Avangrid (AGR) 10-Q 16 Dec 15 2015 Q3 Quarterly report Financial data

Document and Entity Information

Document and Entity Information - shares	9 Months Ended
	Sep. 30, 2015	Dec. 15, 2015
Document Information [Line Items]
Document Type	10-Q
Amendment Flag	false
Document Period End Date	Sep. 30, 2015
Document Fiscal Year Focus	2,015
Document Fiscal Period Focus	Q3
Entity Registrant Name	Iberdrola USA, 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		252,235,232

Condensed Consolidated Statemen

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Operating Revenues	$ 1,048	$ 982	$ 3,214	$ 3,476
Operating Expenses
Purchased power, natural gas and fuel used	211	204	754	925
Operations and maintenance	421	383	1,235	1,130
Impairment of non-current assets	3	3	10	12
Depreciation and amortization	163	159	525	470
Taxes other than income taxes	89	80	260	240
Total Operating Expenses	887	829	2,784	2,777
Operating Income	161	153	430	699
Other Income and (Expense)
Other income	16	19	38	50
Losses from equity method investments	(3)	(9)	(3)
Interest expense, net of capitalization	(64)	(61)	(191)	(178)
Income Before Income Tax	110	102	274	571
Income tax expense	56	38	103	244
Net Income	54	64	171	327
Less: Net income attributable to noncontrolling interests	0	0	0	0
Net Income Attributable to Iberdrola USA, Inc.	$ 54	$ 64	$ 171	$ 327
Earnings Per Common Share, Basic and Diluted	$ 0.2	$ 0.3	$ 0.7	$ 1.3
Weighted-average Number of Common Shares Outstanding:
Basic and diluted	243	243	243	243

Condensed Consolidated Stateme3

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Net Income		$ 54	$ 64	$ 171	$ 327
Other Comprehensive Income, Net of Tax Amounts arising during the period, net of tax:
Gain (loss) on defined benefit plans			1	(2)	2
Unrealized gain (loss) during the period on derivatives qualified as hedges		16	(1)	17	(1)
Reclassification to net income of losses on cash flow hedges	[1]	1	1	5	4
Other Comprehensive Income, Net of Tax		17	1	20	5
Comprehensive Income Attributable to Iberdrola USA, Inc.		$ 71	$ 65	$ 191	$ 332
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Condensed Consolidated Balance

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Current Assets
Cash and cash equivalents	$ 1,050	$ 482
Accounts receivable and unbilled revenues, net	723	841
Accounts receivable from affiliates	69	50
Notes receivable from affiliates	8
Derivative assets	120	134
Fuel and gas in storage	190	229
Materials and supplies	97	98
Deferred income taxes	61	68
Prepayments and other current assets	267	288
Regulatory assets	114	80
Deferred income taxes regulatory	7	29
Total Current Assets	2,706	2,299
Property, plant and equipment, at cost	22,286	21,499
Less: accumulated depreciation	(6,289)	(5,796)
Net Property, Plant and Equipment in Service	15,997	15,703
Construction work in progress	1,032	1,396
Total Property, Plant and Equipment	17,029	17,099
Equity method investments	271	262
Other investments	40	91
Regulatory assets	2,269	2,399
Other Assets
Goodwill	1,361	1,361
Intangible assets	541	569
Derivative assets	120	93
Other	60	79
Total Other Assets	2,082	2,102
Total Assets	24,397	24,252
Current Liabilities
Current portion of debt	173	148
Tax equity financing arrangements	112	124
Interest accrued	37	39
Accounts payable	576	684
Accounts payable to affiliates	83	239
Taxes accrued	45	8
Derivative liabilities	86	103
Other current liabilities	257	275
Regulatory liabilities	130	153
Total Current Liabilities	1,499	1,773
Regulatory liabilities	1,354	1,206
Deferred income taxes regulatory	347	462
Deferred income taxes	2,409	2,322
Deferred income	1,571	1,621
Pension and other postretirement	755	785
Tax equity financing arrangements	205	277
Derivative liabilities	49	38
Asset retirement obligations	245	234
Environmental remediation costs	275	284
Other	247	278
Total Other Non-current Liabilities	5,756	5,839
Non-current Debt	2,794	2,516
Total Non-current Liabilities	10,251	10,023
Total Liabilities	$ 11,750	$ 11,796
Commitments and Contingencies
Stockholder's Equity:
Common stock	$ 0	$ 0
Additional paid in capital	11,378	11,378
Retained earnings	1,332	1,161
Accumulated other comprehensive loss	(79)	(99)
Total Stockholder's Equity	12,631	12,440
Non-controlling interests	16	16
Total Equity	12,647	12,456
Total Liabilities and Equity	$ 24,397	$ 24,252

Condensed Consolidated Stateme5

Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014
Cash Flow from Operating Activities:
Net Income	$ 171	$ 327
Adjustments to reconcile net income to net cash provided by (used in) operating activities:
Depreciation and amortization	525	470
Impairment	10	12
Accretion expenses	6	18
Regulatory assets/liabilities amortization	73	(30)
Regulatory assets/liabilities carrying cost	31	19
Pension cost	81	53
Earnings from equity method investments	3
Unrealized losses on marked to market derivative contracts	(17)	(65)
Deferred taxes	10	142
Changes in current operating assets and liabilities
Decrease in accounts receivable and unbilled revenues, net	99	106
Decrease in inventories	40	9
Decrease (increase) in other assets, net	(17)	44
Decrease in accounts payable	(73)	(37)
Increase (decrease) in other liabilities	(115)	(39)
Increase in taxes accrued	37	(7)
Increase in regulatory assets/liabilities	99	132
Net Cash Provided by Operating Activities	963	1,154
Cash Flow from Investing Activities:
Capital expenditures	(670)	(775)
Contributions in aid of construction	25	22
Government grants	9	5
Proceeds from sale of businesses, net of cash	3	30
Payments (receipts) to affiliates	(8)	10
Other investments and equity method investments	28	4
Net Cash Used in Investing Activities	(613)	(704)
Cash Flow from Financing Activities:
Non-current note issuance	350
Repayments of non-current debt	(68)	(34)
Repayments of other short-term debt, net		(5)
Payments on tax equity financing arrangements	(59)	(95)
Repayments of capital leases	(5)	(12)
Net Cash Provided by (Used in) Financing Activities	218	(146)
Net Increase in Cash and Cash Equivalents	568	304
Cash and Cash Equivalents, Beginning of Period	482	219
Cash and Cash Equivalents, End of Period	1,050	523
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	115	106
Cash paid for income taxes	$ 10	$ 24

Condensed Consolidated Stateme6

Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions		Total	Number of shares		Additional paid-in capital	Retained Earnings	Accumulated Other Comprehensive Income (Loss)	Non controlling Interests
Balance at Dec. 31, 2013		$ 12,030			$ 11,378	$ 737	$ (100)	$ 15
Balance, shares at Dec. 31, 2013	[1]		243
Net Income		327				327
Other comprehensive income, net of tax		5					5
Comprehensive income		332
Sale of noncontrolling interests		(4)						(4)
Balance at Sep. 30, 2014		12,358			11,378	1,064	(95)	11
Balance, shares at Sep. 30, 2014	[1]		243
Balance at Dec. 31, 2014		$ 12,456			11,378	1,161	(99)	16
Balance, shares at Dec. 31, 2014		243	243	[1]
Net Income		$ 171				171
Other comprehensive income, net of tax		20					20
Comprehensive income		191
Balance at Sep. 30, 2015		$ 12,647			$ 11,378	$ 1,332	$ (79)	$ 16
Balance, shares at Sep. 30, 2015		243	243	[1]
[1]	Par value of share amounts is $0.01

Condensed Consolidated Stateme7

Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - $ / shares	Sep. 30, 2015	Dec. 31, 2014
Common Stock, Par or Value Per Share	$ 0.01	$ 0.01

Background and Nature of Operat

Background and Nature of Operations	9 Months Ended
	Sep. 30, 2015
Background and Nature of Operations	Note 1. Background and Nature of Operations Iberdrola USA, Inc. (IUSA) is an energy services holding company engaged through its principal subsidiaries IUSA Networks, Inc. (Networks) and Iberdrola Renewables Holding, Inc. (IRHI) in the regulated energy distribution, renewable energy generation (Renewables) and gas businesses (Gas), collectively (Renewables and Gas). We are a wholly owned subsidiary of Iberdrola S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain. The company was organized in 1997 as Energy East Corporation under the laws of New York as the holding company for the principal operating utility companies. Unless the context indicates otherwise, the terms “we,” and “our” are used to refer to IUSA and its subsidiaries. Transaction with UIL Holdings Corporation (UIL Holdings) On February 25, 2015, we announced that the company had entered into a definitive merger agreement (the Agreement) with UIL Holdings and Green Merger Sub, Inc. (Merger Sub), wholly owned subsidiary of IUSA, under which UIL Holdings will merge with and into Merger Sub. Subsequent to the transaction closing, Merger Sub will be the surviving corporation and will change its name to UIL Holdings Corporation and remain a direct or indirect wholly-owned subsidiary of IUSA. IUSA will then become a newly listed U.S. publicly-traded company under its new name of Avangrid, Inc. In connection with the merger, each issued and outstanding share of the common stock of UIL Holdings will be converted into the right to receive one validly issued share of common stock of the newly listed company and $10.50 in cash. Immediately following the consummation of the merger, former holders of UIL Holdings’ common stock will own approximately 18.5% of the newly listed company. The merger is subject to certain closing conditions, including the approval of the shareowners of UIL Holdings and other regulatory approvals. For the three and nine month periods ended September 30, 2015, we have incurred pre-tax merger related expenses of approximately $7 million and $19 million, respectively, which represented legal, investment bank and other merger-related costs.

Basis of Presentation

Basis of Presentation	9 Months Ended
	Sep. 30, 2015
Basis of Presentation	Note 2. Basis of Presentation The accompanying notes should be read in conjunction with notes to the combined and consolidated financial statements of Iberdrola USA, Inc. and subsidiaries (a wholly owned subsidiary of Iberdrola, S.A.) as of December 31, 2014 and 2013 and for the three years ended December 31, 2014 included in the Form S-4 Registration Statement filed with the Securities and Exchange Commission which was declared effective on November 12, 2015. The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of IUSA and its consolidated subsidiaries. Intercompany accounts and transactions have been eliminated in consolidation. The yearend 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 (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 footnote disclosures required by US GAAP for complete financial statements. We believe that 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, condensed consolidated statements of comprehensive income, condensed consolidated statements of cash flows and condensed consolidated statements of changes in equity for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and nine month periods ended September 30, 2015 are not necessarily indicative of the results for the entire fiscal year ending December 31, 2015.

Significant Accounting Policies

Significant Accounting Policies and New Accounting Pronouncements	9 Months Ended
	Sep. 30, 2015
Significant Accounting Policies and New Accounting Pronouncements	Note 3. Significant Accounting Policies and New Accounting Pronouncements As of September 30, 2015 there have been no material changes to any significant accounting policies described in our combined and consolidated financial statements as of December 31, 2014 and 2013 and for the three years ended December 31, 2014. There have been no new accounting pronouncements issued since the filing of the combined and consolidated financial statements as of December 31, 2014 and 2013 and for the three years ended December 31, 2014, that we expect to have a material impact on our condensed consolidated interim financial statements.

