Avangrid, Inc. - Quarter Report: 2015 September (Form 10-Q)

Large accelerated filer

Accelerated filer

Non-accelerated filer

x (Do not check if a smaller reporting company)

Smaller reporting company

Form 10-Q

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-Q

x	QUARTERLY REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the quarterly period ended September 30, 2015

¨	TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934

For the transition period from to

Commission File No. 001-37660

LOGO

Iberdrola USA, Inc.

(Exact name of registrant as specified in this charter)


New York		14-1798693
(State of Incorporation)		(I.R.S. Employer Identification No.)

Durham Hall, 52 Farm View Drive, New Gloucester, Maine		04260
(Address of principal executive offices)		(Zip Code)

Telephone: (207) 688-6363

(Registrant’s telephone number, including area code)

Not Applicable

(Former Address)

Indicate by check mark whether the registrant (1) has filed all reports required to be filed by Section 13 or 15(d) of the Securities Exchange Act of 1934 during the preceding 12 months (or for such shorter period that the registrant was required to file such reports), and (2) has been subject to such filing requirements for the past 90 days. Yes ¨ No x

Indicate by check mark whether the registrant has submitted electronically and posted on its corporate Website, if any, every Interactive Data File required to be submitted and posted pursuant to Rule 405 of Regulation S-T during the preceding 12 months (or for such shorter period that the registrant was required to submit and post such files). Yes x No ¨

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, or a smaller reporting company. See definitions of “large accelerated filer,” “accelerated filer,” and “smaller reporting company” in Rule 12b-2 of the Exchange Act. (Check one):

Indicate by check mark whether the registrant is a shell company (as defined in Rule 12b-2 of the Exchange Act). Yes ¨ No x

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 252,235,232 shares of common stock, par value $0.01, were outstanding as of December 15, 2015.

IBERDROLA USA, INC.

REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2015

INDEX


			Page
GLOSSARY OF TERMS AND ABBREVIATIONS			ii
PART I. FINANCIAL INFORMATION			1
Item 1. Financial Statements			1
Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations			32
Item 3. Quantitative and Qualitative Disclosures about Market Risk			48
Item 4. Controls and Procedures			49
PART II. OTHER INFORMATION			50
Item 1. Legal Proceedings			50
Item 1A. Risk Factors			50
Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.			69
Item 3. Defaults Upon Senior Securities.			69
Item 4. Mine Safety Disclosures.			69
Item 5. Other Information.			69
Item 6. Exhibits			69
SIGNATURES			70

(i)

GLOSSARY OF TERMS AND ABBREVIATIONS

As used in this report for the quarter ended September 30, 2015, the abbreviations contained herein have the meanings set forth below.


2011 Act		Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011

Bcf		One billion cubic feet

BGEPA		Bald and Golden Eagle Protection Act

BMG		Bank Mendes Gans, N.V.

CCO		Chief Corporate Officer

CFO		Chief Financial Officer

CFTC		Commodity Futures Trading Commission

CMP		Central Maine Power Company

DER		Distributed energy resources

Dodd-Frank Act		Dodd-Frank Wall Street Reform and Consumer Protection Act

DOE		Department of Energy

DOJ		Department of Justice

DOT		Department of Transportation

DSP		Distributed System Platform

EBITDA		Earnings before interest, taxes, depreciation and amortization

EPA		Environmental Protection Agency

EPAct 2005		Energy Policy Act of 2005

ESA		Endangered Species Act

Exchange Act		The Securities Exchange Act of 1934, as amended

FASB		Financial Accounting Standards Board

FERC		Federal Energy Regulatory Commission

FPA		Federal Power Act

GAAP		Generally Accepted Accounting Principles

Gas		Iberdrola Energy Holdings, LLC

Iberdrola		Iberdrola, S.A.

Iberdrola Group		Group of companies controlled by Iberdrola

IRHI		Iberdrola Renewables Holdings, Inc.

ISO		Independent system operator

(i)



ISO-NE		ISO New England, Inc.

IUSA		Iberdrola USA, Inc., a New York Corporation

MBTA		Migratory Bird Treaty Act

Merger sub		Green Merger Sub, Inc.

MNG		Maine Natural Gas Company

MPUC		Maine Power Utilities Commission

MtM		Mark to market

MW		Megawatts

NERC		North American Electric Reliability Corporation

Networks		Iberdrola USA Networks, Inc.

New York TransCo		New York TransCo, LLC.

NGA		Natural Gas Act of 1938

NGPSA		Natural Gas Pipeline Safety Act of 1968

NOL		Net operating loss

NYISO		New York Independent System Operator, Inc.

NYPSC		New York State Public Service Commission

NYSEG		New York State Electric & Gas Corporation

PHMSA		Pipeline and Hazardous Materials Safety Administration

PPA		Power purchase agreement

RDM		Revenue decoupling mechanism

Renewables		Iberdrola Renewables, LLC

REV		Reforming the Energy Vision

RGE		Rochester Gas & Electric Corporation

ROE		Return on equity

RPS		Renewable Portfolio Standards

RTO		Regional transmission organizations

SEC		United States Securities and Exchange Commission

Securities Act		Securities Act of 1933, as amended

U.S. GAAP		U.S. Generally Accepted Accounting Principles

UIL Holdings		UIL Holdings Corporation, a Connecticut Corporation

(ii)

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Condensed Consolidated Statements of Income

(unaudited)


	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
(Millions, except for number of shares)
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		—			—			—			—

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

The accompanying notes are an integral part of our condensed consolidated financial statements.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Condensed Consolidated Statements of Comprehensive Income

(unaudited)


	Three Months Ended September 30,					Nine Months Ended September 30,
	2015		2014			2015			2014
(Millions)
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			5			4

Other Comprehensive Income, Net of Tax		17		1			20			5

Comprehensive Income Attributable to Iberdrola USA, Inc.	$	71	$	65		$	191		$	332

The accompanying notes are an integral part of our condensed consolidated financial statements.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Condensed Consolidated Balance Sheets

(unaudited)


	September 30,			December 31,
As of	2015			2014
(Millions)
Assets
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

The accompanying notes are an integral part of our condensed consolidated financial statements.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Condensed Consolidated Balance Sheets

(unaudited)


	September 30,			December 31,
As of	2015			2014
(Millions)
Liabilities
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

Other Non-current Liabilities
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		—			—
Equity
Stockholder’s Equity:
Common stock		—			—
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

The accompanying notes are an integral part of our condensed consolidated financial statements.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Condensed Consolidated Statements of Cash Flows

(unaudited)


	Nine Months Ended September 30,
	2015			2014
(Millions)
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

The accompanying notes are an integral part of our condensed consolidated financial statements.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Condensed Consolidated Statements of Changes in Equity

(unaudited)


	Iberdrola USA, Inc. Stockholder
(Millions, except for number of shares )	Number of shares (*)		Additional paid-in capital		Retained Earnings		Accumulated Other Comprehensive Income (Loss)			Non controlling Interests			Total
As of December 31, 2013		243	$	11,378	$	737	$	(100	)	$	15		$	12,030
Net Income		—		—		327		—			—			327
Other comprehensive income, net of tax		—		—		—		5			—			5

Comprehensive income														332

Sale of noncontrolling interests		—		—		—		—			(4	)		(4	)

As of September 30, 2014		243	$	11,378	$	1,064	$	(95	)	$	11		$	12,358

As of December 31, 2014		243	$	11,378	$	1,161	$	(99	)	$	16		$	12,456
Net Income		—		—		171		—			—			171
Other comprehensive income, net of tax		—		—		—		20			—			20

Comprehensive income														191

As of September 30, 2015		243	$	11,378	$	1,332	$	(79	)	$	16		$	12,647

(*)	Par value of share amounts is $0.01

The accompanying notes are an integral part of our condensed consolidated financial statements.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

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.

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

“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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

“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.

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

•

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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	)

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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 Ended						Nine Months Ended
(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 in unrealized gains (losses) relating to financial instruments still held at the reporting date	$	(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 Description	Valuation Technique	Valuation Inputs	Index	Variability
Instruments	Instrument Description	Valuation Technique	Valuation Inputs	Index	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

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)


As of December 31, 2014
Instruments	Instrument Description	Valuation Technique	Valuation Inputs	Index	Variability
Instruments	Instrument Description	Valuation Technique	Valuation Inputs	Index	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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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, 2015		December 31, 2014
(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	)

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

The offsetting of derivative assets as of September 30, 2015 and December 31, 2014 consisted of:


As of	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet				Net Amount
As of	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet		Financial Instruments		Cash Collateral Pledged		Net Amount
(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 Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet		Net Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet				Net Amount
As of	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet					Financial Instruments		Cash Collateral Pledged		Net Amount
(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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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 Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet		Gross Amounts Not Offset in the Balance Sheet						Net Amount
As of	Gross Amounts of Recognized Assets		Gross Amounts Offset in the Balance Sheet			Net Amounts of Assets Presented in the Balance Sheet		Financial Instruments			Cash Collateral Pledged			Net Amount
(Millions)
September 30, 2015
Derivatives	$	476	$	(236	)	$	240	$	(45	)	$	(102	)	$	93

December 31, 2014
Derivatives		847		(620	)		227		(66	)		(73	)		88

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

The offsetting of derivative liabilities as of September 30, 2015 and December 31, 2014 consisted of:


As of	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet		Net Amounts of Liabilities Presented in the Balance Sheet			Gross Amounts Not Offset in the Balance Sheet				Net Amount
As of	Gross Amounts of Recognized Liabilities			Gross Amounts Offset in the Balance Sheet					Financial Instruments		Cash Collateral Pledged		Net Amount
(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 Location		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	)

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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 in OCI on Derivatives		Location of Gain Reclassified from Accumulated OCI into Income		Gain Reclassified from Accumulated OCI into Income
(Millions)	Effective Portion ^(a)		Effective Portion ^(a)
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 in OCI on Derivatives		Location of Gain Reclassified from Accumulated OCI into Income		Gain Reclassified from Accumulated OCI into Income
(Millions)	Effective Portion ^(a)		Effective Portion ^(a)
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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

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

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)


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

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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 December 31, 2013			2014 Change			As of September 30, 2014			As of December 31, 2014			2015 Change			As of September 30, 2015
(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 June 30, 2014			2014 Change			As of September 30, 2014			As of June 30, 2015			2015 Change		As of September 30, 2015
(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

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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 Ended September 30,				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

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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.

