23
Future Income Tax [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	494	549
Asset Retirement Obligation Costs [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	19	24
Federal Tax Depreciation Normalization Adjustment [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	163	158
Merger Capital Expense [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	12	15
Debt Premium [Member]
Regulatory Asset [Line Items]
Regulatory Assets, noncurrent	$ 129	$ 141

Regulatory Assets and Liabili47

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Regulatory Liabilities [Line Items]
Regulatory liabilities	$ 183	$ 147
Regulatory liabilities including deferred income taxes, noncurrent	1,723	1,841
Deferred income taxes regulatory	521	519
Regulatory liabilities including deferred income taxes, noncurrent	2,244	2,360
Support Services
Regulatory Liabilities [Line Items]
Regulatory liabilities	10	16
Non By Passable Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	6	7
Energy Efficiency Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	40	33
Gas Supply Charge And Deferred Natural Gas Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	12	6
Transmission Revenue Reconciliation Mechanism [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	13	16
Pension And Other Post-Retirement Benefits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	17	3
Regulatory liabilities including deferred income taxes, noncurrent	78	90
Yankee DOE Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities		5
Carrying Costs On Deferred Income Tax Bonus Depreciation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	15
Regulatory liabilities including deferred income taxes, noncurrent	101	116
Merger Related Rate Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities		20
Regulatory liabilities including deferred income taxes, noncurrent	24	24
Revenue Decoupling Mechanism [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	22	14
Other [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities	48	27
Regulatory liabilities including deferred income taxes, noncurrent	63	93
Accrued Removal Obligations [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	1,107	1,084
Asset Sale Gain Account [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	9	8
Economic Development [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	36	36
Merger Capital Expense [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	15	17
Positive Benefit Adjustment [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	43	51
New York State Tax Rate Change [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	10	17
Post Term Amortization [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	3	25
Theoretical Reserve Flow Thru Impact [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	27	31
Deferred Property Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	18	15
Net Plant Reconciliation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	10	10
Variable Rate Debt [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	30	32
Carrying Costs On Deferred Income Tax [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	28	31
Rate Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	21	21
Accumulated Deferred Investment Tax Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	12	10
Asset Retirement Obligation Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	13	13
Middletown/Norwalk Local Transmission Network Service Collections [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	19	19
Excess Generation Service Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent		21
Low Income Programs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	45	42
Unfunded Future Income Taxes [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent		27
Non-Firm Margin Sharing Credits [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities including deferred income taxes, noncurrent	$ 11	$ 8

Fair Value of Financial Instr48

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 161	$ 177
Derivative financial instruments, liabilities	(185)	(185)
Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(245)	(351)
Derivative financial instruments, liabilities	243	267
Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	41	39
Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	65	68
Derivative financial instruments, liabilities	(11)	(14)
Derivative Financial Instrument Power [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(54)	(71)
Derivative financial instruments, liabilities	42	55
Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	72	80
Derivative financial instruments, liabilities	(61)	(72)
Derivative Financial Instrument Gas [Member] | Netting [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(191)	(280)
Derivative financial instruments, liabilities	201	212
Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	24	29
Derivative financial instruments, liabilities	(112)	(96)
Derivative Financial Instrument Other [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	(1)	(3)
Fair Value, Inputs, Level 1 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	157	277
Derivative financial instruments, liabilities	(198)	(236)
Fair Value, Inputs, Level 1 [Member] | Available-for-sale Securities [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Financial instruments, assets	41	39
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	19	10
Derivative financial instruments, liabilities	(26)	(43)
Fair Value, Inputs, Level 1 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	138	267
Derivative financial instruments, liabilities	(172)	(193)
Fair Value, Inputs, Level 2 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	74	106
Derivative financial instruments, liabilities	(57)	(52)
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	48	81
Derivative financial instruments, liabilities	(22)	(12)
Fair Value, Inputs, Level 2 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	26	25
Derivative financial instruments, liabilities	(35)	(40)
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	175	145
Derivative financial instruments, liabilities	(173)	(164)
Level 3 [Member] | Derivative Financial Instrument Power [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	52	48
Derivative financial instruments, liabilities	(5)	(14)
Level 3 [Member] | Derivative Financial Instrument Gas [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	99	68
Derivative financial instruments, liabilities	(55)	(51)
Level 3 [Member] | Contracts For Differences [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	24	29
Derivative financial instruments, liabilities	(112)	(96)
Level 3 [Member] | Derivative Financial Instrument Other [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	$ (1)	$ (3)