Regulatory Assets and Liabiliti

Regulatory Assets and Liabilities	9 Months Ended
	Sep. 30, 2015
Regulatory Assets and Liabilities	Note 4. Regulatory Assets and Liabilities Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. Substantially all assets or liabilities for which funds have been expended or received are either included in rate base or are accruing a carrying cost until they will be included in rate base. The primary items that are not included in rate base or accruing carrying costs are the regulatory assets for pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses, environmental remediation costs which is primarily the offset of accrued liabilities for future spending, unfunded future income taxes, asset retirement obligations and hedge losses. The total amount of these items is $1,824 million. 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. Current and non-current regulatory assets as of September 30, 2015 and December 31, 2014 consisted of: September 30, December 31, As of 2015 2014 (Millions) Current Environmental remediation costs $ 34 $ — Pension and other postretirement benefits cost deferrals 10 — Storm costs 11 14 Temporary supplemental assessment surcharge 6 12 Hedges losses 25 34 Other 28 20 Deferred income taxes regulatory 7 29 Total Current Regulatory Assets 121 109 Non-current Environmental remediation costs 171 247 Pension and other postretirement benefits cost deferrals 145 125 Pension and other postretirement benefits 976 1,101 Storm costs 251 259 Deferred meter replacement costs 35 36 Unamortized losses on reacquired debt 23 25 Unfunded future income taxes 341 366 Asset retirement obligation 37 32 Deferred property taxes 42 30 Federal tax depreciation normalization adjustment 150 128 Merger capital expense target customer credit 15 10 Other 83 40 Total Non-current Regulatory Assets $ 2,269 $ 2,399 “Environmental remediation costs” represent 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. 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. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. “Pension and other postretirement benefits” represent the actuarial losses on the pension and other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. Because no funds have yet been expended for this regulatory asset, it does not accrue carrying costs and is not included within the rate base. “Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. The recovery of these amounts will be determined in future proceedings. “Storm costs” for Central Maine Power (CMP), New York State Electric and Gas (NYSEG) and Rochester Gas and Electric (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. “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 at the related existing depreciation amounts. “Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt. “Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. “Asset Retirement Obligations” 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 amortization period is awaiting a future NYPSC rate proceeding. Current and non-current regulatory liabilities as of September 30, 2015 and December 31, 2014 consisted of: September 30, December 31, As of 2015 2014 (Millions) Current Reliability support services (Cayuga) $ 17 $ 18 Plant decommissioning 5 13 Non by-passable charges 18 19 Energy efficiency portfolio standard 39 34 Gas supply charge and deferred natural gas cost 4 6 Revenue reconciliation mechanism transmission revenue true up 15 7 Yankee DOE phase I — 23 Rate refund – FERC ROE proceeding 6 — CMP transmission refund 19 16 Other 7 17 Total Current Regulatory Liabilities 130 153 Non-current Accrued removal obligations 737 721 Asset sale gain account 16 32 Carrying costs on deferred income tax bonus depreciation 107 81 Economic development 34 33 Merger capital expense target customer credit 17 17 Pension and other postretirement benefits cost deferrals 60 50 Positive benefit adjustment 51 51 New York State tax rate change 17 16 Post term amortization 37 20 Theoretical reserve flow thru impact 63 24 Deferred property tax 68 51 Other 147 110 Deferred income taxes regulatory 347 462 Total Non-current Regulatory Liabilities $ 1,701 $ 1,668 “Reliability support services (Cayuga)” represent the difference between actual expenses for reliability support services and the amount provided for in rates. “Non by-passable charges” represent the non by-passable fixed charge paid by all customers. An asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered. This 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. “Accrued removal obligations” represent the differences between asset removal costs incurred and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant. “Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is awaiting a future NYPSC rate proceeding. “Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is awaiting a future NYPSC rate proceeding. “Economic development” represents the economic development program which enables NYSEG and RGE to foster economic development through attraction, expansion, and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RGE varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is awaiting a future NYPSC rate proceeding. “Merger capital expense target customer credit” account was created as a result of NYSEG and RGE not meeting certain capital expenditure requirements established in the order approving the purchase of Energy East by Iberdrola. The amortization period is awaiting a future NYPSC rate proceeding. “Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this a regulatory liability is not reflected within rate base. It also represents the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings. “Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Energy East. This is being used to moderate increases in rates. The remaining amortization period is awaiting a future NYPSC rate proceeding. “New York State tax rate change” represents the excess funded accumulated deferred income tax balance caused by the 2014 New York State tax rate change from 7.1% to 6.5%. The amortization period is awaiting a future NYPSC rate proceeding. “Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. Further amortization is awaiting a future NYPSC rate proceeding. “Theoretical reserve flow thru impact” represent the differences from the rate allowance for applicable federal and state flow through tax impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is awaiting a future NYPSC rate proceeding. “Other” includes the reserve for the refund related to the FERC ROE proceedings, cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage.

Fair Value of Financial Instrum

Fair Value of Financial Instruments and Fair Value Measurements	9 Months Ended
	Sep. 30, 2015
Fair Value of Financial Instruments and Fair Value Measurements	Note 5. 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 non-current investments available for sale using quoted market prices in active markets for identical assets and include the measurements in Level 1. The investments primarily consist of money market funds which include the Rabbi Trusts related to the deferred compensation plans. • 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 a basis adjustment is added to the forward prices we include the fair value measurement for these contracts in Level 3. 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. Monthly data points will be included in this category provided they fall within the bid/ask data provided by brokers for seasonal strips and quarterly quotes. Trader marks that fall outside of a five-percent threshold of the average broker marks and fall outside of the widest bid/ask spreads will be adjusted to reflect the broker quotes. Any position that is initially classified as Level 2 will be evaluated before and after the provision of credit reserves with incremental value changes of ten-percent or more classified as Level 3. To be included in this category, market data, or a derivative thereof, must be available for the entire trade term. 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 such as tolling arrangements with historical volatilities, park and loan arrangements that include the value of expired legs, and transactions with significant credit adjustments are included in Level 3 fair value. The valuation premise in this category will be based on market participant assumptions. The financial instruments measured at fair value as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 Level 1 Level 2 Level 3 Netting Total (Millions) Securities Portfolio (available for sale) $ 33 $ — $ — $ — $ 33 Financial Assets Derivative financial instruments – power 13 61 71 (31 ) 114 Derivative financial instruments – gas 253 22 68 (217 ) 126 Total 266 83 139 (248 ) 240 Financial Liabilities Derivative financial instruments – power (42 ) (16 ) (13 ) 31 (40 ) Derivative financial instruments – gas (219 ) (39 ) (52 ) 217 (93 ) Derivative financial instruments – other — — (2 ) — (2 ) Total $ (261 ) $ (55 ) $ (67 ) $ 248 $ (135 ) As of December 31, 2014 Level 1 Level 2 Level 3 Netting Total (Millions) Securities Portfolio (available for sale) $ 33 $ — $ — $ — $ 33 Financial Assets Derivative financial instruments – power 11 83 48 (53 ) 89 Derivative financial instruments – gas 18 638 61 (579 ) 138 Total 29 721 109 (632 ) 227 Financial Liabilities Derivative financial instruments – power (40 ) (42 ) (7 ) 53 (36 ) Derivative financial instruments – gas (25 ) (614 ) (42 ) 579 (102 ) Derivative financial instruments – other — — (3 ) — (3 ) Total $ (65 ) $ (656 ) $ (52 ) $ 632 $ (141 ) The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the periods ended September 30, 2015 and 2014 consisted of: Three Months Nine Months (Millions) 2015 2014 2015 2014 Fair Value Beginning of Period, $ 103 $ — $ 57 $ 53 Gains recognized in revenues (4 ) — 38 4 (Losses) recognized in revenues (3 ) 24 (8 ) (34 ) Total gains (losses) recognized in revenues (7 ) 24 30 (30 ) Gains recognized in OCI 4 — 6 — (Losses) recognized in OCI (2 ) (1 ) (2 ) (1 ) Total Gains (Losses) Recognized in OCI 2 (1 ) 4 (1 ) Purchases (22 ) 1 (1 ) 3 Settlements (5 ) (3 ) (12 ) (6 ) Transfers out of Level 3 (a) — (1 ) (7 ) 1 Fair Value as of September 30, $ 71 $ 20 $ 71 $ 20 Gains (losses) for the period included in earnings attributable to the change $ (7 ) $ 24 $ 30 $ (30 ) (a) Transfers out of Level 3 were the result of increased observability of market data. 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 two years), using past and current views of prices for those future periods. As of September 30, 2015 Instruments Instrument Valuation Technique Valuation Inputs Index Variability Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 4.58 $ 7.37 $ 2.69 SP15 ($/MWh) $ 47.03 $ 80.28 $ 23.59 Mid C ($/MWh) $ 38.12 $ 83.93 $ 11.00 Cinergy ($/MWh) $ 37.91 $ 77.49 $ 21.17 As of December 31, 2014 Instruments Instrument Valuation Technique Valuation Inputs Index Variability Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 4.33 $ 5.47 $ 3.34 SP15 ($/MWh) $ 43.27 $ 59.12 $ 30.04 Mid C ($/MWh) $ 36.16 $ 56.28 $ 12.62 Cinergy ($/MWh) $ 37.41 $ 68.65 $ 21.17 Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2017 beyond two years. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are traded at liquid hubs in the West and Midwest and are used to hedge merchant wind production in those regions. We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuations inputs and concluded that no material change to the financial statements is expected given the following: (i) any changes in the fair value of the gas swaps hedging inventory would be expected to be largely offset by changes in the value of the inventory; and (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. Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models themselves. Authorized trading points and associated forward price curves are maintained and documented by the Middle Office. Models used in valuation of the various products are developed and documented by the Structuring and Market Analysis group. Transaction models are valued in part on the basis of forward price, correlation and volatility curves. Descriptions of these curves and their derivations are maintained and documented by the Structuring and Market Analysis group. Forward price curves used in valuing the models are applied to the full duration of transactional models to a maximum of approximately thirty years. The 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. Fair Value of Debt As of September 30, 2015 and December 31, 2014 debt consisted of first mortgage bonds, fixed and variable unsecured pollution control notes and other various non-current debt. The estimated fair value of debt amounted to $3,193 million and $2,962 million as of September 30, 2015 and December 31, 2014, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy for the fair value of debt is considered as Level 2, except for unsecured pollution control notes-variable, which are considered Level 3.

Derivative Instruments and Hedg

Derivative Instruments and Hedging	9 Months Ended
	Sep. 30, 2015
Derivative Instruments and Hedging	Note 6. 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 a non by-passable wires charge adjustment that allows them to pass through rates any changes in the market price of electricity. They use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations. The amount recognized in regulatory assets for electricity derivatives was a loss of $30.2 million as of September 30, 2015, and a gain of $17.9 million as of September 30, 2014. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a loss of $14.8 million and $27.1 million, respectively, for the three and nine month period ended September 30, 2015, and a loss of $8.9 million and gain of $34.7 million, respectively, for the three and nine month period ended September 30, 2014. 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 loss of $3.9 million as of September 30, 2015, and a loss of $0.4 million as of September 30, 2014. The amount reclassified from regulatory assets into income, which is included in natural gas purchased, was a loss of $3.4 million and a gain of $2.3 million, respectively, for the nine month periods ended September 30, 2015 and 2014. There was no loss or gain reclassified from regulatory assets into income for the three month periods ended September 30, 2015 and 2014. The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, December 31, (Millions) Wholesale electricity purchase contracts (MWh) 6.9 6.6 Natural gas purchase contracts (Dth) 4.6 3.8 Other fuel purchase contracts (Gallons) 4.1 2.8 The location and amounts of derivatives designated as hedging instruments associated with Networks activities as of September 30, 2015 and December 31, 2014 consisted of: Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair (Millions) Location Value Location Value As of September 30, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ (21 ) Non-current Other assets — Other liabilities (9 ) Natural gas derivatives: Current Current assets — Current liabilities (4 ) Other Contracts Current Current assets — Current liabilities (2 ) Total $ — $ (36 ) As of December 31, 2014 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ (20 ) Non-current Other assets — Other liabilities (9 ) Natural gas derivatives: Current Current assets — Current liabilities (4 ) Non-current Other assets — Other liabilities (1 ) Other contracts Current assets — Current liabilities (3 ) Total $ — $ (37 ) The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, (Loss) Recognized in OCI on Derivatives Location of (Loss) Reclassified from Accumulated OCI into Income (Loss) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2015 Interest rate contracts $ — Interest expense $ (3 ) Commodity contracts: Other (2 ) Operating expenses — Total $ (2 ) $ (3 ) 2014 Interest rate contracts $ — Interest expense $ (3 ) Commodity contracts: Other (1 ) Operating expenses — Total $ (1 ) $ (3 ) Nine Month Period Ended September 30, (Loss) Recognized in OCI on Derivatives Location of (Loss) Reclassified from Accumulated OCI into Income (Loss) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2015 Interest rate contracts $ — Interest expense $ (7 ) Commodity contracts: Other (2 ) Operating expenses (2 ) Total $ (2 ) $ (9 ) 2014 Interest rate contracts $ — Interest expense $ (7 ) Commodity contracts: Other (1 ) Operating expenses — Total $ (1 ) $ (7 ) (a) Changes in OCI are reported on a pre-tax basis. The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $93.5 million and $102.3 million as of September 30, 2015 and 2014, respectively. We recorded $2.2 million and $2.3 in net derivative losses related to discontinued cash flow hedges for the three month periods ended September 30, 2015 and 2014, respectively. We recorded $6.5 million and $6.9 in net derivative losses related to discontinued cash flow hedges for the nine month periods ended September 30, 2015 and 2014, respectively. We will amortize approximately $8.7 million of discontinued cash flow hedges in 2015. During the three and nine month periods ended September 30, 2015 and 2014, there was no ineffective portion for cash flow hedges. The unrealized loss of $2.5 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable for the nine month period ended September 30, 2015. We expect that $1.7 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 twenty seven months. The offsetting of derivative assets as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Gross Net Amounts of Assets Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ 13 $ (13 ) $ — $ — $ — $ — December 31, 2014 Derivatives 11 (11 ) — — — — The offsetting of derivative liabilities as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Gross Net Amounts of Liabilities Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ (49 ) $ 13 $ (36 ) $ — $ 36 $ — December 31, 2014 Derivatives (48 ) 11 (37 ) — 37 — (b) Renewables and Gas activities We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities. Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also enter into basis swaps to hedge the value of our contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and delivery point of the contracted transport in future periods. Both Renewables and Gas have proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets. 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 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 September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 December 31, 2014 (MWh/Dth in millions) Wholesale electricity purchase contracts 3 2 Wholesale electricity sales contracts 6 7 Foreign exchange forward purchase contracts 5 — Natural gas and other fuel purchase contracts 309 275 Financial power contracts 8 8 Basis swaps – purchases 82 160 Basis swaps – sales 86 161 The fair values of derivative contracts associated with Renewables and Gas activities as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 December 31, 2014 (Millions) Wholesale electricity purchase contracts $ (11 ) $ (12 ) Wholesale electricity sales contracts 37 44 Foreign exchange forward purchase contracts (2 ) (3 ) Natural gas and other fuel purchase contracts 39 54 Financial power contracts 77 48 Basis swaps – purchases 7 (4 ) Basis swaps – sales (6 ) (4 ) Total $ 141 $ 123 The offsetting of derivative assets as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Gross Net Amounts of Assets Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ 476 $ (236 ) $ 240 $ (45 ) $ (102 ) $ 93 December 31, 2014 Derivatives 847 (620 ) 227 (66 ) (73 ) 88 The offsetting of derivative liabilities as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Amounts Net Amounts of Liabilities Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ (335 ) $ 236 $ (99 ) $ 45 $ 7 $ (47 ) December 31, 2014 Derivatives (724 ) 620 (104 ) 66 1 (37 ) The effect of trading and non-trading derivatives associated with Renewables and Gas activities for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Wholesale electricity purchase contracts $ (14 ) $ (7 ) Wholesale electricity sales contracts 32 5 Financial power contracts 5 18 Financial and natural gas contracts 14 10 Total Gain (Loss) $ 37 $ 26 Nine Month Period Ended September 30, 2015 2014 (Millions) Wholesale electricity purchase contracts $ 1 $ (9 ) Wholesale electricity sales contracts (8 ) (7 ) Financial power contracts 19 (7 ) Financial and natural gas contracts (22 ) 79 Total Gain (Loss) $ (10 ) $ 56 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 location and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of September 30, 2015 (no hedge accounting has been applied in 2014) consisted of: Asset Derivatives Liability Derivatives (Millions) Balance Sheet Location Fair Value Balance Sheet Fair Value As of September 30, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ 3 Current liabilities $ 1 Non-current Other assets 7 Other liabilities — Natural gas derivatives: Current Current assets 21 Current liabilities (3 ) Non-current Other assets 5 Other liabilities (3 ) Total $ 36 $ (5 ) The effect of derivatives in cash flow hedging relationships on OCI and income for the three and nine month periods ended September 30, 2015 (no hedge accounting has been applied in 2014) consisted of: Three Month Period Ended September 30, 2015 Gain Recognized Location of Gain Reclassified from Accumulated OCI into Income Gain Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) Commodity contracts: Other $ 28 Revenues $ — Total $ 28 $ — (a) Changes in OCI are reported on a pre-tax basis. Nine Month Period Ended September 30, 2015 Gain Recognized Location of Gain Reclassified (Millions) Effective Portion (a) Effective Portion (a) Commodity contracts: Other $ 29 Revenues $ — Total $ 29 $ — (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 $18.9 million of gains included in accumulated OCI at September 30, 2015 is expected to be reclassified into earnings within the next 12 months. During the three and nine month periods ended September 30, 2015 we recorded a net gain of $2.1 million and $1.8 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 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. 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 do not 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. Under the master netting arrangements our obligation to return cash collateral was $0.1 million and $0.2 million as of September 30, 2015 and December 31, 2014, respectively. Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of September 30, 2015 is $36.5 million, for which we have posted collateral of $53 million. If the credit risk related contingent features underlying those agreements were triggered on September 30, 2015, we would receive a $16.5 million refund of collateral.