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)

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

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 To			Purchases From		Sales To			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

Iberdrola USA, Inc. and Subsidiaries

(A Wholly Owned Subsidiary of Iberdrola, S.A.)

Notes to Condensed Consolidated Financial Statements

(unaudited)


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.

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.

Item 2. Management’s Discussion and Analysis of Financial Condition and Results of Operations

You should read the following discussion of our financial condition and results of operations in conjunction with the condensed consolidated financial statements and the notes thereto included elsewhere in this Quarterly Report on Form 10-Q and with our audited consolidated financial statements included in the registration statement on Form S-4 filed with the Securities and Exchange Commission, or the SEC, which was declared effective on November 12, 2015. In addition to historical condensed consolidated financial information, the following discussion contains forward-looking statements that reflect our plans, estimates, and beliefs. Our actual results could differ materially from those discussed in the forward-looking statements. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this Quarterly Report on Form 10-Q, particularly in Part II. Item 1A. “Risk Factors.”

Overview

We are a direct, wholly-owned subsidiary of Iberdrola, S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of Spain and one of the world’s leading global energy companies. We hold the U.S. operations of Iberdrola through our direct, wholly-owned operating subsidiaries, Iberdrola Networks, Inc., or Networks, and Iberdrola Renewables Holdings, Inc., or IRHI. IRHI in turn holds Iberdrola Renewables LLC, or Renewables and Iberdrola Energy Holdings, LLC, or Gas.

Networks provides the transmission and distribution of electricity and the distribution of natural gas through regulated electric and gas public utility affiliates and strives to be a leader in safety, reliability and quality of service. Through Networks, we own electric transmission and distribution companies and natural gas distribution companies in New York and Maine, delivering electricity to approximately 1.9 million electric utility customers, with a rate base of $5.3 billion as of September 30, 2015, and delivering natural gas to 574,000 natural gas public utility customers, with a rate base of $1.0 billion as of September 30, 2015. Networks in turn serves as a super-regional energy services and delivery company through four regulated utility companies it owns:

•

New York State Electric & Gas Corporation, or NYSEG: serves electric and natural gas customers across more than 40% of upstate New York geographic area;

•

Rochester Gas & Electric Corporation, or RGE: serves electric and natural gas customers within a nine-county region in western New York, centered around Rochester;

•

Central Maine Power Company, or CMP: serves electric customers in central and southern Maine; and

•

Maine Natural Gas Company, or MNG: serves natural gas customers in several communities in central and southern Maine.

Renewables develops, constructs and operates a portfolio consisting primarily of renewable energy generation facilities using wind, solar and thermal power and strives to lead the transformation of the U.S. energy industry to a competitive, clean energy future. Through Renewables, we had a combined wind, solar and thermal installed capacity of 6,330 megawatts, or MW, as of September 30, 2015, including Renewables’ share of joint ventures, of which 5,645 MW was installed wind capacity. As the second largest wind operator in the United States based on installed capacity as of September 30, 2015, Renewables currently operates 53 wind farms in 18 states across the United States.

Gas operates natural gas storage facilities and gas trading businesses. Through Gas, we owned approximately 67.5 billion cubic feet, or Bcf, of net working natural gas storage capacity as of September 30, 2015. Through its subsidiaries, Gas operated 53.25 Bcf of contracted or managed natural gas storage capacity in North America as of September 30, 2015.

During the three months ended September 30, 2015, our operating revenues were $1.05 billion, compared to $0.98 billion for the three months ended September 30, 2014.

The increase in operating revenues was primary due to a 5% increase in revenues at Networks as a result of an increase in electric and gas sales, transmission revenue and other sundry sales, a 13% increase in revenues at Renewables primarily as a result of increased wind production from existing facilities as well as the opening of a new wind farm at Baffin Bay which began production in 2015 and favorable changes on mark-to-market, or MtM, derivatives, partially offset by decreased revenues in Gas of 42% due to decreases in gas prices.

Net income decreased primarily related to a 15% increase in operations and maintenance at Networks as a result of higher expenses for labor, bad debt expense, and transmission system reliability support expenses, and a 25% increase in purchased power, natural gas and fuel used for Renewables due to higher power costs for the Klamath plant combined with adverse market price volatility on derivatives, partially offset by a 18% decrease in operations and maintenance expenses for Gas as a result of lower indirect expenditures on external labor costs and an 8% decrease in purchased power, natural gas and fuel at Networks.

Adjusted earnings before interest, tax, depreciation and amortization, or adjusted EBITDA, increased by 4% from $315 million for the three months ended September 30, 2014 to $327 million for the three months ended September 30, 2015 primarily as a result of a 22% increase in adjusted EBITDA at Renewables as a result of increased wind production from existing facilities as well as the opening of a new wind farm at Baffin Bay and favorable MtM derivatives, partially offset by a 2% decrease in adjusted EBTIDA at Networks as a result of an increase in operations and maintenance and a 9% decrease in adjusted EBITDA at Gas due to decreases in gas prices.

See “—Results of Operations” for further analysis of our operating results for the quarter.

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the independent system operator, or ISO, markets in which we participate. Federal and state legislative and regulatory actions continue to change how our business is regulated. We are actively participating in these debates at the federal, regional, state and ISO levels. Significant updates are discussed below. For a further discussion of the environmental and other governmental regulations that affect us, see “Additional Information about IUSA—Regulatory Environment and Principal Markets” in our registration statement on Form S-4 filed with the Securities and Exchange Commission, which was declared effective on November 12, 2015.

Electric Transmission and Distribution and Natural Gas Distribution

NYSEG, RGE, CMP and MNG are operating under rate plans or rate case orders that allow for recovery of cost to provide delivery service. NYSEG and RGE’s current rate plans went into effect on August 26, 2010. On May 20, 2015, NYSEG and RGE filed rate cases in New York for new rates to become effective in April 2016. CMP’s current distribution rates went into effect on August 25, 2014 and MNG’s current rate plan went into effect on December 22, 2009. On March 5, 2015, MNG filed a rate case, the final determination on which is expected by the end of 2015. CMP’s transmission rates are determined by a tariff regulated by the Federal Energy Regulatory Commission, or FERC, and administered by ISO New England, Inc., or 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.

On March 5, 2015, MNG filed a rate case to recover investments in infrastructure in future rates and provide safe and adequate service. 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.

Merger with UIL Holdings

On February 25, 2015, we and our wholly-owned subsidiary, Green Merger Sub, Inc., or merger sub, entered into a merger agreement with UIL Holdings Corporation, or UIL Holdings, pursuant to which UIL

Holdings will merge with and into merger sub, with merger sub being the surviving corporation. The proposed merger is aligned with our corporate strategy to invest in regulated electric and gas businesses and is expected to improve our long-term financial strength and risk profile. Upon completion of the transaction, the combined company will own seven regulated utility companies operating in four states, further diversifying our lines of businesses and geographies, while Networks will increase its revenue mix and further diversify its sources of seasonal revenues.

The proposed merger is also expected to result in a combined company with much larger regulated operations, smoother, more predictable cash flows and greater financial flexibility to pursue incremental investment opportunities to enhance our capital expenditure program. With the addition of UIL Holdings’ portfolio of regulated utility companies in Connecticut and Massachusetts, the proposed merger is expected to offer greater flexibility to grow the combined regulated businesses through project development (from the benefits of increased scale) and create an enhanced platform to develop transmission and distribution projects in the Northeastern United States.

For additional information, see the section entitled “Risk Factors—Risks Relating to the Proposed Merger” under Part II, Item 1.A. Risk Factors of this report and our registration statement on Form S-4 filed with the SEC, which was declared effective on November 12, 2015.