Fair Value of Financial Instr49

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		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Debt Instrument Fair Value Carrying Value [Abstract]
Fair value as of January 1,		$ (45)	$ 54	$ (19)	$ 57
Gains recognized in operating revenues		40	31	44	42
(Losses) recognized in operating revenues			(4)	(1)	(5)
Total gains (losses) recognized in operating revenues		40	27	43	37
Gains recognized in OCI			2	1	3
(Losses) recognized in OCI					(1)
Total Gains (Losses) Recognized in OCI			2	1	2
Net change recognized in regulatory assets and liabilities		3		(22)
Purchases		(1)	22	(1)	21
Settlements		(2)	(4)	(7)	(7)
Transfers out of Level 3	[1]	7	2	7	(7)
Fair Value as of June 30,		2	103	2	103
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date		$ 40	$ 27	$ 43	$ 37
[1]	Transfers out of Level 3 were the result of increased observability of market data.

Fair Value of Financial Instr50

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	6 Months Ended
	Jun. 30, 2016$ / MMBTU$ / MWh
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Instruments	Fixed price power and gas swaps with delivery period > two years
Instrument Description	Transactions with delivery periods exceeding two years
Valuation Technique	Transactions are valued against forward market prices on a discounted basis
Valuation Inputs	Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products
CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	NYMEX ($/MMBtu)
CME SWAPS MARKETS (NYMEX) [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	4.24
CME SWAPS MARKETS (NYMEX) [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	7.37
CME SWAPS MARKETS (NYMEX) [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability | $ / MMBTU	1.64
SP15 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	SP15 ($/MWh)
SP15 [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	44.09
SP15 [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	80.28
SP15 [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	14.25
Mid C [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Mid C ($/MWh)
Mid C [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	35.32
Mid C [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	83.93
Mid C [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	3.60
Cinergy [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Index	Cinergy ($/MWh)
Cinergy [Member] | Weighted Average [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	36.29
Cinergy [Member] | Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	77.49
Cinergy [Member] | Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Variability	18.53

Fair Value of Financial Instr51

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Detail) - Contracts For Differences [Member] - Level 3 [Member]	6 Months Ended
	Jun. 30, 2016$ / MWh
Minimum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.05%
Discount rate	0.71%
Forward pricing ($ per MW)	3.15
Maximum [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Risk of non-performance	0.77%
Discount rate	1.49%
Forward pricing ($ per MW)	9.55

Fair Value of Financial Instr52

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of debt	$ 5,252	$ 4,985
Level 3 [Member]
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis [Line Items]
Fair value of debt	$ 204	$ 204

Derivative Instruments and He53

Derivative Instruments and Hedging - Additional Information (Detail) - USD ($)		3 Months Ended		6 Months Ended		12 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2017	Dec. 31, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets				$ 235,000,000	$ (95,000,000)
Derivative financial instruments, assets		$ 161,000,000		161,000,000				$ 177,000,000
Gross Amounts of Recognized Liabilities		185,000,000		185,000,000				185,000,000
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]	1,000,000	$ 2,000,000	(25,000,000)	4,000,000
UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative financial instruments, assets		24,000,000		24,000,000				29,000,000
Regulatory Assets		88,000,000		88,000,000				68,000,000
Gross Amounts of Recognized Liabilities		112,000,000		112,000,000				96,000,000
Regulatory liabilities		1,000,000		$ 1,000,000				1,000,000
Contracts For Differences [Member] | UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers				20.00%
Contracts For Differences [Member] | CL&P [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers				80.00%
Derivative financial instruments, assets		100,000		$ 100,000				1,000,000
Gross Amounts of Recognized Liabilities		83,000,000		83,000,000				61,000,000
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges	[2]				(1,000,000)
Network [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges		2,000,000	2,200,000	4,000,000	4,400,000
Ineffective portion of Cash flow hedge		0	0	0	0
Unrealized gain(loss) from hedging activities reported on OCI				$ 1,400,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months				12 months
Network [Member] | Cash Flow Hedging [Member] | Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes							$ 8,000,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months						$ 1,100,000
Network [Member] | Electricity Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets				$ 7,300,000				(34,300,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income		(13,100,000)	(9,400,000)	(47,900,000)	(12,000,000)
Network [Member] | Natural Gas Hedges [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets				2,800,000				(3,100,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income		0	(1,400,000)	(3,400,000)	(3,000,000)
Network [Member] | forward starting swaps [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps		80,800,000		$ 80,800,000				84,900,000
Network [Member] | Fuel Derivatives [Member] | Cash Flow Hedging [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges				18 months
Renewables and Gas Activities [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Ineffective portion of Cash flow hedge		(400,000)	$ 1,400,000	$ (4,800,000)	$ 1,400,000
Unrealized gain(loss) from hedging activities reported on OCI				$ 25,900,000
Derivative Instruments Gain Loss To Be Reclassified From Accumulated OCI Into Interest Expense During Next Twelve Months				12 months
Counter Party [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities		7,000,000		$ 7,000,000
Cash Collateral Pledged		1,000,000		1,000,000				$ 11,000,000
Counter Party [Member] | UI [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative collateral obligation to be paid in decrease in credit rating below investment grade		$ 10,200,000		$ 10,200,000
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income
[2]	Changes in OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income.