Contingencies

Contingencies	9 Months Ended
	Sep. 30, 2015
Contingencies	Note 7. 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. Transmission – Federal Energy Regulatory Commission (FERC) Return on Equity (ROE) Proceeding CMP’s transmission rates are determined by a tariff regulated by the FERC and administered by ISO New England (ISO-NE). Transmission rates are set annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses, including return of and on investment in assets. The FERC provided a base ROE of 11.14% and additional incentive adders applicable to assets based upon vintage, voltage, and other factors. Complaint I – In September 2011 the Massachusetts Attorney General filed a complaint with the FERC that the ROE was too high and should be lowered by 1.94%, to a value of 9.2%. CMP is a member of the New England Transmission Owners and is therefore subject to the outcome of the complaint proceeding. On October 16, 2014, the FERC issued an order in the ROE case which concluded: • The base ROE is set at 10.57% effective October 16, 2014. • There is a ROE cap on incentive returns of 11.74%, also effective October 16, 2014. • The long-term growth rate used in the two-step discounted cash flows analysis should be Gross Domestic Product and is 4.39% in this proceeding. This aspect of their decision results from the paper hearing that FERC initiated in its September 2014 decision in this case. • CMP must provide refunds for the period October 2011 through December 2012 with a base ROE of 10.57% and a ROE cap on incentives of 11.74%. 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. Complaint II – Filed December 27, 2012. On June 19, 2014, the FERC issued an order setting this case for settlement and hearing and set a refund effective date of December 27, 2012. The parties entered settlement negotiations which ended in late October 2014 when the parties were unable to reach agreement. The FERC held hearings in June 2015 and we are awaiting the judge’s recommended decision. Once the exception period for the decision has passed, FERC will issue an order, which would be expected in mid-2016. Complaint III – Filed August 2014 by the initial complainants in Complaint II, reiterates the same positions in Complaint II. On November 24, 2014, the FERC issued an order setting the complaint for hearing, consolidating Complaints II and III, and establishing a refund effective date of July 31, 2014. CMP reserved for refunds in 2013 and 2014. The 2013 reserve was $6.6 million associated with Complaint I. In 2014, CMP recorded an additional reserve as a regulatory liability of $29.9 million associated with Complaints I, II, and III. CMP’s reserved amounts reflect projected refund obligations that are consistent with the FERC’s March 3, 2015 final Complaint I decision. MNG Rate Case On November 6, 2015, MNG, the Maine Office of Public Advocate and the City of Augusta filed a stipulation in the MNG rate case. The stipulation provides for MNG distribution rate increases of 17.4% on January 1, 2016, 17.4% on January 1, 2017 and 17.4% on January 1, 2018. MNG distribution rates will decrease 6.0% on January 1, 2019 and decrease 2.8% on January 1, 2020. The Stipulation provides for an immediate one-time gross plant investment disallowance for the Augusta Expansion Project of $6.0M as of December 31, 2015. MNG will also phase-in $10.0 million of gross Augusta Expansion investment over three years. Of the $10.0 million Augusta investment phase-in, $7.8 million will be at risk of being further disallowed if MNG does not reach certain Augusta sales throughput targets. Any further disallowance would occur effective January 1, 2020. The rate stipulation provides for a 9.55% ROE, 50% equity allowance and combined revenue requirement with a three year separate Augusta surcharge. The Stipulation is opposed by the City of Brunswick. On December 11, 2015, the MPUC issued an Examiner’s Report recommending that the Commission reject the Stipulation citing that the stipulating parties have not demonstrated that the stipulated result is reasonable and that the overall stipulated result is in the public interest. Exceptions to the Examiner’s Report are to be filed on December 18, 2015. The Maine PUC is expected to rule on the stipulation by the end of December 2015. The Company cannot predict the outcome of the proceeding.

Environmental Liability

Environmental Liability	9 Months Ended
	Sep. 30, 2015
Environmental Liability	Note 8. Environmental Liability Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies. 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-three waste sites. In addition, we have a program to investigate and perform necessary remediation at fifty-three sites where gas was manufactured in the past. We have entered into consent orders with various environmental agencies to investigate, and where necessary, remediate forty-seven of the fifty-three sites. The total liability to investigate and perform remediation, as necessary, at all of these sites was $311 and $319 million as of September 30, 2015 and December 31, 2014, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2048. FirstEnergy NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at nineteen former manufactured gas sites. FirstEnergy’s liability was based on their status as successor to Associated Gas & Electric Company, a utility holding conglomerate that unlawfully dominated operations at the plants from approximately 1906 through 1942. In July 2011, the District Court issued a decision and order in NYSEG’s favor. Based on past and future cleanup costs at the nineteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the decision were upheld on appeal. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-judgment interest of $3 million. FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million, excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014. FirstEnergy remains liable for a substantial share of clean-up expenses at nine MPG Energy sites. In January 2015, NYSEG sent FirstEnergy a demand for $16 million representing FirstEnergy’s share of clean-up expenses incurred by NYSEG at the nine sites from January 2010 to November 2014 while the District Court appeal was pending. FirstEnergy disputes a portion of the demand on various grounds, but paid NYSEG the undisputed portion totaling approximately $12.9 million in October 2015. NYSEG is still pursuing payment of the balance of its original demand. FirstEnergy would also be liable for a share of future costs, which, based on current projections, would be $27 million. As of September 30, 2015, the $16 million has been recorded as a receivable with an offset to the associated regulatory asset and the remaining 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 NYSEG filed suit in federal court on August 14, 2013 against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share is approximately $89 million, excluding pre-judgment interest. Any recovery will be flowed through to NYSEG ratepayers. Century and OneBeacon have answered the complaints admitting issuance of the policies and receipt of notice of the claims, but asserting a number of legal defenses. The legal discovery process is expected to close in early 2016. We cannot predict the outcome of this matter.

Post-retirement and Similar Obl

Post-retirement and Similar Obligations	9 Months Ended
	Sep. 30, 2015
Post-retirement and Similar Obligations	Note 9. Post-retirement and Similar Obligations We made pension contributions of $10.5 million and $10.9 million for the three and nine month periods ended September 30, 2015, respectively. We do not expect to make additional contributions for remainder of 2015. The components of net periodic benefit cost for pension benefits for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 9 $ 8 Interest cost 24 27 Expected return on plan assets (39 ) (41 ) Amortization of: Prior service costs 1 1 Actuarial loss 32 23 Net Periodic Benefit Cost $ 27 $ 18 Nine Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 27 $ 24 Interest cost 72 81 Expected return on plan assets (117 ) (123 ) Amortization of: Prior service costs 3 3 Actuarial loss 96 69 Net Periodic Benefit Cost $ 81 $ 54 The components of net periodic benefit cost for postretirement benefits for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 1 $ 1 Interest cost 4 5 Expected return on plan assets (2 ) (2 ) Amortization of: Prior service costs (2 ) (3 ) Actuarial loss 2 — Net Periodic Benefit Cost $ 3 $ 1 Nine Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 3 $ 3 Interest cost 12 15 Expected return on plan assets (6 ) (6 ) Amortization of: Prior service costs (6 ) (9 ) Actuarial loss 6 — Net Periodic Benefit Cost $ 9 $ 3

Equity

Equity	9 Months Ended
	Sep. 30, 2015
Equity	Note 10. Equity Our share capital consisted of 243 shares, authorized and outstanding, wholly owned by Iberdrola, each having a par value of $0.01, with a total value of additional paid in capital of $11,378 million as of September 30, 2015 and December 31, 2014. All shares have the same voting and economic rights. We have no treasury shares or convertible preferred shares as of September 30, 2015 or December 31, 2014. Accumulated Other Comprehensive Income (Loss) Accumulated OCI for the nine month periods ended September 30, 2015 and 2014 consisted of: Accumulated Other Comprehensive Income (Loss) As of 2014 As of As of 2015 As of September 30, (Millions) Gain (loss) on defined benefit plans, net of income tax expense (benefit) of $0.4 for 2014 and $(1) for 2015 $ (26 ) $ 1 $ (25 ) $ (25 ) $ (2 ) $ (27 ) Gain on nonqualified pension plans , net of income tax expense of $0.4 for 2014 (8 ) 1 (7 ) (11 ) — (11 ) Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, net of income tax expense (benefit) of $(0.4) for 2014 and $11 for 2015 — (1 ) (1 ) (2 ) 17 15 Reclassification to net income of losses on cash flow hedges, net of income tax expense of $2.7 for 2014 and $3.6 for 2015 (a) (66 ) 4 (62 ) (61 ) 5 (56 ) Gain (loss) on derivatives qualified as cash flow hedges (66 ) 3 (63 ) (63 ) 22 (41 ) Accumulated Other Comprehensive (Loss) Income $ (100 ) $ 5 $ (95 ) $ (99 ) $ 20 $ (79 ) Accumulated OCI for the three month periods ended September 30, 2015 and 2014 consisted of: Accumulated Other Comprehensive Income (Loss) As of 2014 As of As of June 30, 2015 2015 As of September (Millions) Gain (loss) on defined benefit plans $ (25 ) $ — $ (25 ) $ (27 ) $ — $ (27 ) Gain on nonqualified pension plans, net of income tax expense of $0.4 for 2014 (8 ) 1 (7 ) (11 ) — (11 ) Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, net of income tax expense (benefit) of $(0.4) for 2014 and $10 for 2015 — (1 ) (1 ) (1 ) 16 15 Reclassification to net income of losses on cash flow hedges, net of income tax benefit of $0.4 for 2014 and $0.4 for 2015 (a) (63 ) 1 (62 ) (57 ) 1 (56 ) Gain (loss) on derivatives qualified as cash flow hedges (63 ) — (63 ) (58 ) 17 (41 ) Accumulated Other Comprehensive (Loss) Income $ (96 ) $ 1 $ (95 ) $ (96 ) $ 17 $ (79 ) (a) Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Net Income Per Share