Results of Operations

The following table sets forth our operating revenues and expenses items for each of the periods indicated and as a percentage of operating revenues:


	Three Months Ended September 30,												Nine Months Ended September 30,
	2015			%			2014			%			2015			%			2014			%
		(in millions)
Operating Revenues	$	1,048			100	%	$	982			100	%	$	3,214			100	%	$	3,476			100	%
Operating Expenses
Purchased power, natural gas and fuel used		211			20			204			21			754			23			925			27
Operations and maintenance		421			40			383			39			1,235			38			1,130			33
Impairment of non-current assets		3			—			3			—			10			—			12			—
Depreciation and amortization		163			16			159			16			525			16			470			14
Taxes other than income taxes		89			8			80			8			260			8			240			7

Total Operating Expenses		887			84			829			84			2,784			86			2,777			81

Operating income from continuing operations		161			16			153			16			430			14			699			19
Other Income (Expense)
Other income (expense)		16			2			19			2			38			1			50			1
Earnings (losses) from equity method investments		(3	)		—			(9	)		(1	)		(3	)		—			—			—
Interest expense, net of capitalization		(64	)		(6	)		(61	)		(6	)		(191	)		(6	)		(178	)		(5	)

Income Before Income Tax		110			12			102			11			274			9			571			15
Income tax expense		56			5			38			4			103			3			244			7

Consolidated Net Income		54			7			64			7			171			6			327			8
Net Income	$	54			7	%	$	64			7	%	$	171			6	%	$	327			8	%

Comparison of Period to Period Results of Operations

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2015

The following table sets forth our operating revenues and expenses by segment for each of the periods indicated and as a percentage of the consolidated total of operating revenues and operating expenses, respectively:


	Three Months Ended September 30,
	2015			%			2014			%
		(in millions)
Networks
Operating revenues	$	790			75	%	$	752			77	%
Operating expenses	$	636			72	%	$	595			72	%
Renewables
Operating revenues	$	302			29	%	$	267			27	%
Operating expenses	$	257			29	%	$	242			29	%
Gas
Operating revenues	$	(17	)		(2	)%	$	(12	)		(1	)%
Operating expenses	$	14			2	%	$	17			2	%
Other⁽¹⁾
Operating revenues	$	(27	)		(2	)%	$	(25	)		(3	)%
Operating expenses	$	(20	)		(3	)%	$	(25	)		(3	)%

⁽¹⁾	Other amounts represent corporate and company eliminations.

Operating Revenues

Our operating revenues increased by 7% from $982 million for the three months ended September 30, 2014 to approximately $1.0 billion for the three months ended September 30, 2015, as detailed by segment below:

Networks

Operating revenues for the three months ended September 30, 2015 increased $38 million or 5% from $752 million for the three months ended September 30, 2014 to $790 million for the three months ended September 30, 2015. The increase in operating revenues was due to the increase in electric and gas sales of $16 million from higher volumes, transmission revenue increases of $4 million and other sundry sales increases of $11 million.

Renewables

Operating revenues for the three months ended September 30, 2015 increased $35 million or 13% from $267 million for the three months ended September 30, 2014 to $302 million for the three months ended September 30, 2015. The increase was due to increased production from higher wind resources on existing facilities of $6 million with an additional $5 million of revenue associated with the Baffin Bay wind farm, which began production in 2015, combined with $23 million of favorable changes on MtM derivatives.

Gas

Operating revenues for the three months ended September 30, 2015 decreased $5 million or 42% from negative $12 million for the three months ended September 30, 2014 to negative $17 million for the three months ended September 30, 2015. The decrease in operating revenues of $5 million is largely due to decrease in gas prices over the periods.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used increased by 3% from $204 million for the three months ended September 30, 2014 to $211 million for the three months ended September 30, 2015, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used for the three months ended September 30, 2015 decreased $15 million or 9% from $168 million for the three months ended September 30, 2014 to $153 million for the three months ended September 30, 2015. The decrease was attributed to lower usage as well as lower prices in 2015 for electricity purchases of $29 million. Additionally gas usage and prices were lower in 2015 compared to 2014 resulting in a $19 million reduction in expenses.

Renewables

Purchased power, natural gas and fuel used for the three months ended September 30, 2015 increased $14 million or 25% from $58 million for the three months ended September 30, 2014 to $72 million for the three months ended September 30, 2015. The $14 million increase in purchased power was due to higher power costs for the Klamath plant combined with adverse market price volatility on derivatives.

Gas

Purchased power, natural gas and fuel used for the three months ended September 30, 2015 and September 30, 2014 was nil since, as a predominantly trading business, purchases of gas are netted within operating revenues.

Operations and Maintenance

Our operations and maintenance increased by 10% from $383 million for the three months ended September 30, 2014 to $421 million for the three months ended September 30, 2015, as detailed by segment below:

Networks

Operations and maintenance for the three months ended September 30, 2015 increased $45 million or 15% from $288 million for the three months ended September 30, 2014 to $332 million for the three months ended September 30, 2015. The increase in operations and maintenance expenses is primarily attributable to higher expenses for labor of $26 million, bad debt expense of $12 million, and transmission system reliability support expenses of $9 million.

Renewables

Operations and maintenance during the three months ended September 30, 2015 showed a $1 million reduction from $86 million for the three months ended September 30, 2014 to $85 million for the three months ended September 30, 2015.

Gas

Operations and maintenance for the three months ended September 30, 2015 decreased $2 million or 20% from $10 million for the three months ended September 30, 2014 to $8 million for the three months ended September 30, 2015. The change in operations and maintenance expenses for the comparative periods represents lower indirect expenditures on external labor costs.

Depreciation, Amortization and Impairment of Non-Current Assets

Depreciation, amortization and impairment expenses for the three months ended September 30, 2015 increased $4 million, from $162 million for the three months ended September 30, 2014 to $166 million for the three months ended September 30, 2015. The change was primarily due to an increase of $4 million for the newly installed Baffin Bay wind asset.

Other Income and (Expense) and Equity Earnings

Other income and (expense) and equity earnings for the three months ended September 30, 2015 increased $3 million from $10 million for the three months ended September 30, 2014 to $13 million for the three months ended September 30, 2015. The increase resulted principally from losses associated with joint ventures of Networks in 2014, which are no longer owned.

Interest Expense, Net of Capitalization

Interest expense for the three months ended September 30, 2015 increased $3 million from $61 million for three months ended September 30, 2014 to $64 million for the three months ended September 30, 2015. The difference is attributed primarily to the Networks business where interest expense increased by $5 million due to higher average debt levels.

Income Tax Expense

The effective tax rates for continuing operations for the three months ended September 30, 2015 and September 30, 2014 were 50.9% and 37.3% respectively. The rate in 2015 is higher than the 35% statutory federal income tax rate primarily due to state income tax expenses, partially offset by the recognition of production tax credits associated with wind production. The rate in 2014 was higher than the 35% statutory federal income tax rate primarily due to the increase in the overall accumulated deferred state income tax liability caused by the imposition of a unitary tax regime in New York effective January 1, 2015, offset by the recognition of production tax credits associated with wind production.

Nine Months Ended September 30, 2015 Compared to Nine Months Ended September 30, 2014


	Nine Months Ended September 30,
	2015			%			2014			%
		(in millions)
Networks
Operating revenues	$	2,519			78	%	$	2,584			74	%
Operating expenses	$	2,077			75	%	$	2,095			75	%
Renewables
Operating revenues	$	793			25	%	$	855			25	%
Operating expenses	$	714			26	%	$	686			25	%
Gas
Operating revenues	$	(28	)		(1	)%	$	90			3	%
Operating expenses	$	44			2	%	$	48			2	%
Other⁽¹⁾
Operating revenues	$	(70	)		(2	)%	$	(53	)		(2	)%
Operating expenses	$	(51	)		(3	)%	$	(52	)		(2	)%

⁽¹⁾	Other amounts represent corporate and company eliminations.

Operating Revenues

Our operating revenues decreased by 8% from $3.5 billion for the nine months ended September 30, 2014 to $3.2 billion for the nine months ended September 30, 2015, as detailed by segment below:

Networks

Operating revenues for the nine months ended September 30, 2015 decreased $65 million or 3% from $2.6 billion for the nine months ended September 30, 2014 to $2.5 billion for the nine months ended September 30, 2015. The decrease in revenues was due to a decrease in retail revenues of $64 million due mainly to lower rates in 2015 compared to 2014. Additionally, revenues decreased $114 million compared to the prior year due to expired wholesale sales agreements. These negative effects were partially offset by the increase in regulatory activity of $72 million with the primary driver to this change being Yankee DOE phase 2 regulatory refund of $28 million and increase in other sales of $29 million.

Renewables

Operating revenues for the nine months ended September 30, 2015 decreased $62 million or 7% from $855 million for the nine months ended September 30, 2014 to $793 million for the nine months ended September 30, 2015. The decrease in operating revenues was due to a decrease of $65 million from existing wind assets reflecting lower wind resources, a decrease of $11 million in prices realized and a decrease of $37 million from power trading activities due to low price volatility in gas market in the Northwest region of the United States from mild weather. Partially offsetting this decrease was a $12 million increase in revenue associated with the Baffin Bay wind farm, which began production in 2015, and $35 million in favorable changes on MtM derivatives.

Gas

Operating revenues for the nine months ended September 30, 2015 decreased $118 million from $90 million for the nine months ended September 30, 2014 to negative $28 million for the nine months ended September 30, 2015. The decrease in operating revenues was due to a $92 million change in MtM, value of hedging instruments caused by volatility in gas prices. In addition, operating revenues from storage decreased $26 million due to milder weather and lower prices in 2015.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used decreased by 19%, from $925 million for nine months ended September 30, 2014 to $754 million for the nine months ended September 30, 2015, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used for the nine months ended September 30, 2015 decreased $186 million or 22% from $832 million for the nine months ended September 30, 2014 to $646 million for the nine months ended September 30, 2015. The decrease was primarily due to lower electricity purchases of $144 million largely driven by higher prices experienced in 2014. Additionally, gas purchases were also lower in 2015 from lower prices, resulting in a $42 million decrease in purchased gas expense.