Derivative Instruments and He54

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Detail) - USD ($) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2016	Jun. 30, 2016
Regulatory Assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory Assets (Liabilities) - Derivative assets (liabilities)	$ (2)	$ (5)
Regulatory Liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory Assets (Liabilities) - Derivative assets (liabilities)	$ 6	$ (16)

Derivative Instruments and He55

Derivative Instruments and Hedging - Net Notional Volume (Detail)	Jun. 30, 2016MWhDTHgal	Dec. 31, 2015MWhDTHgal
Network [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	6,800,000	6,700,000
Network [Member] | Natural Gas Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	5,100,000	4,800,000
Network [Member] | Fleet Fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | gal	3,000,000	3,800,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	3,000,000	3,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount | MWh	6,000,000	6,000,000
Renewables and Gas Activities [Member] | Foreign Exchange Forward [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount		4,000,000
Renewables and Gas Activities [Member] | Natural Gas and Other fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	331,000,000	332,000,000
Renewables and Gas Activities [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	6,000,000	7,000,000
Renewables and Gas Activities [Member] | Basis Swap [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	68,000,000	67,000,000
Renewables and Gas Activities [Member] | Basis Swap [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative non-monetary notional amount	69,000,000	80,000,000

Derivative Instruments and He56

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations and Amounts of Derivatives Designated as Hedging (Detail) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Network [Member] | UIL Holdings [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	$ 13	$ 11
Total derivatives as presented in the balance sheet	13	11
Network [Member] | UIL Holdings [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	14	18
Total derivatives as presented in the balance sheet	14	18
Network [Member] | UIL Holdings [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(34)	(67)
Cash collateral receivable (payable)	4	37
Total derivatives as presented in the balance sheet	(30)	(30)
Network [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral	(87)	(69)
Cash collateral receivable (payable)	3
Total derivatives as presented in the balance sheet	(84)	(69)
Network [Member] | Not Designated as Hedging Instruments [Member] | UIL Holdings [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	10	11
Derivative Fair Value, Net	10	11
Network [Member] | Not Designated as Hedging Instruments [Member] | UIL Holdings [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets	14	18
Derivative Fair Value, Net	14	18
Network [Member] | Not Designated as Hedging Instruments [Member] | UIL Holdings [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets		(28)
Derivative liabilities	(28)
Derivative Fair Value, Net	(28)	(28)
Network [Member] | Not Designated as Hedging Instruments [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative assets		(68)
Derivative liabilities	(84)
Derivative Fair Value, Net	(84)	(68)
Network [Member] | Designated as Hedging Instrument [Member] | UIL Holdings [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(13)	(3)
Derivative Fair Value, Net	3
Derivative assets	16	3
Network [Member] | Designated as Hedging Instrument [Member] | UIL Holdings [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(5)	(6)
Derivative assets	5	6
Network [Member] | Designated as Hedging Instrument [Member] | UIL Holdings [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(20)	(42)
Derivative Fair Value, Net	(6)	(39)
Derivative assets	14	3
Network [Member] | Designated as Hedging Instrument [Member] | UIL Holdings [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(8)	(7)
Derivative Fair Value, Net	(3)	(1)
Derivative assets	5	6
Renewables and Gas Activities [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral		157
Cash collateral receivable (payable)	(16)	(80)
Total derivatives as presented in the balance sheet	75	77
Total derivatives before offset of cash collateral	91
Renewables and Gas Activities [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral		112
Cash collateral receivable (payable)	(42)	(41)
Total derivatives as presented in the balance sheet	59	71
Total derivatives before offset of cash collateral	101
Renewables and Gas Activities [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral		(61)
Cash collateral receivable (payable)	39
Total derivatives as presented in the balance sheet	(57)	(61)
Total derivatives before offset of cash collateral	(96)
Renewables and Gas Activities [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral		(25)
Cash collateral receivable (payable)	9
Total derivatives as presented in the balance sheet	(14)	(25)
Total derivatives before offset of cash collateral	(23)
Renewables and Gas Activities [Member] | Not Designated as Hedging Instruments [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(29)	(85)
Derivative Fair Value, Net	83	101
Derivative assets	112	186
Renewables and Gas Activities [Member] | Not Designated as Hedging Instruments [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(10)	(14)
Derivative Fair Value, Net	93	99
Derivative assets	103	113
Renewables and Gas Activities [Member] | Not Designated as Hedging Instruments [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(186)	(169)
Derivative Fair Value, Net	(62)	(52)
Derivative assets	124	117
Renewables and Gas Activities [Member] | Not Designated as Hedging Instruments [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(17)	(29)
Derivative Fair Value, Net	(13)	(25)
Derivative assets	4	4
Renewables and Gas Activities [Member] | Designated as Hedging Instrument [Member] | Current Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	8	56
Derivative assets	8	56
Renewables and Gas Activities [Member] | Designated as Hedging Instrument [Member] | Noncurrent Assets [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	8	13
Derivative assets	8	13
Renewables and Gas Activities [Member] | Designated as Hedging Instrument [Member] | Current Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(34)	(9)
Derivative Fair Value, Net	(34)	$ (9)
Renewables and Gas Activities [Member] | Designated as Hedging Instrument [Member] | Noncurrent Liabilities [Member]
Derivative Instruments And Hedging Activities Disclosures [Line Items]
Derivative liabilities	(10)
Derivative Fair Value, Net	$ (10)