Net Income Per Share	9 Months Ended
	Sep. 30, 2015
Net Income Per Share	Note 11. Net Income Per Share Basic net income per share is computed by dividing net income attributable to Iberdrola USA, Inc. by the weighted-average number of shares of our common stock outstanding. We did not have any potentially-dilutive securities for the three and nine month periods ended September 30, 2015 and 2014. The calculations of basic and diluted earnings per share attributable to Iberdrola USA, Inc., including a reconciliation of the numerators and denominators for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Months Nine Months Ended September 30, 2015 2014 2015 2014 (Millions, except for number of shares) Numerator: Net income attributable to Iberdrola USA, Inc. $ 54 $ 64 $ 171 $ 327 Denominator: Weighted-average number of shares outstanding, basic and diluted 243 243 243 243 Net Income Per Share, Basic and Diluted $ 0.2 $ 0.3 $ 0.7 $ 1.3

Segment Information

Segment Information	9 Months Ended
	Sep. 30, 2015
Segment Information	Note 12. Segment Information Our segment reporting structure uses our management reporting structure as its foundation to reflect how IUSA manages the business internally and is organized by type of business. We report our financial performance based on the following three reportable segments: • Networks: including all the energy transmission and distribution activities, and any other regulated activity originated in New York and Maine carried out by the Group. The Networks reportable segment includes four rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment. • Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities. • Gas: including gas trading and storage businesses carried on by the Group. Products and services are sold between reportable segments and affiliate companies at cost. The Chief Operating Decision Maker evaluates segment performance based on segment adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) defined as net income (loss), adding back net income (loss) attributable to other non-controlling interests, income tax expense (benefit), depreciation and amortization, impairment of non-current assets and interest expense, net of capitalization, and then subtracting other income and (expense), earnings (losses) from equity method investments and income from discontinued operations, 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 month period ended September 30, 2015 consisted of: Three Month Period Ended September 30, 2015 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 783 $ 299 $ (34 ) $ — $ 1,048 Revenue - intersegment 7 3 17 (27 ) — Impairment of non-current assets — 3 — — 3 Depreciation and amortization 70 88 5 — 163 Operating income (loss) 154 45 (31 ) (7 ) 161 Adjusted EBITDA 224 136 (26 ) (7 ) 327 Earnings (losses) from equity method investments $ — $ (4 ) $ — $ 1 $ (3 ) (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the three month period ended September 30, 2015 are: $705 million from regulated electric operations, $80 million from regulated gas operations and $(2) million from other operations of Networks; $299 million from renewable energy generation of Renewables; $3 million from gas storage services and $(37) million from gas trading operations of Gas. Segment information for the three month period ended September 2014 consisted of: Three Month Period Ended September 30, 2014 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 752 $ 264 $ (34 ) $ — $ 982 Revenue - intersegment — 3 22 (25 ) — Impairment of non-current assets — 3 — — 3 Depreciation and amortization 70 84 5 — 159 Operating income (loss) 157 25 (29 ) — 153 Adjusted EBITDA 227 112 (24 ) — 315 Earnings (losses) from equity method investments $ (5 ) $ (4 ) $ — $ — $ (9 ) (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the three month period ended September 30, 2014 are: $668 million from regulated electric operations, $83 million from regulated gas operations and $1 million from other operations of Networks; $264 million from renewable energy generation of Renewables; $0 million from gas storage services and $(34) million from gas trading operations of Gas. Segment information as of and for the nine month period ended September 30, 2015 consisted of: Nine Month Period Ended September 30, 2015 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 2,496 $ 781 $ (63 ) $ — $ 3,214 Revenue - intersegment 23 12 35 (70 ) — Impairment of non-current assets — 10 — — 10 Depreciation and amortization 250 260 14 1 525 Operating income (loss) 443 79 (72 ) (20 ) 430 Adjusted EBITDA 693 349 (58 ) (19 ) 965 Earnings (losses) from equity method investments — (6 ) — 3 (3 ) Capital expenditures $ 484 $ 183 $ 3 $ — $ 670 As of September 30, 2015 Property, plant and equipment 8,608 7,887 534 — 17,029 Equity method investments — 250 — 21 271 Total assets $ 12,929 $ 10,785 $ 1,261 $ (578 ) $ 24,397 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the nine month period ended September 30, 2015 are: $2,031 million from regulated electric operations, $462 million from regulated gas operations and $3 million from other operations of Networks; $781 million from renewable energy generation of Renewables; $9 million from gas storage services and $(72) million from gas trading operations of Gas. Segment information for the nine month period ended September 30, 2014 consisted of: Nine Month Period Ended September 30, 2014 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 2,584 $ 848 $ 38 $ 6 $ 3,476 Revenue – intersegment — 7 52 (59 ) — Impairment of non-current assets — 12 — — 12 Depreciation and amortization 205 248 16 1 470 Operating income 489 169 42 (1 ) 699 Adjusted EBITDA 694 429 58 — 1,181 Earnings (losses) from equity method investments (5 ) 2 — 3 — Capital expenditures $ 667 $ 106 $ 2 $ — $ 775 As of December 31, 2014 Property, plant and equipment 8,389 8,185 525 — 17,099 Equity method investments — 262 — — 262 Total assets $ 12,961 $ 12,329 $ 1,393 $ (2,431 ) $ 24,252 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Included in revenue-external for the nine month period ended September 30, 2014 are: $2,080 million from regulated electric operations, $502 million from regulated gas operations and $2 million from other operations of Networks; $848 million from renewable energy generation of Renewables; $5 million from gas storage services and $33 million from gas trading operations of Gas. Reconciliation of consolidated Adjusted EBITDA to the IUSA consolidated Income Before Income Tax for the three and nine month periods ended September 30, 2015 and 2014 is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2015 2014 2015 2014 Consolidated Adjusted EBITDA $ 327 $ 315 $ 965 $ 1,181 Less: Impairment of non-current assets 3 3 10 12 Depreciation and amortization 163 159 525 470 Interest expense, net of capitalization 64 61 191 178 Add: Other income and (expense) 16 19 38 50 Earnings (losses) from equity method investments (3 ) (9 ) (3 ) — Consolidated Income Before Income Tax $ 110 $ 102 $ 274 $ 571

Related Party Transactions

Related Party Transactions	9 Months Ended
	Sep. 30, 2015
Related Party Transactions	Note 13. Related Party Transactions We engage in related party transactions which are generally provided at cost and in accordance with applicable state and federal commission regulations. Related party transactions for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Sales Purchases From Sales Purchases From Iberdrola Canada Energy Services, Ltd $ (1 ) $ 14 $ — $ 34 Iberdrola Renovables Energía, S.L. — 2 — 2 Iberdrola, S.A. — 8 — 3 Other (2 ) — (2 ) 1 Nine Month Period Ended September 30, 2015 2014 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ 45 $ — $ 29 Iberdrola Renovables Energía, S.L. — 7 — 7 Iberdrola, S.A. — 26 — 14 Other (2 ) 4 (1 ) 2 In addition to the statements of income items above we made purchases of turbines for wind farms from Gamesa Corporación Tecnológica, S.A., in which our ultimate parent Iberdrola has a 20% ownership. The incremental amounts capitalized for these transactions were $72 million and $226 million as of September 30, 2015 and December 31, 2014, respectively. Related party balances as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 December 31, 2014 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ 9 $ (5 ) $ 1 $ — Iberdrola, S.A. — (26 ) — — Iberdrola Renovables Energía, S.A.U. — (7 ) — — Gamesa Corporación Tecnológica, S.A. 63 (38 ) 33 (223 ) Other — (2 ) 1 (1 ) Transactions with our parent company, Iberdrola, relate predominantly to recharges of corporate services and management fees. Also included within the Purchases From category are charges for credit support relating to guarantees Iberdrola has provided to third parties guarantying our performance. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when corporate services are provided to two or more companies of IUSA 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 IRHI’s gas-fired generation facility at Klamath. We also have gas purchase and sales for trading activities with Iberdrola Canada Energy Services and these trading transactions are presented net within revenue in the consolidated statements of income. There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances, other than a $10 million write-off related to an arrangement to purchase turbines from Gamesa Corporación Tecnológica, S.A which was recorded in impairment of non-current assets in the consolidated statements of income. IUSA manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a cash pooling agreement with Bank Mendes Gans, N.V., similar to other Iberdrola subsidiaries. Cash surpluses remaining after meeting the liquidity requirements of IUSA 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	9 Months Ended
	Sep. 30, 2015
Accounts Receivable	Note 14. 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. 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. The allowance for doubtful accounts for DPAs at September 30, 2015 and December 31, 2014 were $37 million and $35 million, respectively. Furthermore, the provision for bad debts associated DPA’s for the nine month periods ended September 30, 2015 and 2014 approximated $1 million and $6 million, respectively, and for the three month periods ended September 30, 2015 and 2014 approximated $5 million and $(7) million, respectively. DPA receivable balances, net of the applicable reserve, were $27.4 million and $40.1 million at September 30, 2015 and December 31, 2014, respectively.

Regulatory Assets and Liabili22

Regulatory Assets and Liabilities (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Current and Non-Current Regulatory Assets	Current and non-current regulatory assets as of September 30, 2015 and December 31, 2014 consisted of: September 30, December 31, As of 2015 2014 (Millions) Current Environmental remediation costs $ 34 $ — Pension and other postretirement benefits cost deferrals 10 — Storm costs 11 14 Temporary supplemental assessment surcharge 6 12 Hedges losses 25 34 Other 28 20 Deferred income taxes regulatory 7 29 Total Current Regulatory Assets 121 109 Non-current Environmental remediation costs 171 247 Pension and other postretirement benefits cost deferrals 145 125 Pension and other postretirement benefits 976 1,101 Storm costs 251 259 Deferred meter replacement costs 35 36 Unamortized losses on reacquired debt 23 25 Unfunded future income taxes 341 366 Asset retirement obligation 37 32 Deferred property taxes 42 30 Federal tax depreciation normalization adjustment 150 128 Merger capital expense target customer credit 15 10 Other 83 40 Total Non-current Regulatory Assets $ 2,269 $ 2,399
Schedule of Current and Non-Current Regulatory Liabilities	Current and non-current regulatory liabilities as of September 30, 2015 and December 31, 2014 consisted of: September 30, December 31, As of 2015 2014 (Millions) Current Reliability support services (Cayuga) $ 17 $ 18 Plant decommissioning 5 13 Non by-passable charges 18 19 Energy efficiency portfolio standard 39 34 Gas supply charge and deferred natural gas cost 4 6 Revenue reconciliation mechanism transmission revenue true up 15 7 Yankee DOE phase I — 23 Rate refund – FERC ROE proceeding 6 — CMP transmission refund 19 16 Other 7 17 Total Current Regulatory Liabilities 130 153 Non-current Accrued removal obligations 737 721 Asset sale gain account 16 32 Carrying costs on deferred income tax bonus depreciation 107 81 Economic development 34 33 Merger capital expense target customer credit 17 17 Pension and other postretirement benefits cost deferrals 60 50 Positive benefit adjustment 51 51 New York State tax rate change 17 16 Post term amortization 37 20 Theoretical reserve flow thru impact 63 24 Deferred property tax 68 51 Other 147 110 Deferred income taxes regulatory 347 462 Total Non-current Regulatory Liabilities $ 1,701 $ 1,668