Renewables

Purchased power, natural gas and fuel used for the nine months ended September 30, 2015 increased $2 million or 1% from $141 million for the nine months ended September 30, 2014 to $143 million for the nine months ended September 30, 2015. The increase in purchased power was due to adverse market price volatility on derivatives.

Gas

Purchased power, natural gas and fuel used for the nine months ended September 30, 2015 decreased by $1 million from $1 million for the nine months ended September 30, 2014 to nil for the nine months ended September 30, 2015. The $1 million decrease was due to lower fuel costs for running owned storage facilities.

Operations and Maintenance

Our operations and maintenance increased by 10% from $1.1 billion for the nine months ended September 30, 2014 to $1.2 billion for the nine months ended September 30, 2015, as detailed by segment below:

Networks

Operations and maintenance for the nine months ended September 30, 2015 increased $106 million or 12% from $857 million for the nine months ended September 30, 2014 to $963 million for the nine months ended September 30, 2015. The primary drivers were regulatory refunds received in 2014 for the Yankee DOE phase 2 of $28 million and labor expenses increases of $35 million as a result of lower capitalized amounts between the periods. The remaining variance is attributable to higher overheads of $9 million, energy efficiency expenditures of $4 million and transmission system reliability expense increases of $11 million.

Renewables

Operations and maintenance expenses during the nine months ended September 30, 2015 increased $14 million or 6% from $249 million for the nine months ended September 30, 2014 to $263 million for the nine months ended September 30, 2015. The increase in operating expenses was due to $3 million of additional costs incurred with the commencement of operations for the Baffin Bay wind. In addition, a reserve was recorded during the nine months ended September 30, 2015 for bad debt of $6 million related to the collection of curtailment revenues.

Gas

Operations and maintenance for the nine months ended September 30, 2015 decreased $2 million from $27 million for the nine months ended September 30, 2014 to $25 million for the nine months ended September 30, 2015. The change in operations and maintenance expenses for the comparative periods represents lower indirect expenditures on external labor costs.

Depreciation, Amortization and Impairment of Non-Current Assets

Depreciation, amortization and impairment expenses for the nine months ended September 30, 2015 was $535 million compared to $482 million for the nine months ended September 30, 2014, an increase of $53 million. The increase was primarily attributable to a $24 million increase of additional non-current assets within the Networks business, together with an increase of $9 million in the Renewables business, attributable to the newly installed Baffin Bay wind asset.

Other Income and (Expense) and Equity Earnings

Other income and (expense) and equity earnings for the nine months ended September 30, 2015 decreased $15 million from $50 million for the nine months ended September 30, 2014 to $35 million for the nine months ended September 30, 2015. The decrease resulted principally from lower contributions associated with joint ventures of Renewables for the Colorado Green and Flat Rock wind assets of $8 million as a result of lower generation output and lower merchant prices, reductions in interest and other non-operating income at Renewables of $9 million.

Interest Expense, Net of Capitalization

Interest expense for the nine months ended September 30, 2015 and September 30, 2014 were $191 million and $178 million, respectively. The increase was attributed primarily to the Networks business associated with carrying costs on regulatory liabilities.

Income Tax Expense

The effective tax rates for the nine months ended September 30, 2015 and September 30, 2014 were 37.6% and 42.7% respectively. The rate in 2015 is higher than the 35% statutory federal income tax rate primarily due to state income tax expenses, partially offset by the recognition of production tax credits associated with wind production. The rate in 2014 was higher than the 35% statutory federal income tax rate primarily due to the increase in the overall accumulated deferred state income tax liability caused by the imposition of a unitary tax regime in New York effective January 1, 2015, offset by the recognition of production tax credits associated with wind production.

Non-GAAP Financial Measures

We supplement the use of U.S. Generally Accepted Accounting Principles, or U.S. GAAP, financial measures with non-GAAP financial measures, including adjusted EBITDA, which we define as net income (loss) attributable to us, 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, and adjusted gross margin, which we define as adjusted EBITDA adding back operations and maintenance and taxes other than income taxes and then subtracting transmission wheeling. We refer to these measures as “non-GAAP financial measures” given they are not required by, or presented in accordance with U.S. GAAP. We present these non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance. We also use these measures internally to establish budgets and operational goals to manage and monitor our business, as well as to evaluate our underlying historical performance.

These non-GAAP financial measures are not measurements of our performance under U.S. GAAP and should not be considered as alternatives to operating income (loss) from continuing operations, net income or any other performance measures determined in accordance with U.S. GAAP. The most directly comparable U.S. GAAP measure to adjusted EBITDA and adjusted gross margin is net income. Additionally, these non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools and should not be considered in isolation or as a substitute for analysis of our operating results as reported under U.S. GAAP.

The following table provides a reconciliation between our net income and adjusted EBITDA as well as our net income and adjusted gross margin for the three and nine months ended September 30, 2015 and 2014:


	Three Months Ended September 30,						Nine Months Ended September 30,
	2015			2014			2015			2014
		(in millions)
Net Income	$	54		$	64		$	171		$	327

Add: Net income attributable to other Non-controlling-interests		—			—			—			—
Income tax expense		56			38			103			244
Depreciation and amortization		163			159			525			470
Impairment of non-current assets		3			3			10			12
Less: 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	)		—

Adjusted EBITDA	$	327		$	315		$	965		$	1,181

Add: Operations and maintenance⁽¹⁾		421			383			1,235			1,130
Taxes other than income taxes		89			80			260			240
Less: Transmission wheeling⁽¹⁾		42			38			108			107

Adjusted gross margin	$	795		$	740		$	2,352		$	2,444

⁽¹⁾	Transmission wheeling is a component of operations and maintenance and is considered a component of adjusted gross margin since it is directly associated with the power supply costs included in the cost of sales.

Three Months Ended September 30, 2014 Compared to Three Months Ended September 30, 2015

The following table sets forth our adjusted EBITDA and adjusted gross margin by segment for each of the periods indicated and as a percentage of operating revenues:


	Three Months Ended September 30,
	2015			%			2014			%
		(in millions)
Networks
Adjusted EBITDA	$	224			28	%	$	227			30	%
Adjusted gross margin	$	592			75	%	$	545			73	%
Renewables
Adjusted EBITDA	$	136			45	%	$	112			42	%
Adjusted gross margin	$	229			76	%	$	208			78	%
Gas
Adjusted EBITDA	$	(26	)		152	%	$	(24	)		197	%
Adjusted gross margin	$	(16	)		96	%	$	(13	)		105	%
Other⁽¹⁾
Adjusted EBITDA	$	(7	)		26	%		—			—
Adjusted gross margin	$	(10	)		37	%		—			—

⁽¹⁾	Other amounts represent corporate and company eliminations.

Adjusted EBITDA

Our adjusted EBITDA increased by 4% from $315 million for the three months ended September 30, 2014 to $327 million for the three months ended September 30, 2015, as detailed by segment below:

Networks

Adjusted EBITDA for the three months ended September 30, 2015 decreased $3 million or 1% from $227 million for the three months ended September 30, 2014 to $224 million for the three months ended September 30, 2015. The decrease was driven by the increases in adjusted gross margin offset by the higher increase in operations and maintenance discussed above and increases in the cost of transmission wheeling expense period over period.

Renewables

Adjusted EBITDA for the three months ended September 30, 2015 increased $24 million or 22% from $112 million for the three months ended September 30, 2014 to $136 million for the three months ended September 30, 2015. The increase in adjusted EBITDA was due to the reasons discussed above related to operating revenues and purchased power, natural gas and fuel used.

Gas

Adjusted EBITDA for the three months ended September 30, 2015 decreased $2 million or 9% from negative $24 million for the three months ended September 30, 2014 to negative $26 million for the three months ended September 30, 2015. The decrease was due to the reasons discussed above for operating revenues.

Adjusted Gross Margin

Our adjusted gross margin increased by 7% from $740 million for the three months ended September 30, 2014 to $795 million for the three months ended September 30, 2015, as detailed by segment below:

Networks

Adjusted gross margin for the three months ended September 30, 2015 increased $47 million or 9% from $545 million for the three months ended September 30, 2014 to $592 million for the three months ended September 30, 2015 due to the reasons discussed above for operating revenues and purchased power, natural gas and fuel used.

Renewables

Adjusted gross margin for the three months ended September 30, 2015 increased $21 million or 10% from $208 million for the three months ended September 30, 2014 to $229 million for the three months ended September 30, 2015. The increase in total adjusted gross margin was due to the reasons discussed above for operating revenues and purchased power, natural gas and fuel used.

Gas

Adjusted gross margin for the three months ended September 30, 2015 decreased $3 million or 22% from negative $13 million for the three months ended September 30, 2014 to negative $16 million for the three months ended September 30, 2015. The decrease was due to the reasons discussed above for operating revenues.

Nine Months Ended September 30, 2014 Compared to Nine Months Ended September 30, 2015

The following table sets forth our adjusted EBITDA and adjusted gross margin by segment for each of the periods indicated and as a percentage of operating revenues:


	Nine Months Ended September 30,
	2015			%			2014			%
		(in millions)
Networks
Adjusted EBITDA	$	693			28	%	$	694			27	%
Adjusted gross margin	$	1,766			70	%	$	1,644			64	%
Renewables
Adjusted EBITDA	$	349			44	%	$	429			50	%
Adjusted gross margin	$	651			82	%	$	714			84	%
Gas
Adjusted EBITDA	$	(58	)		208	%	$	58			64	%
Adjusted gross margin	$	(30	)		106	%	$	88			98	%
Other⁽¹⁾
Adjusted EBITDA	$	(19	)		27	%		—			—
Adjusted gross margin	$	(35	)		49	%	$	(2	)		4	%

⁽¹⁾	Other amounts represent corporate and company eliminations.