Derivative Instruments and He57

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[1]	$ (38)		$ (35)	$ 1
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[2]				(1)
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[2]	(2)	$ (3)	(5)	(6)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Reclassified from Accumulated OCI Income Effective Portion	[1]	(2)		(48)
Interest Rate Contract [Member] | Network [Member] | Interest expense [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[2]	(2)	(2)	(4)	(4)
Commodity Contract [Member] | Network [Member] | Operating expenses [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion	[2]				(1)
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[2]		$ (1)	(1)	$ (2)
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Revenue [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Reclassified from Accumulated OCI Income Effective Portion	[1]	$ (2)		$ (48)
[1]	Changes in OCI are reported on a pre-tax basis.
[2]	Changes in OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income.

Derivative Instruments and He58

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 63	$ 62
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	44	32
Long [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(1)	(13)
Long [Member] | Foreign Exchange Forward [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net		(1)
Long [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	18	10
Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(5)	1
Short [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	11	35
Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ (4)	$ (2)

Derivative Instruments and He59

Derivative Instruments and Hedging - Effect of Trading and Non-Trading Derivatives (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	$ (1)	$ 8	$ (31)	$ (46)
Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	5	3	5	10
Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(6)	(13)	(7)	(18)
Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	1	11	2	10
Trading Derivatives [Member] | Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(1)	7	(31)	(48)
Non-Trading Derivatives [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	9	(8)	4	(1)
Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	11	6	8	5
Non-Trading Derivatives [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(20)	(19)	(14)	(22)
Non-Trading Derivatives [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(17)	(1)	(16)	4
Non-Trading Derivatives [Member] | Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	$ 35	$ 6	$ 26	$ 12

Contingencies - Additional Info

Contingencies - Additional Information (Detail) - USD ($) $ in Thousands

May 03, 2016

Apr. 29, 2016

Mar. 25, 2016

Mar. 22, 2016

Nov. 06, 2015

Mar. 05, 2015

Jul. 31, 2014

Dec. 26, 2012

Nov. 30, 2013

Dec. 31, 2012

Jun. 30, 2016

Dec. 31, 2012

May 31, 2016

Dec. 31, 2015

Loss Contingencies [Line Items]

Requested return on equity base percentage

9.55%

9.55%

10.00%

9.20%

Requested equity ratio

50.00%

50.00%

50.00%

One-time gross plant investment disallowance

$ 6,000

$ 19,950

Investment phase in amount

$ 10,000

Cash Reserve

$ 6,000

$ 6,000

New rate plan

10 years

Delivery revenue percentage

34.60%

One-time gross plant investment

$ 15,000

Disclosure of Rate Matters

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

Regulatory liabilities

$ 1,723,000

$ 1,841,000

Spent fuel litigation damages awarded, value

$ 76,800

$ 235,400

$ 160,000

Litigation appeal expiration date

Jul. 18, 2016

Adjustment regulatory deferral and earning sharing accruals

$ 9,800

Staff issue settlement reserve

3,400

3,400

Customer share of earnings sharing

2,400

Price of the power purchase agreements

$ 259,000

Standby letters of credit

2,500

Connecticut Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Court of Federal Claims award