Fair Value of Financial Instr23

Fair Value of Financial Instruments and Fair Value Measurements (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Fair Value Measurements	The financial instruments measured at fair value as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 Level 1 Level 2 Level 3 Netting Total (Millions) Securities Portfolio (available for sale) $ 33 $ — $ — $ — $ 33 Financial Assets Derivative financial instruments – power 13 61 71 (31 ) 114 Derivative financial instruments – gas 253 22 68 (217 ) 126 Total 266 83 139 (248 ) 240 Financial Liabilities Derivative financial instruments – power (42 ) (16 ) (13 ) 31 (40 ) Derivative financial instruments – gas (219 ) (39 ) (52 ) 217 (93 ) Derivative financial instruments – other — — (2 ) — (2 ) Total $ (261 ) $ (55 ) $ (67 ) $ 248 $ (135 ) As of December 31, 2014 Level 1 Level 2 Level 3 Netting Total (Millions) Securities Portfolio (available for sale) $ 33 $ — $ — $ — $ 33 Financial Assets Derivative financial instruments – power 11 83 48 (53 ) 89 Derivative financial instruments – gas 18 638 61 (579 ) 138 Total 29 721 109 (632 ) 227 Financial Liabilities Derivative financial instruments – power (40 ) (42 ) (7 ) 53 (36 ) Derivative financial instruments – gas (25 ) (614 ) (42 ) 579 (102 ) Derivative financial instruments – other — — (3 ) — (3 ) Total $ (65 ) $ (656 ) $ (52 ) $ 632 $ (141 )
Fair Value, Financial instrument Based on Level 3 Reconciliation	The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the periods ended September 30, 2015 and 2014 consisted of: Three Months Nine Months (Millions) 2015 2014 2015 2014 Fair Value Beginning of Period, $ 103 $ — $ 57 $ 53 Gains recognized in revenues (4 ) — 38 4 (Losses) recognized in revenues (3 ) 24 (8 ) (34 ) Total gains (losses) recognized in revenues (7 ) 24 30 (30 ) Gains recognized in OCI 4 — 6 — (Losses) recognized in OCI (2 ) (1 ) (2 ) (1 ) Total Gains (Losses) Recognized in OCI 2 (1 ) 4 (1 ) Purchases (22 ) 1 (1 ) 3 Settlements (5 ) (3 ) (12 ) (6 ) Transfers out of Level 3 (a) — (1 ) (7 ) 1 Fair Value as of September 30, $ 71 $ 20 $ 71 $ 20 Gains (losses) for the period included in earnings attributable to the change $ (7 ) $ 24 $ 30 $ (30 ) (a) Transfers out of Level 3 were the result of increased observability of market data.
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 two years), using past and current views of prices for those future periods. As of September 30, 2015 Instruments Instrument Valuation Technique Valuation Inputs Index Variability Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 4.58 $ 7.37 $ 2.69 SP15 ($/MWh) $ 47.03 $ 80.28 $ 23.59 Mid C ($/MWh) $ 38.12 $ 83.93 $ 11.00 Cinergy ($/MWh) $ 37.91 $ 77.49 $ 21.17 As of December 31, 2014 Instruments Instrument Valuation Technique Valuation Inputs Index Variability Avg. Max. Min. Fixed price power and gas swaps with delivery period > two years Transactions with delivery periods exceeding two years Transactions are valued against forward market prices on a discounted basis Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products NYMEX ($/MMBtu) $ 4.33 $ 5.47 $ 3.34 SP15 ($/MWh) $ 43.27 $ 59.12 $ 30.04 Mid C ($/MWh) $ 36.16 $ 56.28 $ 12.62 Cinergy ($/MWh) $ 37.41 $ 68.65 $ 21.17

Derivative Instruments and He24

Derivative Instruments and Hedging (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Notional Volumes of Outstanding Derivative Positions	The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, December 31, (Millions) Wholesale electricity purchase contracts (MWh) 6.9 6.6 Natural gas purchase contracts (Dth) 4.6 3.8 Other fuel purchase contracts (Gallons) 4.1 2.8 The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 December 31, 2014 (MWh/Dth in millions) Wholesale electricity purchase contracts 3 2 Wholesale electricity sales contracts 6 7 Foreign exchange forward purchase contracts 5 — Natural gas and other fuel purchase contracts 309 275 Financial power contracts 8 8 Basis swaps – purchases 82 160 Basis swaps – sales 86 161
Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location and Amount	The location and amounts of derivatives designated as hedging instruments associated with Networks activities as of September 30, 2015 and December 31, 2014 consisted of: Asset Derivatives Liability Derivatives Balance Sheet Fair Balance Sheet Fair (Millions) Location Value Location Value As of September 30, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ (21 ) Non-current Other assets — Other liabilities (9 ) Natural gas derivatives: Current Current assets — Current liabilities (4 ) Other Contracts Current Current assets — Current liabilities (2 ) Total $ — $ (36 ) As of December 31, 2014 Commodity contracts: Electricity derivatives: Current Current assets $ — Current liabilities $ (20 ) Non-current Other assets — Other liabilities (9 ) Natural gas derivatives: Current Current assets — Current liabilities (4 ) Non-current Other assets — Other liabilities (1 ) Other contracts Current assets — Current liabilities (3 ) Total $ — $ (37 ) The location and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of September 30, 2015 (no hedge accounting has been applied in 2014) consisted of: Asset Derivatives Liability Derivatives (Millions) Balance Sheet Location Fair Value Balance Sheet Fair Value As of September 30, 2015 Commodity contracts: Electricity derivatives: Current Current assets $ 3 Current liabilities $ 1 Non-current Other assets 7 Other liabilities — Natural gas derivatives: Current Current assets 21 Current liabilities (3 ) Non-current Other assets 5 Other liabilities (3 ) Total $ 36 $ (5 )
Schedule of Derivative Instruments, Effect of Cashflow Hedging on Other Comprehensive Income and Income	The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, (Loss) Recognized in OCI on Derivatives Location of (Loss) Reclassified from Accumulated OCI into Income (Loss) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2015 Interest rate contracts $ — Interest expense $ (3 ) Commodity contracts: Other (2 ) Operating expenses — Total $ (2 ) $ (3 ) 2014 Interest rate contracts $ — Interest expense $ (3 ) Commodity contracts: Other (1 ) Operating expenses — Total $ (1 ) $ (3 ) Nine Month Period Ended September 30, (Loss) Recognized in OCI on Derivatives Location of (Loss) Reclassified from Accumulated OCI into Income (Loss) Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) 2015 Interest rate contracts $ — Interest expense $ (7 ) Commodity contracts: Other (2 ) Operating expenses (2 ) Total $ (2 ) $ (9 ) 2014 Interest rate contracts $ — Interest expense $ (7 ) Commodity contracts: Other (1 ) Operating expenses — Total $ (1 ) $ (7 ) (a) Changes in OCI are reported on a pre-tax basis. The effect of derivatives in cash flow hedging relationships on OCI and income for the three and nine month periods ended September 30, 2015 (no hedge accounting has been applied in 2014) consisted of: Three Month Period Ended September 30, 2015 Gain Recognized Location of Gain Reclassified from Accumulated OCI into Income Gain Reclassified from Accumulated OCI into Income (Millions) Effective Portion (a) Effective Portion (a) Commodity contracts: Other $ 28 Revenues $ — Total $ 28 $ — (a) Changes in OCI are reported on a pre-tax basis. Nine Month Period Ended September 30, 2015 Gain Recognized Location of Gain Reclassified (Millions) Effective Portion (a) Effective Portion (a) Commodity contracts: Other $ 29 Revenues $ — Total $ 29 $ — (a) Changes in OCI are reported on a pre-tax basis.
Schedule of Offseting of Derivative Assets	The offsetting of derivative assets as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Gross Net Amounts of Assets Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ 13 $ (13 ) $ — $ — $ — $ — December 31, 2014 Derivatives 11 (11 ) — — — — The offsetting of derivative assets as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Gross Net Amounts of Assets Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ 476 $ (236 ) $ 240 $ (45 ) $ (102 ) $ 93 December 31, 2014 Derivatives 847 (620 ) 227 (66 ) (73 ) 88
Schedule of Offseting of Derivative Liabilities	The offsetting of derivative liabilities as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Gross Net Amounts of Liabilities Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ (49 ) $ 13 $ (36 ) $ — $ 36 $ — December 31, 2014 Derivatives (48 ) 11 (37 ) — 37 — The offsetting of derivative liabilities as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Gross Net Amounts of Liabilities Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ (49 ) $ 13 $ (36 ) $ — $ 36 $ — December 31, 2014 Derivatives (48 ) 11 (37 ) — 37 — The offsetting of derivative liabilities as of September 30, 2015 and December 31, 2014 consisted of: As of Gross Amounts Net Amounts of Liabilities Gross Amounts Not Offset in Net Amount Financial Cash (Millions) September 30, 2015 Derivatives $ (335 ) $ 236 $ (99 ) $ 45 $ 7 $ (47 ) December 31, 2014 Derivatives (724 ) 620 (104 ) 66 1 (37 )
Schedule of Fair Value, Net Derivative Contracts	The fair values of derivative contracts associated with Renewables and Gas activities as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 December 31, 2014 (Millions) Wholesale electricity purchase contracts $ (11 ) $ (12 ) Wholesale electricity sales contracts 37 44 Foreign exchange forward purchase contracts (2 ) (3 ) Natural gas and other fuel purchase contracts 39 54 Financial power contracts 77 48 Basis swaps – purchases 7 (4 ) Basis swaps – sales (6 ) (4 ) Total $ 141 $ 123
Effect of Trading and Non-trading Derivatives Associated with Renewables and Gas Activities	The effect of trading and non-trading derivatives associated with Renewables and Gas activities for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Wholesale electricity purchase contracts $ (14 ) $ (7 ) Wholesale electricity sales contracts 32 5 Financial power contracts 5 18 Financial and natural gas contracts 14 10 Total Gain (Loss) $ 37 $ 26 Nine Month Period Ended September 30, 2015 2014 (Millions) Wholesale electricity purchase contracts $ 1 $ (9 ) Wholesale electricity sales contracts (8 ) (7 ) Financial power contracts 19 (7 ) Financial and natural gas contracts (22 ) 79 Total Gain (Loss) $ (10 ) $ 56

Post-retirement and Similar O25

Post-retirement and Similar Obligations (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Components of Net Periodic Pension and Postretirement Benefits	The components of net periodic benefit cost for pension benefits for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 9 $ 8 Interest cost 24 27 Expected return on plan assets (39 ) (41 ) Amortization of: Prior service costs 1 1 Actuarial loss 32 23 Net Periodic Benefit Cost $ 27 $ 18 Nine Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 27 $ 24 Interest cost 72 81 Expected return on plan assets (117 ) (123 ) Amortization of: Prior service costs 3 3 Actuarial loss 96 69 Net Periodic Benefit Cost $ 81 $ 54 The components of net periodic benefit cost for postretirement benefits for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 1 $ 1 Interest cost 4 5 Expected return on plan assets (2 ) (2 ) Amortization of: Prior service costs (2 ) (3 ) Actuarial loss 2 — Net Periodic Benefit Cost $ 3 $ 1 Nine Month Period Ended September 30, 2015 2014 (Millions) Service cost $ 3 $ 3 Interest cost 12 15 Expected return on plan assets (6 ) (6 ) Amortization of: Prior service costs (6 ) (9 ) Actuarial loss 6 — Net Periodic Benefit Cost $ 9 $ 3

Equity (Tables)

Equity (Tables)	9 Months Ended
	Sep. 30, 2015
Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Accumulated OCI for the nine month periods ended September 30, 2015 and 2014 consisted of: Accumulated Other Comprehensive Income (Loss) As of 2014 As of As of 2015 As of September 30, (Millions) Gain (loss) on defined benefit plans, net of income tax expense (benefit) of $0.4 for 2014 and $(1) for 2015 $ (26 ) $ 1 $ (25 ) $ (25 ) $ (2 ) $ (27 ) Gain on nonqualified pension plans , net of income tax expense of $0.4 for 2014 (8 ) 1 (7 ) (11 ) — (11 ) Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, net of income tax expense (benefit) of $(0.4) for 2014 and $11 for 2015 — (1 ) (1 ) (2 ) 17 15 Reclassification to net income of losses on cash flow hedges, net of income tax expense of $2.7 for 2014 and $3.6 for 2015 (a) (66 ) 4 (62 ) (61 ) 5 (56 ) Gain (loss) on derivatives qualified as cash flow hedges (66 ) 3 (63 ) (63 ) 22 (41 ) Accumulated Other Comprehensive (Loss) Income $ (100 ) $ 5 $ (95 ) $ (99 ) $ 20 $ (79 ) Accumulated OCI for the three month periods ended September 30, 2015 and 2014 consisted of: Accumulated Other Comprehensive Income (Loss) As of 2014 As of As of June 30, 2015 2015 As of September (Millions) Gain (loss) on defined benefit plans $ (25 ) $ — $ (25 ) $ (27 ) $ — $ (27 ) Gain on nonqualified pension plans, net of income tax expense of $0.4 for 2014 (8 ) 1 (7 ) (11 ) — (11 ) Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, net of income tax expense (benefit) of $(0.4) for 2014 and $10 for 2015 — (1 ) (1 ) (1 ) 16 15 Reclassification to net income of losses on cash flow hedges, net of income tax benefit of $0.4 for 2014 and $0.4 for 2015 (a) (63 ) 1 (62 ) (57 ) 1 (56 ) Gain (loss) on derivatives qualified as cash flow hedges (63 ) — (63 ) (58 ) 17 (41 ) Accumulated Other Comprehensive (Loss) Income $ (96 ) $ 1 $ (95 ) $ (96 ) $ 17 $ (79 ) (a) Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Net Income Per Share (Tables)

Net Income Per Share (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Earnings Per Share, Basic and Diluted	The calculations of basic and diluted earnings per share attributable to Iberdrola USA, Inc., including a reconciliation of the numerators and denominators for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Months Nine Months Ended September 30, 2015 2014 2015 2014 (Millions, except for number of shares) Numerator: Net income attributable to Iberdrola USA, Inc. $ 54 $ 64 $ 171 $ 327 Denominator: Weighted-average number of shares outstanding, basic and diluted 243 243 243 243 Net Income Per Share, Basic and Diluted $ 0.2 $ 0.3 $ 0.7 $ 1.3