Adjusted EBITDA

Our adjusted EBITDA decreased by 18%, from $1.2 billion for the nine months ended September 30, 2014 to $965 million for the nine months ended September 30, 2015, as detailed by segment below:

Networks

Adjusted EBITDA for the nine months ended September 30, 2015 decreased marginally, by $1 million to $693 million compared to the nine months ended September 30, 2014 amount of $694 million.

Renewables

Adjusted EBITDA for the nine months ended September 30, 2015 decreased $80 million or 19% from $429 million for the nine months ended September 30, 2014 to $349 million for the nine months ended September 30, 2015. The decrease in adjusted EBITDA was due to the reasons discussed above for revenues and purchased power, natural gas and fuel used.

Gas

Adjusted EBITDA for the nine months ended September 30, 2015 decreased $116 million from $58 million for the nine months ended September 30, 2014 to negative $58 million for the nine months ended September 30, 2015. The decrease was driven by the decreases in operating revenues discussed above.

Adjusted Gross Margin

Our adjusted gross margin decreased by 4%, from $2.4 billion for nine months ended September 30, 2014 to $2.3 billion for the nine months ended September 30, 2015, as detailed by segment below:

Networks

Adjusted gross margin for the nine months ended September 30, 2015 increased $120 million or 7% from $1.6 billion for the nine months ended September 30, 2014 to $1.7 billion for the nine months ended September 30, 2015. The increase was associated with the lower purchased fuel expenses discussed above of $186 million, which was partially offset by the decrease in revenue discussed above of $65 million. The remaining $1 million represents the increase in the cost of transmission wheeling expense period over period.

Renewables

Adjusted gross margin for the nine months ended September 30, 2015 decreased $63 million or 9% from $714 million for the nine months ended September 30, 2014 to $651 million for the nine months ended September 30, 2015. The decrease in adjusted gross margin was due to the reasons discussed above for revenues and purchased power, natural gas and fuel used.

Gas

Adjusted gross margin for the nine months ended September 30, 2015 decreased $118 million from $88 million for the nine months ended September 30, 2014 to negative $30 million for the nine months ended September 30, 2015. The decrease resulted from the items discussed above for operating revenues.

Liquidity and Capital Resources

Our operating, investing, developing and acquisition activities have significant short-term liquidity and long-term capital requirements. Historically, we have used cash from operations and borrowings under our credit facilities and commercial paper programs as our primary sources of liquidity. Our long-term capital requirements have been met primarily through retention of earnings, equity contributions from Iberdrola and borrowings in the investment grade debt capital markets. Continued access to these sources of liquidity and capital are critical to our business.

We and our subsidiaries are required to comply with certain covenants in connection with our respective loan agreements. The covenants are standard and customary in bank and loan agreements, and we and our subsidiaries were in compliance with such covenants as of September 30, 2015.

Liquidity Position

At September 30, 2015 and December 31, 2014, the liquidity available to us and our unregulated subsidiaries was approximately $1,348 million and $769 million, respectively, the additional liquidity available to the regulated utilities was approximately $574 million and $599 million, respectively and total liquidity was approximately $1,368 million and $1,922 million, respectively.

Our cash balances are primarily deposited with Bank Mendes Gans, N.V., or BMG pursuant to a notional cash pooling agreement with Iberdrola, S.A. and certain of its subsidiaries. Deposits in the cash pooling account were $449 million and $1,045 million at December 31, 2014 and September 30, 2015, respectively. The deposit amounts are reflected in our consolidated balance sheets under cash and cash equivalents because our deposited surplus funds under the cash pooling agreement are highly-liquid short-term investments.

The following table provides the components of our liquidity position as of September 30, 2015 and December 31, 2014:


	As of September 30, 2015		As of December 31, 2014
		(in millions)
Cash and cash equivalents		1,050		482
IUSA Revolving Credit Facility		300		300
Less: borrowings		—		—
Joint Utility Revolving Credit Facility		600		600
Less: borrowings		(28)		(14)
Total		1,922		1,368

IUSA Revolving Credit Facility

As of December 31, 2014 and September 30, 2015, the revolving credit facility was undrawn.

Joint Utility Revolving Credit Facility

The joint facility is the backstop for CMP and NYSEG’s commercial paper programs. The companies intend to use commercial paper as an alternative to revolving credit facilities as a source of short-term debt. As of December 31, 2014 and September 30, 2015, there was $586 million and $572 million, respectively, available under the joint facility. The maturity date for the join facility is July 15, 2018.

Iberdrola Financiación, S.A.U. Credit Facility

As of September 30, 2015, there was no balance outstanding under this agreement and on October 28, 2015 we cancelled the agreement and have no further rights or obligations under it.

Liquidity Management

Our liquidity resources are comprised of cash and undrawn revolving credit capacity. We optimize our liquidity through a series of arms’ length intercompany lending arrangements with our subsidiaries to move liquidity from subsidiaries with cash surplus to subsidiaries with liquidity needs, subject to the limitation that the regulated utilities may borrow from affiliates, but may not lend to unregulated affiliates.

We have two revolving credit facilities. The IUSA revolving credit facility allows IUSA to borrow up to $300 million and expires in May 2019. The joint utility revolving credit facility allows NYSEG, RGE and CMP to borrow up to $600 million and matures in July 2018. NYSEG and CMP have commercial paper programs backstopped by the joint utility revolving credit facility.

Capital Requirements

We expect to incur approximately $280 million in capital expenditures through the end of 2015.

Cash Flows

Our cash flows depend on many factors, including general economic conditions, regulatory decisions, weather, commodity price movements, and operating expense and capital spending control.

The following is a summary of the cash flows by activity for the nine months ended September 30, 2015 and 2014:


	Nine Months Ended September 30,
	2015			2014
		(in millions)
Net cash from operating activities	$	963		$	1,154
Net cash used in investing activities		(613	)		(704	)
Net cash provided by (used in) financing activities		218			(146	)

Net increase in cash and cash equivalents	$	568		$	304

Operating Activities

For the nine months ended September 30, 2015, net cash provided by operating activities was $963 million. During the period, Renewables contributed $409 million of operating cash flow associated with wholesale sales of energy, Networks contributed $721 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas, and Gas used $36 million in cash associated with losses on marketing of wholesale gas and gas storage services. Additionally $121 million in cash was used associated with corporate operating expenses in support of the operating segments. In addition, changes in working capital used $10 million in cash. The cash from operating activities for the nine months ended September 30, 2015 compared to the nine months ended September 30, 2014 decreased $191 million, primarily attributable to the decreased revenues at Renewables due to lower wind sources at existing assets and unfavorable pricing as well as decreased revenues at Gas due to lower gas prices. The $70 million net change in operating assets and liabilities during the nine months ended September 30, 2015 was primarily attributable to a decrease in inventory of $40 million from lower gas requirements and a net decrease of $26 million in accounts payable and receivable due to impacts from sales and purchases.

For the nine months ended September 30, 2014, net cash provided by operating activities was $1,154 million. During the period, Renewables contributed $394 million of operating cash associated with wholesale sales of energy, Networks contributed $617 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas, and Gas contributed cash of $13 million associated with gains on marketing of wholesale gas and gas storage services. Additionally $104 million in cash was used associated with corporate operating expenses in support of the operating segments. In addition, changes in working capital contributed cash of approximately $236 million. The $208 million net change in operating assets and liabilities during the nine months ended September 30, 2014 was attributable to a decrease in accounts receivable of $106 million driven by improvements in collection, together with a favorable change in net regulatory assets/liabilities of $132 million, partially offset by a reduction in accounts payable of $37 million due to lower energy prices.

Investing Activities

For the nine months ended September 30, 2015, net cash used in investing activities was $613 million, which was comprised of $484 million associated with capital expenditures at Networks with the remainder primarily attributable to investments within Renewables, including turbine payments in support of the Baffin Bay wind construction project.

For the nine months ended September 30, 2014, net cash used in investing activities was $704 million, primarily attributable to $667 million associated with capital expenditures at Networks. The majority of the remaining amounts were attributed to changes in working capital to support investments within Renewables, including payments in support of the Baffin Bay wind construction project that was constructed in 2014.

Financing Activities

For nine months ended September 30, 2015, financing activities provided $218 million in cash. CMP issued $150 million in first mortgage bonds and NYSEG issued $200 million related to financing the investments of the Networks business. Additionally $60 million of pollution control notes matured at NYSEG. This was offset by a decrease in the amortization of the tax equity financing arrangements of $59 million.

For nine months ended September 30, 2014, net cash used in financing activities was $146 million primarily attributed to repayment of long-term debt of $34 million, amortization of the tax equity financing arrangements of $95 million and capital lease repayments of $12 million.

Off-Balance Sheet Arrangements

We did not have any off-balance sheet arrangements as of September 30, 2015.

Contractual Obligations

There has been no material changes in contractual and contingent obligations from those reported for the fiscal year ended December 31, 2014 in our registration statement on Form S-4 filed with the SEC, which was declared effective on November 12, 2015.