39,700

39,700

Spent fuel litigation damages awarded, value

32,600

126,300

Maine Yankee Atomic Power Company [Member]

Loss Contingencies [Line Items]

Court of Federal Claims award

$ 81,700

81,700

Spent fuel litigation damages awarded, value

24,600

37,700

CMP Distribution [Member]

Loss Contingencies [Line Items]

Share of the award credited back to customers

28,200

36,500

UI [Member]

Loss Contingencies [Line Items]

Share of the award credited back to customers

12,000

3,800

Yankee Atomic Energy Corporation [Member]

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 19,600

73,300

Complaint One [Member]

Loss Contingencies [Line Items]

Regulatory liabilities

21,200

Complaint Two [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.70%

Regulatory liabilities

21,200

Complaint Three [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

8.84%

Regulatory liabilities

$ 4,200

Complaint Two and Three [Member]

Loss Contingencies [Line Items]

Disclosure of Rate Matters

On November 24, 2014, FERC accepted the third complaint, established a 15-month refund effective date of July 31, 2014, and set this matter, consolidated with Complaint II, for hearing in June 2015. Hearings were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge, relating to the refund periods and going forward period. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the New England transmission owners filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The FERC Administrative Law Judge issued an Initial Decision on March 22, 2016. The Initial Decision determined that, 1) for the 15-month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and 2) for the 15-month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The Initial Decision is the Administrative Law Judge’s recommendation to the FERC Commissioners. The FERC is expected to make its final decision in late 2016 or early 2017.

Reasonably possible loss, in additional reserve, net of tax

$ 10,200

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

Loss Contingencies [Line Items]

Approved return on equity

10.57%

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

Loss Contingencies [Line Items]

Approved return on equity

9.59%

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

Loss Contingencies [Line Items]

Approved return on equity

10.90%

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

Loss Contingencies [Line Items]

Approved return on equity

8.61%

Before Amendment [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.14%

Minimum [Member]

Loss Contingencies [Line Items]

Requested return on equity base percentage

14.55%

Spent fuel litigation damages awarded, value

$ 82,000

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

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

21,400

Maximum [Member]

Loss Contingencies [Line Items]

Approved return on equity

11.74%

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

Loss Contingencies [Line Items]

Spent fuel litigation damages awarded, value

$ 38,300

Maximum [Member] | Complaint Two [Member]

Loss Contingencies [Line Items]

Approved return on equity

10.42%

Maximum [Member] | Complaint Three [Member]

Loss Contingencies [Line Items]

Approved return on equity

12.19%

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

Loss Contingencies [Line Items]

Approved return on equity

11.24%

Environmental Liabilities - Add

Environmental Liabilities - Additional Information (Detail) $ in Millions	Sep. 11, 2014USD ($)	Aug. 14, 2013USD ($)	Sep. 09, 2011USD ($)	Nov. 30, 2014USD ($)	Jul. 31, 2011USD ($)	Jun. 30, 2016USD ($)siteLocation	Dec. 31, 2015USD ($)	Sep. 16, 2015USD ($)	Jan. 31, 2015USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						24
Number of sites where gas was manufactured in the past | site						53
Number of sites for which we have entered into consent orders to investigate and remediate | site						47
Costs related to investigation and remediation						$ 388	$ 397
Accrual for environmental loss contingencies	$ 27					$ 26
Damages for incurred costs payment amount	$ 22
Refund of environmental remediation cost paid				$ 5
Number of sites with modified decision | site						9
Future costs that have been recorded as a receivable									$ 16
First Energy [Member]
Environmental Exit Cost [Line Items]
Amount that would be required to be paid based on past and future cleanup costs					$ 60
Environmental costs paid			$ 30
First Energy [Member] | Past Costs [Member]
Environmental Exit Cost [Line Items]
Accrual for environmental loss contingencies			27
First Energy [Member] | Pre-judgment Interest [Member]
Environmental Exit Cost [Line Items]
Environmental costs paid			$ 3
Century Indemnity and OneBeacon [Member]
Environmental Exit Cost [Line Items]
Amount that would be required to be paid based on past and future cleanup costs		$ 89
Number of hazardous waste sites | Location						22
Legal discovery process expected closing year description						Century and One Beacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Estimated environmental liability						$ 9.5
Costs related to investigation and remediation						$ 20.5		$ 30
Maximum [Member] | Century Indemnity and OneBeacon [Member]
Environmental Exit Cost [Line Items]
Amount that would be required to be paid based on past and future cleanup costs		$ 282
New York State Registry [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						15
Number of sites where gas was manufactured in the past | site						8
Maine's Uncontrolled Sites Program [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						6
Number of sites where gas was manufactured in the past | site						2
Massachusetts Non- Priority Confirmed Disposal Site List [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						1
National Priorities List [Member]
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations | site						9
Nine of Twenty-three Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability						$ 6
Another Ten Sites [Member]
Environmental Exit Cost [Line Items]
Estimated environmental liability						$ 8
New York Voluntary Cleanup Program [Member]
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site						11
Maine’s Voluntary Response Action Program [Member]
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past | site						3
Manufactured Gas Plants
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 99	$ 99
Manufactured Gas Plants | Minimum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						235
Manufactured Gas Plants | Maximum [Member]
Environmental Exit Cost [Line Items]
Costs related to investigation and remediation						$ 468