Segment Information (Tables)

Segment Information (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Segment Information	Segment information for the three month period ended September 30, 2015 consisted of: Three Month Period Ended September 30, 2015 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 783 $ 299 $ (34 ) $ — $ 1,048 Revenue - intersegment 7 3 17 (27 ) — Impairment of non-current assets — 3 — — 3 Depreciation and amortization 70 88 5 — 163 Operating income (loss) 154 45 (31 ) (7 ) 161 Adjusted EBITDA 224 136 (26 ) (7 ) 327 Earnings (losses) from equity method investments $ — $ (4 ) $ — $ 1 $ (3 ) (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Segment information for the three month period ended September 2014 consisted of: Three Month Period Ended September 30, 2014 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 752 $ 264 $ (34 ) $ — $ 982 Revenue - intersegment — 3 22 (25 ) — Impairment of non-current assets — 3 — — 3 Depreciation and amortization 70 84 5 — 159 Operating income (loss) 157 25 (29 ) — 153 Adjusted EBITDA 227 112 (24 ) — 315 Earnings (losses) from equity method investments $ (5 ) $ (4 ) $ — $ — $ (9 ) (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Segment information as of and for the nine month period ended September 30, 2015 consisted of: Nine Month Period Ended September 30, 2015 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 2,496 $ 781 $ (63 ) $ — $ 3,214 Revenue - intersegment 23 12 35 (70 ) — Impairment of non-current assets — 10 — — 10 Depreciation and amortization 250 260 14 1 525 Operating income (loss) 443 79 (72 ) (20 ) 430 Adjusted EBITDA 693 349 (58 ) (19 ) 965 Earnings (losses) from equity method investments — (6 ) — 3 (3 ) Capital expenditures $ 484 $ 183 $ 3 $ — $ 670 As of September 30, 2015 Property, plant and equipment 8,608 7,887 534 — 17,029 Equity method investments — 250 — 21 271 Total assets $ 12,929 $ 10,785 $ 1,261 $ (578 ) $ 24,397 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations. Segment information for the nine month period ended September 30, 2014 consisted of: Nine Month Period Ended September 30, 2014 Networks Renewables Gas Other (a) IUSA Consolidated (Millions) Revenue - external $ 2,584 $ 848 $ 38 $ 6 $ 3,476 Revenue – intersegment — 7 52 (59 ) — Impairment of non-current assets — 12 — — 12 Depreciation and amortization 205 248 16 1 470 Operating income 489 169 42 (1 ) 699 Adjusted EBITDA 694 429 58 — 1,181 Earnings (losses) from equity method investments (5 ) 2 — 3 — Capital expenditures $ 667 $ 106 $ 2 $ — $ 775 As of December 31, 2014 Property, plant and equipment 8,389 8,185 525 — 17,099 Equity method investments — 262 — — 262 Total assets $ 12,961 $ 12,329 $ 1,393 $ (2,431 ) $ 24,252 (a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations.
Schedule of Reconciliation of Cosolidated EBITDA to Consolidated Income Before Income Tax	Reconciliation of consolidated Adjusted EBITDA to the IUSA consolidated Income Before Income Tax for the three and nine month periods ended September 30, 2015 and 2014 is as follows: Three Months Ended September 30, Nine Months Ended September 30, (Millions) 2015 2014 2015 2014 Consolidated Adjusted EBITDA $ 327 $ 315 $ 965 $ 1,181 Less: Impairment of non-current assets 3 3 10 12 Depreciation and amortization 163 159 525 470 Interest expense, net of capitalization 64 61 191 178 Add: Other income and (expense) 16 19 38 50 Earnings (losses) from equity method investments (3 ) (9 ) (3 ) — Consolidated Income Before Income Tax $ 110 $ 102 $ 274 $ 571

Related Party Transactions (Tab

Related Party Transactions (Tables)	9 Months Ended
	Sep. 30, 2015
Schedule of Related Party Transactions	Related party transactions for the three and nine month periods ended September 30, 2015 and 2014 consisted of: Three Month Period Ended September 30, 2015 2014 (Millions) Sales Purchases From Sales Purchases From Iberdrola Canada Energy Services, Ltd $ (1 ) $ 14 $ — $ 34 Iberdrola Renovables Energía, S.L. — 2 — 2 Iberdrola, S.A. — 8 — 3 Other (2 ) — (2 ) 1 Nine Month Period Ended September 30, 2015 2014 (Millions) Sales To Purchases From Sales To Purchases From Iberdrola Canada Energy Services, Ltd $ — $ 45 $ — $ 29 Iberdrola Renovables Energía, S.L. — 7 — 7 Iberdrola, S.A. — 26 — 14 Other (2 ) 4 (1 ) 2 Related party balances as of September 30, 2015 and December 31, 2014 consisted of: As of September 30, 2015 December 31, 2014 (Millions) Owed By Owed To Owed By Owed To Iberdrola Canada Energy Services, Ltd. $ 9 $ (5 ) $ 1 $ — Iberdrola, S.A. — (26 ) — — Iberdrola Renovables Energía, S.A.U. — (7 ) — — Gamesa Corporación Tecnológica, S.A. 63 (38 ) 33 (223 ) Other — (2 ) 1 (1 )

Background and Nature Of Oper30

Background and Nature Of Operations - Additional Information (Detail) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2015USD ($)
Nature Of Business [Line Items]
Issuance of share in connection of merger		In connection with the merger, each issued and outstanding share of the common stock of UIL Holdings will be converted into the right to receive one validly issued share of common stock of the newly listed company and $10.50 in cash.
Percentage of ownership	18.50%	18.50%
Merger related expenses	$ 7	$ 19
NEW YORK
Nature Of Business [Line Items]
Incorporation date of organization		Jan. 1, 1997

Regulatory Assets and Liabili31

Regulatory Assets and Liabilities - Additional Information (Detail) $ in Millions	9 Months Ended
	Sep. 30, 2015USD ($)
Regulatory Assets And Liabiliaties [Line Items]
Unrecorded Regulatory Assets	$ 1,824
NEW YORK | Prior Tax Rate [Member]
Regulatory Assets And Liabiliaties [Line Items]
Statutory income tax rate, state	7.10%
NEW YORK | Revised Tax Rate [Member]
Regulatory Assets And Liabiliaties [Line Items]
Statutory income tax rate, state	6.50%

Regulatory Assets and Liabili32

Regulatory Assets and Liabilities - Current and Non-Current Assets (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Regulatory Assets [Line Items]
Regulatory Assets, current	$ 114	$ 80
Deferred income taxes regulatory	7	29
Regulatory Assets, current	121	109
Regulatory Assets, noncurrent	2,269	2,399
Environmental Restoration Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, current	34
Regulatory Assets, noncurrent	171	247
Pension And Other Post Retirement Benefits Deferrals [Member]
Regulatory Assets [Line Items]
Regulatory Assets, current	10
Regulatory Assets, noncurrent	145	125
Storm Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, current	11	14
Regulatory Assets, noncurrent	251	259
Temporary Supplemental Assessment Surcharge [Member]
Regulatory Assets [Line Items]
Regulatory Assets, current	6	12
Hedges Loss [Member]
Regulatory Assets [Line Items]
Regulatory Assets, current	25	34
Other [Member]
Regulatory Assets [Line Items]
Regulatory Assets, current	28	20
Regulatory Assets, noncurrent	83	40
Pension and Other Postretirement Plans Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	976	1,101
Deferred Meter Replacement Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	35	36
Unamortized Loss On Reacquired Debt [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	23	25
Future Income Tax [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	341	366
Asset Retirement Obligation Costs [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	37	32
Deferred Property Tax Asset [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	42	30
Federal Tax Depreciation Normalization Adjustment [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	150	128
Merger Capital Expense [Member]
Regulatory Assets [Line Items]
Regulatory Assets, noncurrent	$ 15	$ 10

Regulatory Assets and Liabili33

Regulatory Assets and Liabilities - Current and Non-Current Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	$ 130	$ 153
Deferred income taxes regulatory	347	462
Regulatory liabilities, noncurrent	1,354	1,206
Regulatory liabilities, noncurrent	1,701	1,668
Support Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	17	18
Plant Decommissioning [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	5	13
Non By Passable Charge [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	18	19
Energy Efficiency Services [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	39	34
Gas Supply Charge And Deferred Natural Gas Cost [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	4	6
Revenue Reconciliation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	15	7
Yankee DOE Phase One [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current		23
Rate Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	6
CMP Transmission Refund [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	19	16
Other Regulatory Assets (Liabilities)
Regulatory Liabilities [Line Items]
Regulatory liabilities, current	7	17
Regulatory liabilities, noncurrent	147	110
Removal Costs [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	737	721
Asset Sale [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	16	32
Deferred Income Tax Bonus Depreciation [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	107	81
Economic Development [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	34	33
Merger Capital Expense [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	17	17
Pension and Other Post Retirement Benefits Deferrals, Liabilities [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	60	50
Positive Benefit Adjustment [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	51	51
New York State Income Tax Rate Change [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	17	16
Post Term Amortization [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	37	20
Flow Thru Impact [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	63	24
Deferred Property Tax Asset [Member]
Regulatory Liabilities [Line Items]
Regulatory liabilities, noncurrent	$ 68	$ 51

Fair Value of Financial Instr34

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	$ 240	$ 227
Derivative financial instruments, liabilities	(135)	(141)
Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	266	29
Derivative financial instruments, liabilities	(261)	(65)
Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	83	721
Derivative financial instruments, liabilities	(55)	(656)
Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	139	109
Derivative financial instruments, liabilities	(67)	(52)
Available-for-sale Securities [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Securities Portfolio (available for sale)	33	33
Available-for-sale Securities [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Securities Portfolio (available for sale)	33	33
Derivative Financial Instrument Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	114	89
Derivative financial instruments, liabilities	(40)	(36)
Derivative Financial Instrument Power [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	13	11
Derivative financial instruments, liabilities	(42)	(40)
Derivative Financial Instrument Power [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	61	83
Derivative financial instruments, liabilities	(16)	(42)
Derivative Financial Instrument Power [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	71	48
Derivative financial instruments, liabilities	(13)	(7)
Derivative Financial Instrument Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	126	138
Derivative financial instruments, liabilities	(93)	(102)
Derivative Financial Instrument Gas [Member] | Fair Value, Inputs, Level 1 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	253	18
Derivative financial instruments, liabilities	(219)	(25)
Derivative Financial Instrument Gas [Member] | Fair Value, Inputs, Level 2 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	22	638
Derivative financial instruments, liabilities	(39)	(614)
Derivative Financial Instrument Gas [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	68	61
Derivative financial instruments, liabilities	(52)	(42)
Derivative Financial Instrument Other [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	(2)	(3)
Derivative Financial Instrument Other [Member] | Fair Value, Inputs, Level 3 [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, liabilities	(2)	(3)
Netting [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(248)	(632)
Derivative financial instruments, liabilities	248	632
Netting [Member] | Derivative Financial Instrument Power [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(31)	(53)
Derivative financial instruments, liabilities	31	53
Netting [Member] | Derivative Financial Instrument Gas [Member]
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative financial instruments, assets	(217)	(579)
Derivative financial instruments, liabilities	$ 217	$ 579

Fair Value of Financial Instr35

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Detail) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Fair Value as of January 1,		$ 103		$ 57	$ 53
Total gains or losses for the period recognized in revenues		(7)	$ 24	30	(30)
Total Gains or Losses Recognized in OCI		2	(1)	4	(1)
Purchases		(22)	1	(1)	3
Settlements		(5)	(3)	(12)	(6)
Transfers out of Level 3	[1]		(1)	(7)	1
Fair Value as of September 30,		71	20	71	20
Gains (losses) for the period included in earnings attributable to the change in unrealized gains (losses) relating to financial instruments still held at the reporting date		(7)	24	30	(30)
Gains Included In Earnings [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total gains or losses for the period recognized in revenues		(4)		38	4
Losses Included In Earnings [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total gains or losses for the period recognized in revenues		(3)	24	(8)	(34)
Gains Included In OCI [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total Gains or Losses Recognized in OCI		4		6
Losses Included In OCI [Member]
Fair Value, Assets Measured on Recurring Basis, Unobservable Input Reconciliation [Line Items]
Total Gains or Losses Recognized in OCI		$ (2)	$ (1)	$ (2)	$ (1)
[1]	Transfers out of Level 3 were the result of increased observability of market data.