Critical Accounting Policies and Estimates

The accompanying financial statements provided herein have been prepared in accordance with U.S. GAAP. In preparing the accompanying financial statements, our management has applied accounting policies and made certain estimates and assumptions that affect the reported amounts of assets, liabilities, shareholder’s equity, revenues and expenses, and the disclosures thereof. While we believe that these policies and estimates used are appropriate, actual future events can and often do result in outcomes that can be materially different from these estimates. The accounting policies and related risks described in our registration statement on Form S-4 filed with the SEC, which was declared effective on November 12, 2015, are those that depend most heavily on these judgments and estimates. As of September 30, 2015, there have been no material changes to any of the policies described therein.

New Accounting Standards

We review new accounting standards to determine the expected financial impact, if any, that the adoption of each such standard will have. There have been no new accounting standards issued since the filing of our registration statement on Form S-4 filed with the SEC, which was declared effective on November 12, 2015, that we expect to have a material impact on our consolidated financial position, results of operations or liquidity.

CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Quarterly Report on Form 10-Q contains a number of forward-looking statements. Forward-looking statements may be identified by the use of forward-looking terms such as “may,” “will,” “should,” “can,” “expects,” “believes,” “anticipates,” “intends,” “plans,” “estimates,” “projects,” “assumes,” “guides,” “targets,” “forecasts,” “is confident that” and “seeks” or the negative of such terms or other variations on such terms or comparable terminology. Such forward-looking statements include, but are not limited to, statements about the potential benefits of the proposed merger between us and UIL Holdings, including the combined company’s plans, objectives and intentions, the expected timing of completion of the transaction, outlooks or expectations for earnings, revenues, expenses or other future financial or business performance, strategies or expectations, or the impact of legal or regulatory matters on business, results of operations or financial condition of the combined business and other statements that are not historical facts. Such statements are based upon the current beliefs and expectations of our respective managements and are subject to significant risks and uncertainties that could cause actual outcomes and results to differ materially. Important factors that could cause actual results to differ materially from those indicated by such forward-looking statements include, without limitation, the risks and uncertainties set forth under Part II, Item 1A. Risk Factors in this report. Specifically, forward-looking statements may include statements relating to:

•

the inability to complete the merger due to the failure to satisfy conditions to the completion of the merger or the failure of the merger to be completed for any other reason;

•

the occurrence of any event, change or other circumstances that could give rise to the termination of the merger agreement;

•

the future financial performance, anticipated liquidity and capital expenditures of the combined company;

•

success in retaining or recruiting, or changes required in, our officers, key employees or directors following the merger;

•

the risk that the businesses will not be coordinated successfully, or that the coordination will be more costly or more time consuming and complex than anticipated;

•

disruption from the merger making it difficult to maintain business and operational relationships;

•

adverse developments in general market, business, economic, labor, regulatory and political conditions;

•

the impact of any cyber-breaches, acts of war or terrorism or natural disasters; and

•

the impact of any change to applicable laws and regulations affecting operations, including those relating to environmental and climate change, taxes, price controls, regulatory approval and permitting.

Should one or more of these risks or uncertainties materialize, or should any of the underlying assumptions prove incorrect, actual results may vary in material respects from those expressed or implied by these forward-looking statements. You should not place undue reliance on these forward-looking statements. We do not undertake any obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this report, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in our market risk during the nine months ended September 30, 2015 from those reported for the fiscal year ended December 31, 2014 in our registration statement on Form S-4 filed with the SEC, which was declared effective on November 12, 2015.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Corporate Officer, or CCO, and our Chief Financial Officer, CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), as of the end of the period covered by this Quarterly Report on Form 10-Q. Based on such evaluation, our CCO and CFO have concluded that as of such date, our disclosure controls and procedures were effective.

Changes in Internal Control

There were no changes in our internal control over financial reporting identified in management’s evaluation pursuant to Rules 13a-15(d) or 15d-15(d) of the Exchange Act during the period covered by this Quarterly Report on Form 10-Q that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please read Note 7—Contingencies and Note 8—Environmental Liability to the accompanying unaudited condensed consolidated financial statements under Part I.A of this report for a discussion of the legal proceedings that we believe could be material to us.

Item 1A. Risk Factors

Risks Relating to the Proposed Merger

There is no assurance when or if the proposed merger will be completed.

Completion of the proposed merger is subject to the satisfaction or waiver of a number of conditions as set forth in the merger agreement, including regulatory and UIL Holdings shareowner approvals and other customary closing conditions. There can be no assurance that the conditions to completion of the proposed merger will be satisfied or waived or that other events will not intervene to delay or result in the failure to close the proposed merger. In addition, both we and UIL Holdings may unilaterally terminate the merger agreement under certain circumstances, and we and UIL Holdings may agree at any time to terminate the merger agreement, even if UIL Holdings’ shareowners have already approved the merger agreement and thereby approved the proposed merger and the other transactions contemplated by the merger agreement. We and UIL Holdings can also terminate the merger agreement under other specified circumstances.

The combined company may be unable to integrate successfully and the combined company may not experience the strategic and financial benefits being sought from the proposed merger.

We and UIL Holdings have operated and, until the completion of the proposed merger will continue to operate, independently. If the proposed merger is completed, UIL Holdings will become an indirect wholly-owned subsidiary of the combined company but will initially continue its operations on a basis that is separate from the rest of the combined company’s subsidiaries’ operations. Coordinating certain aspects of the operations and personnel of UIL Holdings with us after the completion of the proposed merger will involve complex operational, technological and personnel-related challenges. This process will be time-consuming and expensive, may disrupt the businesses of either or both of the companies and may not result in the benefits potentially available to us and UIL Holdings. The potential difficulties, and resulting costs and delays, include:

•

managing a larger combined company;

•

coordinating corporate and administrative infrastructures;

•

unanticipated issues in coordinating information technology, communications, administration and other systems;

•

difficulty addressing possible differences in corporate cultures and management philosophies;

•

unforeseen and unexpected liabilities related to the proposed merger or UIL Holdings’ business; and

•

a deterioration of credit ratings.

Further, while, either party can, in general, refuse to complete the proposed merger if there is a material adverse effect (as defined in the merger agreement) affecting the other party prior to the completion of the proposed merger, certain types of changes do not permit either party to refuse to complete the proposed merger, even if such changes would have a material adverse effect on us or UIL Holdings. If adverse changes occur but we and UIL Holdings must still complete the proposed merger, the market price of the combined company common stock may suffer. There can be no assurance that, if the proposed merger is not completed, these risks will not materialize and will not materially adversely affect our business and financial results and the business and financial results of UIL Holdings as separate companies.

Risks Relating to Our Regulatory Environment

Our businesses are subject to substantial regulation by federal, state and local regulatory agencies and our businesses, results of operations and prospects may be materially adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements.

The operations of our subsidiaries are subject to, and our businesses are influenced by, complex and comprehensive federal, state and local regulation and legislation, including regulations promulgated by state utilities commissions and FERC. This extensive regulatory and legislative framework, portions of which are more specifically identified in the following risk factors, regulates, among other things and to varying degrees, the industries in which our subsidiaries operate, our business segments, rates for our products and services, financings, capital structures, cost structures, construction, environmental obligations (including in respect of, among others, air emissions, water consumption, water discharge, protections for wildlife and humans, nuisance prohibitions and allowances, and regulation of gas and oil infrastructure operations, and associated environmental and facility permitting), development and operation of electric and gas transmission and distribution facilities, natural gas transportation, processing and storage facilities, acquisition, disposal, depreciation and amortization of facilities and other assets, service reliability, hedging and derivatives transactions and Gas’ commodities trading.

In our business planning and in the management of our subsidiaries’ operations, we must address the effects of regulation on our businesses, including the significant and increasing compliance costs imposed on our operations as a result of such regulation, and any inability or failure to do so timely and adequately could have a material adverse effect on our businesses, results of operations, financial condition and cash flows. The federal, state and local political and economic environment has had, and may in the future have, an adverse effect on regulatory decisions with negative consequences for our businesses. These decisions may require, for example, our businesses to cancel or delay planned development activities, to reduce or delay other planned capital expenditures or investments or otherwise incur costs that we may not be able to recover through rates, any of which could have a material adverse effect on the business, results of operations, financial condition and cash flows of our businesses. In addition, changes in the nature of the regulation of our business could have a material adverse effect on our business, results of operations, financial condition and cash flows. We are unable to predict future legislative or regulatory changes, initiatives or interpretations, and there can be no assurance that we will be able to respond adequately or sufficiently quickly to such changes, although any such changes, initiatives or interpretations may increase costs and competitive pressures on us, which could have a material adverse effect on our business, results of operations, financial condition and cash flows. There can be no assurance that we will be able to respond adequately or sufficiently quickly to such rules and developments, or to any other changes that reverse or restrict the competitive restructuring of the energy industry in those jurisdictions in which such restructuring has occurred. Any of these events could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Our businesses are subject to the jurisdiction of various federal, state and local regulatory agencies including, but not limited to, FERC, the Commodity Futures Trading Commission, or CFTC, the Department of Energy, or DOE, and the Environmental Protection Agency, or EPA. Further, Networks’ regulated utilities in New York and Maine are subject to the jurisdiction of the New York State Public Service Commission, or NYPSC, the MPUC, the New York State Department of Environmental Conservation and the Maine Department of Environmental Protection. These regulatory agencies cover a wide range of business activities, including, among other items, the retail and wholesale rates for electric energy, capacity and ancillary services, and for the transmission and distribution of these products, the costs charged to Networks’ customers through tariffs including cost recovery clauses, the terms and conditions of Networks’ services, procurement of electricity for Networks’ customers, issuances of securities, the provision of services by affiliates and the allocation of those service costs, certain accounting matters, and certain aspects of the siting, construction and transmission and distribution systems. FERC has the authority to impose penalties on regulated utilities owned by us and the