Post-Retirement and Similar O62

Post-Retirement and Similar Obligations - Additional Information (Detail) $ in Millions	3 Months Ended	6 Months Ended
	Jun. 30, 2016USD ($)	Jun. 30, 2016USD ($)
Compensation And Retirement Disclosure [Abstract]
Defined benefit, pension contributions	$ 15	$ 15
Contributions for remainder of fiscal year	$ 28	$ 28

Post-Retirement and Similar O63

Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 11	$ 9	$ 22	$ 18
Interest cost	35	24	70	48
Expected return on plan assets	(51)	(39)	(102)	(78)
Amortization of prior service costs	1	1	1	2
Amortization of actuarial loss	37	32	75	64
Net Periodic Benefit Cost	33	27	66	54
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1	2	2
Interest cost	6	4	12	8
Expected return on plan assets	(3)	(2)	(6)	(4)
Amortization of prior service costs	(2)	(2)	(4)	(4)
Amortization of actuarial loss	2	2	4	4
Net Periodic Benefit Cost	$ 4	$ 3	$ 8	$ 6

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions		Dec. 15, 2015	Jun. 30, 2016		Dec. 31, 2015		Jun. 30, 2015	[1]	Dec. 31, 2014	[1]	Nov. 30, 2011
Class Of Stock [Line Items]
Common stock, authorized			500,000,000		500,000,000
Common stock, issued			309,592,620		309,491,082						243
Common stock, outstanding		252,235,232	309,003,589	[1]	308,864,609	[1]	252,235,232		252,235,232
Common stock, par value			$ 0.01		$ 0.01
Common stock			$ 3		$ 3
Additional paid-in capital			$ 13,651		$ 13,653
Treasury stock, shares			491,552		626,473
Convertible preferred stock, shares outstanding			0		0
Issuance of common stock, shares	[1]		101,538
Reissuance of common stock held in trust, shares	[1]		134,921
Repurchase of common stock, shares	[1]		97,479
Repurchase of common stock			$ 4
Common stock issued from stock split		252,234,989
Iberdrola Renewables Holding, Inc [Member]
Class Of Stock [Line Items]
Percentage of equity owned by parent			81.50%		81.50%
[1]	Par value of share amounts is $0.01

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		3 Months Ended				6 Months Ended		12 Months Ended
		Jun. 30, 2016	Mar. 31, 2016	Jun. 30, 2015	Mar. 31, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015	Dec. 31, 2014
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, net of income taxes				$ (1)		$ 4	$ (2)
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)		$ (23)		1		(21)	1
Reclassification to net income of (gains) losses on cash flow hedges, net of income taxes	[1]	1		2		(25)	4
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)		(69)	$ (47)	(58)	$ (61)	(69)	(58)	$ (23)	$ (63)
Other Comprehensive Income (Loss), Derivatives Qualifying as Hedges, Net of Tax		(22)		3		(46)	5
Other comprehensive (loss) income, net of tax		(22)		2		(42)	3
Accumulated other comprehensive (loss) Income		(94)	(72)	(96)	(98)	(94)	(96)	(52)	(99)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)	[1]	(79)	(80)	(57)	(59)	(79)	(57)	(54)	(61)
Designated as Hedging Instrument [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)		10	33	(1)	(2)	10	(1)	31	(2)
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans		(17)	(17)	(27)	(26)	(17)	(27)	(21)	(25)
Gain (loss) on defined benefit plans, net of income taxes				(1)		4	(2)
Non-Qualified Pension Plans [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans		$ (8)	$ (8)	$ (11)	$ (11)	$ (8)	$ (11)	$ (8)	$ (11)
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Equity - Accumulated Other Co66