Fair Value of Financial Instr36

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2015$ / MMBTU$ / MWh	Dec. 31, 2014$ / MMBTU$ / MWh
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Instruments	Fixed price power and gas swaps with delivery period two years	Fixed price power and gas swaps with delivery period two years
Instrument Description	Transactions with delivery periods exceeding two years	Transactions with delivery periods exceeding two years
Valuation Technique	Transactions are valued against forward market prices on a discounted basis	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	Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products
SP15 [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Index	SP15 ($/MWh)	SP15 ($/MWh)
Mid C [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Index	Mid C ($/MWh)	Mid C ($/MWh)
Cinergy [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Index	Cinergy ($/MWh)	Cinergy ($/MWh)
CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Index	NYMEX ($/MMBtu)	NYMEX ($/MMBtu)
Weighted Average [Member] | SP15 [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	47.03	43.27
Weighted Average [Member] | Mid C [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	38.12	36.16
Weighted Average [Member] | Cinergy [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	37.91	37.41
Weighted Average [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability | $ / MMBTU	4.58	4.33
Maximum [Member] | SP15 [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	80.28	59.12
Maximum [Member] | Mid C [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	83.93	56.28
Maximum [Member] | Cinergy [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	77.49	68.65
Maximum [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability | $ / MMBTU	7.37	5.47
Minimum [Member] | SP15 [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	23.59	30.04
Minimum [Member] | Mid C [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	11	12.62
Minimum [Member] | Cinergy [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability	21.17	21.17
Minimum [Member] | CME SWAPS MARKETS (NYMEX) [Member]
Fair Value Measurements, Recurring and Nonrecurring, Valuation Techniques [Line Items]
Variability | $ / MMBTU	2.69	3.34

Fair Value of Financial Instr37

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Detail) - USD ($)	Sep. 30, 2015	Dec. 31, 2014
Fair Value, Net Asset (Liability) [Abstract]
Fair value of debt	$ 3,193	$ 2,962

Derivative Instruments and He38

Derivative Instruments and Hedging - Additional Information (Detail) - USD ($)		3 Months Ended				9 Months Ended		12 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2016	Dec. 31, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets						$ (99,000,000)	$ (132,000,000)			$ 29,900,000
Reclassification to net income of losses on cash flow hedges	[1]	$ 1,000,000		$ 1,000,000		5,000,000	4,000,000
Gross Amounts of Recognized Liabilities		(135,000,000)				(135,000,000)				(141,000,000)
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges		(2,000,000)	[2]	(1,000,000)	[2]	(2,000,000)	(1,000,000)
Gross Amounts of Recognized Liabilities		36,000,000				36,000,000				37,000,000
Cash Collateral Pledged		36,000,000				36,000,000				37,000,000
Network [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net derivative losses related to discontinued cash flow hedges		(2,200,000)		(2,300,000)		(6,500,000)	(6,900,000)
Ineffective portion of Cash flow hedge		0		0		0	0
Unrealized gain(loss) from hedging activities reported on OCI						$ (2,500,000)
Derivative instruments, gain (loss) reclassification from accumulated OCI to income, estimate of time to transfer						12 months
Network [Member] | Cash Flow Hedging [Member] | Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Reclassification to net income of losses on cash flow hedges									$ (8,700,000)
Derivative Instruments Gain Loss To Be Reclassified From Accumulated Oci Into Interest Expense During Next Twelve Months								$ (1,700,000)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) reclassified from regulatory assets and liabilities into income		37,000,000		26,000,000		$ (10,000,000)	56,000,000
Ineffective portion of Cash flow hedge		2,100,000				1,800,000
Cash Collateral Pledged		102,000,000				102,000,000				73,000,000
Gross Amounts of Recognized Liabilities		5,000,000				5,000,000
Cash Collateral Pledged		7,000,000				7,000,000				1,000,000
Renewables and Gas Activities [Member] | Cash Flow Hedging [Member] | Scenario, Forecast [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gain(loss) from hedging activities reported on OCI								$ 18,900,000
Counter Party [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash Collateral Pledged		100,000				100,000				$ 200,000
Gross Amounts of Recognized Liabilities		36,500,000				36,500,000
Financial Instruments		53,000,000				53,000,000
Cash Collateral Pledged		16,500,000				16,500,000
Electricity Derivatives [Member] | Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets						(30,200,000)	17,900,000
Gain (Loss) reclassified from regulatory assets and liabilities into income		(14,800,000)		(8,900,000)		(27,100,000)	34,700,000
forward starting swaps [Member] | Network [Member] | Cash Flow Hedging [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps		(93,500,000)		(102,300,000)		$ (93,500,000)	(102,300,000)
Fuel Derivatives [Member] | Network [Member] | Cash Flow Hedging [Member] | Maximum [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges						27 months
Natural Gas Hedges [Member] | Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) recognized in regulatory assets						$ (3,900,000)	(400,000)
Gain (Loss) reclassified from regulatory assets and liabilities into income		$ 0		$ 0		$ (3,400,000)	$ 2,300,000
[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.

Derivative Instruments and He39

Derivative Instruments and Hedging - Net Notional Volume (Detail)	9 Months Ended	12 Months Ended
	Sep. 30, 2015DTHgalMWh	Dec. 31, 2014DTHgalMWh
Network [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure | MWh	6,900,000	6,600,000
Network [Member] | Natural Gas Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure	4,600,000	3,800,000
Network [Member] | Other Fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure | gal	4,100,000	2,800,000
Renewables and Gas Activities [Member] | Long [Member] | Foreign Exchange Forward [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure | MWh	5,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure | MWh	3,000,000	2,000,000
Renewables and Gas Activities [Member] | Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure | MWh	6,000,000	7,000,000
Renewables and Gas Activities [Member] | Natural Gas and Other fuel Contracts [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure	309,000,000	275,000,000
Renewables and Gas Activities [Member] | Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure	8,000,000	8,000,000
Renewables and Gas Activities [Member] | Basis Swap [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure	82,000,000	160,000,000
Renewables and Gas Activities [Member] | Basis Swap [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount, energy measure	86,000,000	161,000,000

Derivative Instruments and He40

Derivative Instruments and Hedging - Locations and Amounts of Derivatives Designated as Hedging (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	$ 135	$ 141
Asset derivatives, fair value	240	227
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(36)	(37)
Network [Member] | Commodity Contract [Member] | Electricity derivatives [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(21)	(20)
Network [Member] | Commodity Contract [Member] | Electricity derivatives [Member] | Other liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(9)	(9)
Network [Member] | Commodity Contract [Member] | Natural Gas Derivatives [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(4)	(4)
Network [Member] | Commodity Contract [Member] | Natural Gas Derivatives [Member] | Other liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value		(1)
Network [Member] | Other Contract [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(2)	$ (3)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(5)
Asset derivatives, fair value	36
Renewables and Gas Activities [Member] | Commodity Contract [Member] | Electricity derivatives [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	1
Renewables and Gas Activities [Member] | Commodity Contract [Member] | Electricity derivatives [Member] | Current assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Asset derivatives, fair value	3
Renewables and Gas Activities [Member] | Commodity Contract [Member] | Electricity derivatives [Member] | Other assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Asset derivatives, fair value	7
Renewables and Gas Activities [Member] | Commodity Contract [Member] | Natural Gas Derivatives [Member] | Current liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(3)
Renewables and Gas Activities [Member] | Commodity Contract [Member] | Natural Gas Derivatives [Member] | Other liabilities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Liability derivatives, fair value	(3)
Renewables and Gas Activities [Member] | Commodity Contract [Member] | Natural Gas Derivatives [Member] | Current assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Asset derivatives, fair value	21
Renewables and Gas Activities [Member] | Commodity Contract [Member] | Natural Gas Derivatives [Member] | Other assets [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Asset derivatives, fair value	$ 5

Derivative Instruments and He41

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Detail) - USD ($) $ in Millions		3 Months Ended				9 Months Ended
		Sep. 30, 2015		Sep. 30, 2014		Sep. 30, 2015	Sep. 30, 2014
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion		$ (2)	[1]	$ (1)	[1]	$ (2)	$ (1)
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[1]	(3)		(3)		(9)	(7)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Recognized in OCI Derivatives Effective Portion	[2]	28				29
Gain Reclassified from Accumulated OCI Income Effective Portion	[2]	0				0
Interest Rate Contract [Member] | Network [Member] | Interest expense [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[1]	(3)		(3)		(7)	(7)
Commodity Contract [Member] | Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Recognized in OCI Derivatives Effective Portion		(2)	[1]	$ (1)	[1]	(2)	$ (1)
Commodity Contract [Member] | Network [Member] | Operating expenses [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Reclassified from Accumulated OCI Income Effective Portion	[1]					(2)
Commodity Contract [Member] | Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Recognized in OCI Derivatives Effective Portion	[2]	28				29
Commodity Contract [Member] | Renewables and Gas Activities [Member] | Revenue [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain Reclassified from Accumulated OCI Income Effective Portion	[2]	$ 0				$ 0
[1]	Changes in OCI are reported on a pre-tax basis.
[2]	Changes in OCI are reporting on a pre-tax basis.

Derivative Instruments and He42

Derivative Instruments and Hedging - Offsetting Derivative Assets (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Assets	$ 13	$ 11
Gross Amounts Offset in the Balance Sheet	(13)	(11)
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Assets	476	847
Gross Amounts Offset in the Balance Sheet	(236)	(620)
Net Amounts of Assets Presented in the Balance Sheet	240	227
Financial Instruments	(45)	(66)
Cash Collateral Pledged	(102)	(73)
Net Amount	$ 93	$ 88

Derivative Instruments and He43

Derivative Instruments and Hedging - Offsetting Derivative Liabilities (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Network [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities	$ (49)	$ (48)
Gross Amounts Offset in the Balance Sheet	13	11
Net Amounts of Liabilities Presented in the Balance Sheet	(36)	(37)
Cash Collateral Pledged	36	37
Renewables and Gas Activities [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gross Amounts of Recognized Liabilities	(335)	(724)
Gross Amounts Offset in the Balance Sheet	236	620
Net Amounts of Liabilities Presented in the Balance Sheet	(99)	(104)
Financial Instruments	45	66
Cash Collateral Pledged	7	1
Net Amount	$ (47)	$ (37)

Derivative Instruments and He44

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ 141	$ 123
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	77	48
Long [Member] | Foreign Exchange Forward [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(2)	(3)
Long [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	(11)	(12)
Long [Member] | Natural Gas and Other fuel Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	39	54
Long [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	7	(4)
Short [Member] | Wholesale Electricity Contract [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	37	44
Short [Member] | Basis Swap [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Fair Value, Net	$ (6)	$ (4)

Derivative Instruments and He45

Derivative Instruments and Hedging - Effect of Trading and Non-Trading Derivatives (Detail) - Renewables and Gas Activities [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	$ 37	$ 26	$ (10)	$ 56
Wholesale Electricity Contract [Member] | Long [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	(14)	(7)	1	(9)
Wholesale Electricity Contract [Member] | Short [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	32	5	(8)	(7)
Financial Power Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	5	18	19	(7)
Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net	$ 14	$ 10
Financial and Natural Gas Contracts [Member]
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (Loss) on Derivative, Net			$ (22)	$ 79

Contingencies - Additional Info

Contingencies - Additional Information (Detail) - USD ($) $ in Millions	Jan. 01, 2020	Jan. 01, 2019	Jan. 01, 2018	Jan. 01, 2017	Jan. 01, 2016	Nov. 06, 2015	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Dec. 31, 2015	Dec. 31, 2013
Loss Contingencies [Line Items]
Approved Return on Equity, Percentage							10.57%
Requested Return on Equity, Percentage							9.20%
Disclosure of Rate Matters							In September 2011 the Massachusetts Attorney General filed a complaint with the FERC that the ROE was too high and should be lowered by 1.94%, to a value of 9.2%.
Long-term Growth Rate							4.39%
Regulatory liabilities							$ 1,354		$ 1,206
Increase (decrease) in regulatory assets/liabilities							$ (99)	$ (132)	$ 29.9
Subsequent Event [Member]
Loss Contingencies [Line Items]
Requested Return on Equity, Percentage						9.55%
Additional gross plant investment						$ 10
Additional gross plant investment disallowance period						3 years
Gross plant investment disallowance subject to sales throughput targets						$ 7.8
Equity allowance, percentage						50.00%
Scenario, Forecast [Member]
Loss Contingencies [Line Items]
Increase (decrease) in distribution rates	(2.80%)	(6.00%)	17.40%	17.40%	17.40%
One-time gross plant investment disallowance										$ 6
Maximum [Member]
Loss Contingencies [Line Items]
Approved Return on Equity, Percentage							11.74%
Complaint One [Member]
Loss Contingencies [Line Items]
Regulatory liabilities											$ 6.6
Unfavorable Regulatory Action [Member] | Complaint One [Member]
Loss Contingencies [Line Items]
Requested Return on Equity, Percentage							1.94%
Before Amendment [Member]
Loss Contingencies [Line Items]
Approved Return on Equity, Percentage							11.14%

Environmental Liabilities - Add

Environmental Liabilities - Additional Information (Detail) $ in Millions	Sep. 11, 2014USD ($)site	Aug. 14, 2013USD ($)Location	Sep. 30, 2011USD ($)	Oct. 31, 2015USD ($)	Jul. 31, 2011USD ($)	Sep. 30, 2015USD ($)site	Dec. 31, 2014USD ($)
Environmental Exit Cost [Line Items]
Number of hazardous waste sites for which we have been notified of being potentially responsible | site						23
Sites where gas was manufactured in the past | site						53
Number of sites for which we have entered into consent orders to investigate, and where necessary remediate | site						47
Total liability to investigate and perform remediation						$ 311	$ 319
First Energy [Member]
Environmental Exit Cost [Line Items]
Amount that would be required to be paid based on past and future cleanup costs					$ 60
Number of sites to clean up | site						19
Environmental costs paid			$ 30
Number of sites with modified decision | site	9
Damages for incurred costs payment amount	$ 22
Refund of environmental remediation cost paid	$ 5
Accrual for environmental loss contingencies						$ 27
Future costs that have been recorded as a receivable						$ 16
First Energy [Member] | Subsequent Event [Member]
Environmental Exit Cost [Line Items]
Environmental loss undisputed, payment				$ 12.9
First Energy [Member] | Past Costs [Member]
Environmental Exit Cost [Line Items]
Environmental costs paid			27
First Energy [Member] | Pre-judgment Interest [Member]
Environmental Exit Cost [Line Items]
Environmental costs paid			$ 3
Century Indemnity and OneBeacon [Member]
Environmental Exit Cost [Line Items]
Amount that would be required to be paid based on past and future cleanup costs		$ 89
Number of hazardous waste sites | Location		22
Estimated clean-up costs		$ 282
Legal discovery process expected closing year description						The legal discovery process is expected to close in early 2016.