transmission and distribution of electricity and gas, which could be substantial, for violations of the Federal Power Act, or FPA, the Natural Gas Act of 1938, or NGA, or related rules, including reliability and cyber security rules as described in further detail below. The Financial Accounting Standards Board, or FASB, or the SEC may enact new accounting standards that could impact the way we are required to record revenue, expenses, assets and liabilities. Certain regulatory agencies have the authority to review and disallow recovery of costs that they consider excessive or imprudently incurred and to determine the level of return that our businesses are permitted to earn on invested capital. The regulatory process, which may be adversely affected by the political, regulatory and economic environment in New York or Maine, as applicable, may limit our ability to increase earnings and does not provide any assurance as to achievement of authorized or other earnings levels. The disallowance of the recovery of costs incurred by us or a decrease in the rate of return that we are permitted to earn on our invested capital could have a material adverse effect on our business, results of operation, financial condition and cash flows. Certain of these regulatory agencies also have the authority to audit the management and operations of our businesses in New York and Maine and require or recommend operational changes. Such audits and post-audit work requires the attention of our management and employees and may divert their attention from other regulatory, operational or financial matters. The last management audit was by the NYPSC of Iberdrola, us, NYSEG, and RGE, and completed in 2012. This audit resulted in 72 recommendations that were accepted by the NYPSC and that the companies verified as complete in 2014. As of April 24, 2015, the NYPSC has accepted 63 of the companies’ implementations as complete, and Networks continues to work with the NYPSC on the remaining nine recommendations.

Our failure to meet the reliability standards mandated by the Energy Policy Act of 2005 could have a material adverse effect on our business, results of operation, financial condition and cash flows.

As a result of the Energy Policy Act of 2005, or EPAct 2005, owners, operators and users of bulk electric systems are subject to mandatory reliability standards developed by the North American Electric Reliability Corporation, or NERC, and its regional entities and approved and enforced by FERC. The standards are based on the functions that need to be performed to ensure that the bulk electric system operates reliably. Networks’ and Renewables’ businesses have been, and will continue to be, subject to routine audits and monitoring with respect to compliance with applicable NERC reliability standards, including standards approved by FERC that will result in an increase in the number of assets (including cyber-security assets) designated as “critical assets,” which would subject such assets to NERC cyber-security. NERC and FERC can be expected to continue to refine existing reliability standards as well as develop and adopt new reliability standards. Compliance with modified or new reliability standards may subject Networks’ and/or Renewables’ businesses to new requirements resulting in higher operating costs and/or increased capital expenditures. If Networks’ and/or Renewables’ businesses were found not to be in compliance with the mandatory reliability standards, it could be subject to penalties of up to $1.0 million per day per violation. Both the costs of regulatory compliance and the costs that may be imposed as a result of any actual or alleged compliance failures could have a material adverse effect on our business, results of operation, financial condition and prospects.

The NYPSC has initiated a proceeding that may result in the alteration of the public utility model in New York State and could materially and adversely impact our business and operations in New York State.

In April 2014, the NYPSC initiated a proceeding intended to explore the Reforming the Energy Vision, or REV, the goals of which are to improve electric system efficiency and reliability, encourage renewable energy resources, support distributed energy resources, or DER, and empower customer choice. In this proceeding, the NYPSC is examining the establishment of a Distributed System Platform, or DSP, to manage and coordinate DER, and provide customers with market data and tools to manage their energy use. The NYPSC also is examining how its regulatory practices should be modified to incent utility practices to promote REV objectives. The proceeding is following a two-phased schedule with an order relating to policy determinations for DSP and related matters issued in February 2015 and an order for regulatory design and regulatory matters, expected in 2016. We are not able to predict the outcome of the REV proceeding or its impact on our business, results of operations, financial condition and cash flows. While the end result of the REV process at the NYPSC remains unclear, it could alter the utility model in New York in a manner that could create material adverse impacts on our businesses and operations in New York.

Changes in regulatory and/or legislative policy could negatively impact Networks’ transmission planning and cost allocation.

The existing FERC-approved ISO-NE transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities. As new investment in regional transmission infrastructure occurs in any one state, its cost is shared across New England in accordance with a FERC approved formula found in the transmission tariff. Participating New England transmission owners’ agreement to this regional cost allocation is set forth in the Transmission Operating Agreement. This agreement can be modified with the approval of a majority of the transmission owning utilities and approval by FERC. In addition, other parties, such as state regulators, may seek certain changes to the regional cost allocation formula, which could have adverse effects on the rates Networks’ distribution companies in New England charge their retail customers.

FERC has issued rules requiring all regional transmission organizations, or RTOs, and transmission owning utilities to make compliance changes to their tariffs and contracts in order to further encourage the construction of transmission for generation, including renewable generation. This compliance will require RTOs (such as ISO-NE and New York Independent System Operator, Inc., or NYISO) and the transmission owners in New England and New York to develop methodologies that allow for regional planning and cost allocation for transmission projects chosen in the regional plan that are designed to meet public policy goals such as reducing greenhouse gas emissions or encouraging renewable generation. Such compliance may also allow non-incumbent utilities and other entities to participate in the planning and construction of new projects in Networks’ service areas and regionally.

Changes in RTO tariffs, transmission owners’ agreements, or legislative policy, or implementation of these new FERC planning rules, could adversely affect our transmission planning, results of operations, financial condition and cash flows.

We are subject to numerous environmental laws, regulations and other standards, including rules and regulations with respect to climate change, that may result in capital expenditures, increased operating costs and various liabilities, and may require us to limit or eliminate certain operations.

Our businesses are subject to environmental laws and regulations, including, but not limited to, extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality and usage, climate change, emissions of greenhouse gases (including, but not limited to carbon dioxide), waste management, hazardous wastes (including the clean-up of former manufactured gas and electric generation facilities), marine, avian and other wildlife mortality and habitat protection, historical artifact preservation, natural resources and health and safety (including, but not limited to, electric and magnetic fields from power lines and substations, and ice throw, shadow flicker and noise related to wind turbines) that could, among other things, prevent or delay the development of power generation, power or natural gas transmission, or other infrastructure projects, restrict the output of some existing facilities, limit the availability and use of some fuels required for the production of electricity, require additional pollution control equipment, and otherwise increase costs, increase capital expenditures and limit or eliminate certain operations. There are significant capital, operating and other costs associated with compliance with these environmental statutes, rules and regulations, and those costs could be even more significant in the future as a result of new legislation, the current trend toward more stringent standards, and stricter and more expansive application and enforcement of existing environmental regulations. For example, new laws, regulations or treaties relating to climate change could mandate new or increased requirements to control or reduce the emission of greenhouse gases, such as carbon dioxide, taxes or fees on fossil fuels or emissions, cap and trade programs, emission limits and clean or renewable energy standards. Violations of current or future laws, rules, regulations or other standards could expose our subsidiaries to regulatory and legal proceedings, disputes with, and legal challenges by, third parties, and potentially significant civil fines, criminal penalties and other sanctions. Proceedings could include, for example, litigation regarding property damage, personal injury, common law nuisance, noise and enforcement by citizens or governmental authorities of environmental requirements such as air, water, wildlife and soil quality-standards.

Our regulated utility operations may not be able to recover costs in a timely manner or at all or obtain a return on certain assets or invested capital through base rates, cost recovery clauses, other regulatory mechanisms or otherwise.

Networks’ regulated utilities in New York and Maine are subject to periodic review of their rates by the NYPSC and MPUC, respectively, and the retail rates charged to Networks’ regulated utilities’ customers through base rates and cost recovery clauses are subject to the jurisdiction of the NYPSC or MPUC, as applicable. New rates may be proposed by the Iberdrola Network’s businesses, which are then subject to review, modification and final authorization and implementation by regulators. Alternatively, regulators may review the rates of Networks’ regulated utilities on their own motion. Networks’ regulated utilities’ rate plans cover specified periods, but rates determined pursuant to a plan generally continue in effect until a new rate plan is approved by the state utility regulator. The Networks’ regulated utilities’ business rate plans approved by state utility regulators limit the rates Networks’ regulated utilities can charge their customers. The rates are generally designed for, but do not guarantee, the recovery of Networks’ regulated utilities’ respective cost of service and the opportunity to earn a reasonable rate of return (including return on equity, or ROE). Actual costs may exceed levels provided for such costs in the rate plans for Networks’ regulated utilities. Utility regulators can initiate proceedings to prohibit Networks’ regulated utilities from recovering from their customers the cost of service (including energy costs) that the regulators determine to have been imprudently incurred. Networks’ regulated utilities defer for future recovery certain costs including major storm costs and environmental costs. If Networks’ regulated utilities’ costs are not fully and timely recovered through the rates ultimately approved by regulators, our cash flows, results of operations and financial condition, and our ability to earn a return on investment and meet financial obligations, could be adversely affected.