Equity - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense (benefit)	$ 0.1	$ (0.1)	$ 2.9	$ (1)
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax expense (benefit)	(14.2)	0.4	(13)	0.4
Reclassification to net income of (gains) losses on cash flow hedges, income tax expense	0.7	1.2	(15.9)	2.2
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income Loss [Line Items]
Gain (loss) on defined benefit plans, income tax expense (benefit)	$ 0.1	$ (0.1)	$ 2.9	$ (1)

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		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Numerator:
Net income attributable to AVANGRID	$ 102	$ 11	$ 314	$ 117
Denominator:
Weighted average number of shares outstanding - basic	309,527,868	252,235,232	309,533,042	252,235,232
Weighted average number of shares outstanding - diluted	309,683,965	252,235,232	309,689,138	252,235,232
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$ 0.33	$ 0.04	$ 1.01	$ 0.46
Earnings Per Common Share, Diluted	$ 0.33	$ 0.04	$ 1.01	$ 0.46

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016USD ($)	Jun. 30, 2015USD ($)	Jun. 30, 2016USD ($)Segment	Jun. 30, 2015USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			3
Operating Revenues	$ 1,439	$ 939	$ 3,109	$ 2,166
Regulated Electric Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	949	608	1,862	1,336
Regulated Gas Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	263	110	740	382
Other Networks [Member]
Segment Reporting Information [Line Items]
Operating Revenues	(1)	(3)	(1)	(5)
Renewable Energy Generation Of Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues	242	243	518	482
Gas Storage Services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	5	4	12	6
Gas Trading Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	$ (19)	$ (23)	$ (23)	$ (35)
Network [Member]
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			1
Number of operating segments | Segment			8

Segment information (Detail)

Segment information (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended
		Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Segment Reporting Information [Line Items]
Revenue - external		$ 1,439	$ 939	$ 3,109	$ 2,166
Impairment of non-current assets			7		7
Depreciation and amortization		213	187	418	362
Operating income (loss)		322	73	671	269
Adjusted EBITDA		535	267	1,089	638
Earnings (losses) from equity method investments			(1)	2
Capital expenditures				674	530
Property, plant and equipment		20,830		20,830		$ 20,711
Equity method investments		371		371		385
Total assets		30,411		30,411		30,743
Other Segments [Member]
Segment Reporting Information [Line Items]
Revenue - external	[1]			1
Revenue - intersegment	[1]	(7)	(17)	(18)	(27)
Depreciation and amortization	[1]				1
Operating income (loss)	[1]	(7)	(9)	(9)	(13)
Adjusted EBITDA	[1]	(7)	(9)	(9)	(12)
Earnings (losses) from equity method investments	[1]		2		2
Equity method investments	[1]					22
Total assets	[1]	(931)		(931)		(1,333)
Operating Segments [Member] | Network [Member]
Segment Reporting Information [Line Items]
Revenue - external		1,211	715	2,601	1,713
Revenue - intersegment		2		2
Depreciation and amortization		126	94	244	180
Operating income (loss)		299	100	611	289
Adjusted EBITDA		425	194	855	469
Earnings (losses) from equity method investments		3		6
Capital expenditures				470	355
Property, plant and equipment		12,525		12,525		12,363
Equity method investments		131		131		110
Total assets		19,871		19,871		20,126
Operating Segments [Member] | Renewables [Member]
Segment Reporting Information [Line Items]
Revenue - external		242	243	518	482
Revenue - intersegment		2	8	4	9
Impairment of non-current assets			7		7
Depreciation and amortization		81	89	161	172
Operating income (loss)		58	8	107	34
Adjusted EBITDA		139	104	268	213
Earnings (losses) from equity method investments		(3)	(3)	(4)	(2)
Capital expenditures				203	172
Property, plant and equipment		7,800		7,800		7,835
Equity method investments		240		240		253
Total assets		10,437		10,437		10,685
Operating Segments [Member] | Gas [Member]
Segment Reporting Information [Line Items]
Revenue - external		(14)	(19)	(11)	(29)
Revenue - intersegment		3	9	12	18
Depreciation and amortization		6	4	13	9
Operating income (loss)		(28)	(26)	(38)	(41)
Adjusted EBITDA		(22)	$ (22)	(25)	(32)
Capital expenditures				1	$ 3
Property, plant and equipment		505		505		513
Total assets		$ 1,034		$ 1,034		$ 1,265
[1]	Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