Post-Retirement and Similar O48

Post-Retirement and Similar Obligations - Additional Information (Detail) - USD ($) $ in Millions	3 Months Ended	9 Months Ended
	Sep. 30, 2015	Sep. 30, 2015
Defined Benefit Plan Disclosure [Line Items]
Defined benefit, pension contributions	$ 10.5	$ 10.9

Post-Retirement and Similar O49

Post-Retirement and Similar Obligations - Net Periodic Benefit Costs (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Pension Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 9	$ 8	$ 27	$ 24
Interest cost	24	27	72	81
Expected return on plan assets	(39)	(41)	(117)	(123)
Prior service costs	1	1	3	3
Actuarial loss	32	23	96	69
Net Periodic Benefit Cost	27	18	81	54
Other Postretirement Benefit Plan [Member]
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1	3	3
Interest cost	4	5	12	15
Expected return on plan assets	(2)	(2)	(6)	(6)
Prior service costs	(2)	(3)	(6)	(9)
Actuarial loss	2		6
Net Periodic Benefit Cost	$ 3	$ 1	$ 9	$ 3

Equity - Additional Information

Equity - Additional Information (Detail) - USD ($) $ / shares in Units, $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Stockholder's Equity:
Common stock, authorized	243	243
Common stock, outstanding	243	243
Common stock, par value	$ 0.01	$ 0.01
Additional paid in capital	$ 11,378	$ 11,378
Treasury stock, shares	0	0
Convertible preferred stock, shares outstanding	0	0

Equity - Accumulated Other Comp

Equity - Accumulated Other Comprehensive Income (Loss) (Detail) - USD ($) $ in Millions		3 Months Ended		6 Months Ended	9 Months Ended		12 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Jun. 30, 2015	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014	Jun. 30, 2014	Dec. 31, 2013
Accumulated Other Comprehensive Income (Loss) [Line Items]
Gain (loss) on derivatives qualified as cash flow hedges		$ (41)	$ (63)	$ (58)	$ (41)	$ (63)	$ (63)	$ (63)	$ (66)
Accumulated Other Comprehensive (Loss) Income		(79)	(95)	(96)	(79)	(95)	(99)	(96)	(100)
Gain (loss) on defined benefit plans			1		(2)	2
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, net of income tax expense(benefit) of $(0.4) for 2014 and $10 for 2015		16	(1)		17	(1)
Reclassification to net income of losses on cash flow hedges, net of income tax benefit of $0.4 for 2014 and $0.4 for 2015	[1]	1	1		5	4
Gain (loss) on derivatives qualified as cash flow hedges		17			22	3
Other Comprehensive Income, Net of Tax		17	1		20	5
Designated as Hedging Instrument [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, net of income tax expense(benefit) of $(0.4) for 2014 and $10 for 2015				(1)	15	(1)	(2)
Reclassification out of Accumulated Other Comprehensive Income [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Gain (loss) on derivatives qualified as cash flow hedges	[1]	(56)	(62)	(57)	(56)	(62)	(61)	(63)	(66)
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Gain (loss) on defined benefit plans		(27)	(25)	(27)	(27)	(25)	(25)	(25)	(26)
Gain (loss) on defined benefit plans					(2)	1
Non Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Gain (loss) on defined benefit plans		$ (11)	(7)	$ (11)	$ (11)	(7)	$ (11)	$ (8)	$ (8)
Gain (loss) on defined benefit plans			$ 1			$ 1
[1]	Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Equity - Accumulated Other Co52

Equity - Accumulated Other Comprehensive Income (Loss) (Parenthetical) (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Accumulated Other Comprehensive Income (Loss) [Line Items]
Unrealized gain (loss) during period on derivatives qualified as cash flow hedges, income tax expense(benefit)	$ 10	$ (0.4)	$ 11	$ (0.4)
Reclassification to net income of losses on cash flow hedges, income tax expense	$ 0.4	0.4	3.6	2.7
Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Gain(loss) on defined benefit plans, income tax expense (benefit)			$ (1)	0.4
Non Qualified Pension Plan [Member]
Accumulated Other Comprehensive Income (Loss) [Line Items]
Gain(loss) on defined benefit plans, income tax expense (benefit)		$ 0.4		$ 0.4

Net Income per Share - Basic an

Net Income per Share - Basic and Diluted (Detail) - USD ($) $ / shares in Units, $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Numerator:
Net income attributable to Iberdrola USA, Inc.	$ 54	$ 64	$ 171	$ 327
Denominator:
Weighted-average number of shares outstanding, basic and diluted	243	243	243	243
Net Income Per Share, Basic and Diluted	$ 0.2	$ 0.3	$ 0.7	$ 1.3

Segment Information - Additiona

Segment Information - Additional Information (Detail) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015USD ($)	Sep. 30, 2014USD ($)	Sep. 30, 2015USD ($)Segment	Sep. 30, 2014USD ($)
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			3
Operating Revenues	$ 1,048	$ 982	$ 3,214	$ 3,476
Regulated Electric Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	705	668	2,031	2,080
Regulated Gas Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	80	83	462	502
Other Networks [Member]
Segment Reporting Information [Line Items]
Operating Revenues	(2)	1	3	2
Renewable Energy Generation Of Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues	299	264	781	848
Gas Storage Services [Member]
Segment Reporting Information [Line Items]
Operating Revenues	3	0	9	5
Gas Trading Operations [Member]
Segment Reporting Information [Line Items]
Operating Revenues	$ (37)	$ (34)	$ (72)	$ 33
Network [Member]
Segment Reporting Information [Line Items]
Number of reportable segments | Segment			1
Number of operating segments | Segment			4

Segment information (Detail)

Segment information (Detail) - USD ($) $ in Millions		3 Months Ended		9 Months Ended
		Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Segment Reporting Information [Line Items]
Operating Revenues		$ 1,048	$ 982	$ 3,214	$ 3,476
Impairment of non-current assets		3	3	10	12
Depreciation and amortization		163	159	525	470
Operating income		161	153	430	699
Adjusted EBITDA		327	315	965	1,181
Earnings (losses) from equity method investments		(3)	(9)	(3)
Capital expenditures				670	775
Property, plant and equipment		17,029	17,099	17,029	17,099	$ 17,099
Equity method investments		271	262	271	262	262
Total assets		24,397	24,252	24,397	24,252	$ 24,252
Network [Member]
Segment Reporting Information [Line Items]
Operating Revenues		783	752	2,496	2,584
Depreciation and amortization		70	70	250	205
Operating income		154	157	443	489
Adjusted EBITDA		224	227	693	694
Earnings (losses) from equity method investments			(5)		(5)
Capital expenditures				484	667
Property, plant and equipment		8,608	8,389	8,608	8,389
Total assets		12,929	12,961	12,929	12,961
Network [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Operating Revenues		7		23
Renewables [Member]
Segment Reporting Information [Line Items]
Operating Revenues		299	264	781	848
Impairment of non-current assets		3	3	10	12
Depreciation and amortization		88	84	260	248
Operating income		45	25	79	169
Adjusted EBITDA		136	112	349	429
Earnings (losses) from equity method investments		(4)	(4)	(6)	2
Capital expenditures				183	106
Property, plant and equipment		7,887	8,185	7,887	8,185
Equity method investments		250	262	250	262
Total assets		10,785	12,329	10,785	12,329
Renewables [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Operating Revenues		3	3	12	7
Gas [Member]
Segment Reporting Information [Line Items]
Operating Revenues		(34)	(34)	(63)	38
Depreciation and amortization		5	5	14	16
Operating income		(31)	(29)	(72)	42
Adjusted EBITDA		(26)	(24)	(58)	58
Capital expenditures				3	2
Property, plant and equipment		534	525	534	525
Total assets		1,261	1,393	1,261	1,393
Gas [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Operating Revenues		17	22	35	52
Other Segments [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]				6
Depreciation and amortization	[1]			1	1
Operating income	[1]	(7)		(20)	(1)
Adjusted EBITDA	[1]	(7)		(19)	0
Earnings (losses) from equity method investments	[1]	1		3	3
Equity method investments	[1]	21		21
Total assets	[1]	(578)	(2,431)	(578)	(2,431)
Other Segments [Member] | Intersegment [Member]
Segment Reporting Information [Line Items]
Operating Revenues	[1]	$ (27)	$ (25)	$ (70)	$ (59)
[1]	Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

Segment information - Reconcili

Segment information - Reconciliation of Adjusted EBITDA to Income Before Income Taxes (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Segment Reporting Information [Line Items]
Consolidated Adjusted EBITDA	$ 327	$ 315	$ 965	$ 1,181
Impairment of non-current assets	3	3	10	12
Depreciation and amortization	163	159	525	470
Interest expense, net of capitalization	64	61	191	178
Other income and (expense)	16	19	38	50
Earnings (losses) from equity method investments	(3)	(9)	(3)
Consolidated Income Before Income Tax	$ 110	$ 102	$ 274	$ 571

Related Party Transactions (Det

Related Party Transactions (Detail) - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014
Iberdrola Canada Energy Services Ltd [Member]
Related Party Transaction [Line Items]
2014 Sales To	$ (1)
Purchases From	14	$ 34	$ 45	$ 29
Iberdrola Renovables Energia, S.L. [Member]
Related Party Transaction [Line Items]
Purchases From	2	2	7	7
Iberdrola SA [Member]
Related Party Transaction [Line Items]
Purchases From	8	3	26	14
Other Related Parties [Member]
Related Party Transaction [Line Items]
2014 Sales To	$ (2)	(2)	(2)	(1)
Purchases From		$ 1	$ 4	$ 2

Related Party Transactions - Ad

Related Party Transactions - Additional Information (Detail) - USD ($)	3 Months Ended		9 Months Ended		12 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Related Party Transaction [Line Items]
Impairments	$ 3,000,000	$ 3,000,000	$ 10,000,000	$ 12,000,000
Affiliated Entity [Member] | Impairment of non-current assets [Member]
Related Party Transaction [Line Items]
Receivable from related party, write-off			10,000,000
Impairments			$ 0
Iberdrola SA [Member] | Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Business combination, equity interest percentage	20.00%		20.00%
Iberdrola SA [Member] | Gamesa Corporacion Tecnologica, S.A. [Member] | Business Combinations [Member]
Related Party Transaction [Line Items]
Related party transaction, amount			$ 72,000,000		$ 226,000,000

Related Party Balances (Detail)

Related Party Balances (Detail) - USD ($) $ in Millions	Sep. 30, 2015	Dec. 31, 2014
Iberdrola Canada Energy Services Ltd [Member]
Related Party Transaction [Line Items]
Owed By	$ 9	$ 1
Owed To	(5)
Iberdrola SA [Member]
Related Party Transaction [Line Items]
Owed To	(26)
Iberdrola Renovables Energia SL [Member]
Related Party Transaction [Line Items]
Owed To	(7)
Gamesa Corporacion Tecnologica, S.A. [Member]
Related Party Transaction [Line Items]
Owed By	63	33
Owed To	(38)	(223)
Other Related Parties [Member]
Related Party Transaction [Line Items]
Owed By		1
Owed To	$ (2)	$ (1)

Accounts Receivable - Additiona

Accounts Receivable - Additional Information (Detail) - DPA [Member] - USD ($) $ in Millions	3 Months Ended		9 Months Ended
	Sep. 30, 2015	Sep. 30, 2014	Sep. 30, 2015	Sep. 30, 2014	Dec. 31, 2014
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for doubtful accounts, deferred payment arrangement	$ 37		$ 37		$ 35
Provision for doubtful accounts, accounts receivable	5		1	$ 6
Provision for doubtful accounts, accounts receivable		$ (7)
Accounts receivable, net	$ 27.4		$ 27.4		$ 40.1