Segment information - Reconcili

Segment information - Reconciliation of Adjusted EBITDA to Net Income (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Segment Reporting [Abstract]
Consolidated Adjusted EBITDA	$ 535	$ 267	$ 1,089	$ 638
Impairment of non-current assets		7		7
Depreciation and amortization	213	187	418	362
Interest expense, net of capitalization	68	66	152	127
Income tax expense	172	5	276	47
Other income and (expense)	20	10	69	22
Earnings (losses) from equity method investments		(1)	2
Net Income	$ 102	$ 11	$ 314	$ 117

Related Party Transactions - Sc

Related Party Transactions - Schedule of Related Party Transactions (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Sales To		$ 1		$ 1
Purchases From	$ (14)	(19)	$ (19)	(31)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Purchases From	(2)	(3)	(5)	(5)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Purchases From	(10)	(12)	(18)	(18)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Sales To	1		2
Purchases From	$ (1)	$ (3)	$ (1)	$ (4)

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended		6 Months Ended		12 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Related Party Transaction [Line Items]
Impairments		$ 7,000,000		$ 7,000,000
Equity method investments	$ 371,000,000		$ 371,000,000		$ 385,000,000
Contributions in aid of construction			41,000,000	$ 10,000,000
Affiliated Entity [Member] | Impairment of non-current assets [Member]
Related Party Transaction [Line Items]
Receivable from related party, write-off		$ 7,000,000
Impairments			$ 0
Iberdrola, S.A. [Member] | Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%		20.00%
Related party transaction, amount			$ 57,000,000		$ 70,000,000
Iberdrola, S.A. [Member] | Siemens AG And Gamesa Corporacin Tecnolgica S.A. [Member]
Related Party Transaction [Line Items]
Business acquisition, percentage of voting interests acquired	8.10%		8.10%
Network [Member] | New York Transco [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%		20.00%
Increase in equity method investments	$ 21,000,000
Equity method investments	22,000,000		$ 22,000,000
Total cash consideration received	67,000,000
Proceed from contributions in assets transfer	43,000,000
Contributions in aid of construction	22,000,000
Proceed from contributions in advanced lease payment	$ 2,000,000
Lease period of land and attachment right	99 years

Related Party Transactions - 73

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Jun. 30, 2016	Dec. 31, 2015
Iberdrola Canada Energy Services, Ltd [Member]
Related Party Transaction [Line Items]
Owed By	$ 4	$ 7
Owed To	(4)	(5)
Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Owed By	61	68
Owed To	(48)	(77)
Iberdrola, S.A. [Member]
Related Party Transaction [Line Items]
Owed To	(17)	(3)
Iberdrola Energy Projects, Inc. [Member]
Related Party Transaction [Line Items]
Owed By	1	1
Owed To		(3)
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Owed To	(5)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Owed By	4
Owed To	$ (1)	$ (2)

Accounts Receivable - Additiona

Accounts Receivable - Additional Information (Detail) - DPA [Member] - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015	Dec. 31, 2015
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable, net	$ 61		$ 61		$ 62
Allowance for doubtful accounts, deferred payment arrangement	34		34		$ 35
Provision for doubtful accounts, accounts receivable	$ 0	$ (5)	$ (1)	$ (4)

Income Tax Expense - Additional

Income Tax Expense - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended		6 Months Ended
	Jun. 30, 2016	Jun. 30, 2015	Jun. 30, 2016	Jun. 30, 2015
Income Tax Disclosure [Abstract]
Effective income tax rate before elimination of unfunded future income tax and sale of equity investment	62.90%		46.80%
Unfunded future income tax expense	$ 126		$ 126
Effective tax rate	31.70%	31.20%	31.90%	28.60%
Statutory federal income tax rate			35.00%

Subsequent Events - Additional

Subsequent Events - Additional Information (Detail) shares in Millions	Jul. 14, 2016Installment$ / sharesshares	Jun. 30, 2016$ / shares	Jun. 30, 2016$ / shares
Subsequent Event [Line Items]
Quarterly dividend payable, per share		$ 0.432	$ 0.864
Subsequent Event [Member]
Subsequent Event [Line Items]
Dividend declared date	Jul. 14, 2016
Quarterly dividend payable, per share	$ 0.432
Dividend payment date	Oct. 3, 2016
Dividend record date	Sep. 9, 2016
Subsequent Event [Member] | Performance Shares Units [Member] | Officers and Employees [Member]
Subsequent Event [Line Items]
Share based payment award options grants in period | shares	2.5
Number of equal installments | Installment	3