Networks’ regulated utilities in New York filed for new rates at the NYPSC on May 20, 2015. CMP, filed for approval of a billing system on February 27, 2015. MNG, filed a multi-year distribution rate case with the MPUC on March 5, 2015. 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 and an immediate one-time gross plant investment disallowance of $6.0M as of December 31, 2015. The Maine PUC is expected to rule on the stipulation by the end of December 2015. The outcome of future rates for the New York and Maine businesses remains uncertain due to the pending rate proceedings. Networks may not be able to recover from customers increasing costs, taxes or state-mandated assessments or surcharges, which could adversely affect Networks’ ability to generate a reasonable rate of return. Networks’ current electric and gas rate plans include revenue decoupling mechanisms, or RDMs, and the gas and electric rate plans of Networks’ New York regulated utilities include provisions for the recovery of energy costs, including reconciliation of the actual amount paid by Networks. There is no guarantee that such decoupling mechanisms or recovery and reconciliation mechanism will remain part of the rate plan of Networks in future rate proceedings.

Networks previously owned and operated manufactured gas and electric generation facilities. Most of these facilities have been sold or decommissioned. State and federal environmental laws impose continuing strict liability on former owners and operators to clean up environmental contamination that impacts human health or the environment. NYSEG and RGE have a comprehensive state plan to investigate and clean up more than 40 former manufactured gas plants. NYSEG, RGE and CMP are all allowed to recover reasonable clean-up costs in their current rate provisions. The timing, allowance, and mechanism for future clean-up cost recovery is subject to future rate proceedings. NYSEG, RGE and CMP could also be responsible to decommission former generation facilities to ensure compliance with state and federal environmental and health and safety laws. RGE is currently decommissioning two former fossil generation sites located in Rochester, New York, and while NYPSC has allowed cost recovery for the decommissioning, the total amount of the decommissioning costs, the allowance, and the timing could be subject to future rate proceedings. Networks may not be able to obtain, in a timely manner or at all, rate recovery in respect of all or a portion of the costs its subsidiaries may incur in respect of clean-up decommissioning manufactured gas and electric generation facilities.

In addition, there are pending challenges at FERC against New England transmission owners (including CMP) seeking to lower the ROE that these transmission owners are allowed by FERC to receive for wholesale transmission service pursuant to the ISO-NE Open Access Transmission Tariff. Reductions to returns on equity adversely impact the revenues that Networks’ regulated utilities receive from wholesale transmission customers and could materially adversely affect our business, results of operations, financial condition and cash flows.

Harming of protected species can result in curtailment of wind project operations and other damages.

The operation of energy projects and transmission of energy can adversely affect endangered, threatened or otherwise protected animal species under federal and state statutes, laws, rules and regulations. Wind projects involve a risk that protected flying species, such as birds and bats, will be harmed due to collision. Transmission and distribution lines are another source of potential avian collision as well as electrocution. Energy generation and transmission facilities can result in impacts to protected wildlife, including death caused by collision, electrocution and poisoning. Energy infrastructure occasionally affects endangered or protected species. Our businesses observe industry guidelines and government-recommended best practices to avoid, minimize and mitigate harm to protected species, but complete avoidance is not possible and subsequent penalties may result. Where appropriate, our businesses can apply for an “incidental take” permit for protected species, which may be conditioned upon the institution of costly avoidance and remediation measures.

Violations of environmental laws in certain jurisdictions may result in civil or criminal penalties, including with respect to violations of certain laws protecting migratory birds, endangered species and eagles. The federal Endangered Species Act, or ESA, and analogous state laws restrict activities without a permit that may adversely affect endangered and threatened species or their habitat. The ESA also provides for private causes of actions against a development project, an operating facility, or the agency that oversees the alleged violation of law. Similar protections are offered to migratory birds under the Migratory Bird Treaty Act, or MBTA, which implements various treaties and conventions between the United States and certain other nations for the protection of migratory birds and, pursuant to which the taking, killing or possessing of migratory birds is unlawful. Complying with the ESA and the MBTA may require implementation of operating restrictions or a temporary, seasonal, or permanent ban on operations in affected areas, which can materially adversely affect the revenue of those projects. Similar federal protections for eagles are provided for by the Bald and Golden Eagle Protection Act, or BGEPA, which prohibits the taking of eagles without a permit. The ESA, MBTA and BGEPA provide for criminal penalties for the “take” of protected species; the ESA and BGEPA also provide for civil penalties. Networks and Renewables are particularly prone to risks relating to birds and bats given the potential for collision and electrocution with their infrastructure, which can be considered an incidental “take” and therefore subject to penalties. The designation of new endangered or threatened species located in, or the movement or migration of species into areas where our businesses operate could cause us to incur additional costs or become subject to operating delays, restrictions or bans. For example, there have been recent sightings of the protected California condor at Renewables’ Manzana wind facility. Any incidental taking of a California condor could result in substantial financial, legal and reputational harm to us. The U.S. Department of Justice, or DOJ, is currently investigating Renewables for potential violations under the MBTA and the ESA at its Blue Creek facility and for potential violations of the MBTA and BGEPA at its three wind farms located in the state of Washington. Successful prosecutions or settlements relating to these potential violations or other violations involving environmental laws could result in material financial and reputational harm to us. Taking of protected species can result in requirements to implement mitigation strategies, including curtailment of operations, short-term or long-term compensatory mitigation payments, investments or participation in mitigation research, and processing of and compliance with permits. We cannot guarantee that our practices and mitigation strategies will not have a material adverse effect on our business, results of operations, financial condition and cash flows.

Renewables relies in part on governmental policies that support utility-scale renewable energy. Any reductions to, or the elimination of, governmental incentives that support utility-scale renewable energy or the imposition of additional taxes or other assessments on renewable energy, could result in a material adverse effect on our business, results of operations, financial condition and cash flows.

Renewables relies, in part, upon government policies that support utility-scale renewable energy projects and enhance the economic feasibility of developing and operating wind energy projects in regions in which Renewables operates or plans to develop and operate renewable energy facilities. The federal government and many states and local jurisdictions have policies or other mechanisms, such as tax incentives or Renewable

Portfolio Standards, or RPS, that support the sale of energy from utility-scale renewable energy facilities, such as wind and solar energy facilities. As a result of budgetary constraints, political factors or otherwise, federal, state and local governments from time to time may review their policies and other mechanisms that support renewable energy and consider actions that would make them less conducive to the development or operation of renewable energy facilities. Any reductions to, or the elimination of, governmental policies or other mechanisms that support renewable energy or the imposition of additional taxes or other assessments on renewable energy, could result in, among other items, the lack of a satisfactory market for the development of new renewable energy projects, Renewables abandoning the development of new renewable energy projects, a loss of Renewables’ investments in the projects and reduced project returns, any of which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Our businesses may face risks related to obtaining governmental approvals and permits in respect of project siting, financing, construction, operation and the negotiation of project development agreements.

Renewables owns, develops, constructs and/or operates electricity generation, including renewable and thermal generators, and associated transmission facilities. Gas owns, develops, constructs, manages and/or operates natural gas storage and associated transportation facilities. Networks develops, constructs, manages and operates transmission and distribution facilities to meet customer needs. As part of these operations, our businesses must periodically apply for licenses and permits from various local, state, federal and other regulatory authorities and abide by their respective conditions. In particular, with respect to Renewables, over the past two years noise standards and siting criteria in the Northeast, where population density is higher compared to the Northwest, where Renewables also operates, have grown more restrictive. If our businesses are unsuccessful in obtaining necessary licenses or permits on acceptable terms, there is a delay in obtaining or renewing necessary licenses or permits or regulatory authorities initiate any associated investigations or enforcement actions or impose related penalties or disallowances on us, our businesses, results of operations, financial conditions and cash flows could be materially adversely affected.

Our operating subsidiaries’ purchases and sales of energy commodities and related transportation and services expose us to potential regulatory risks.

Under the EPAct 2005, as well as under the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, our businesses are subject to enhanced FERC and CFTC statutory authority to monitor certain segments of the physical and financial energy commodities markets. The Dodd-Frank Act creates a new regulatory framework for federal oversight of derivatives transactions by the CFTC and the SEC and requires the CFTC, the SEC and other regulatory agencies to promulgate rules and regulations implementing the legislation. These agencies have imposed broad regulations prohibiting fraud and manipulation of the electricity and gas markets. Under these laws, FERC and CFTC have promulgated new regulations that have increased compliance costs and imposed new reporting requirements on our businesses. For example, the Dodd-Frank Act substantially increased regulation of the over-the-counter derivative contracts market and futures contract markets, which impacts our businesses. The new regulations require our operating subsidiaries to comply with certain margin requirements for our over-the-counter derivative contracts with certain CFTC- or SEC-registered entities and if the rules implementing the new regulations require us to post significant amounts of cash collateral with respect to swap transactions, our liquidity could be materially adversely affected. We cannot predict the impact these new regulations will have on our businesses’ ability to hedge their commodity and interest rate risks or on over-the-counter derivatives markets as a whole, but they could potentially have a material adverse effect on our businesses’ risk exposure, as well as reduce market liquidity and further increase the cost of hedging activities.

With regard to the physical purchases and sales of energy commodities, the physical trading of energy commodities and any related transportation and/or hedging activities that some of our operating subsidiaries undertake, our operating subsidiaries are required to observe the market-related regulations and certain reporting and other requirements enforced by the FERC, the CFTC and the SEC. Additionally, to the extent that the operating subsidiaries enter into transportation contracts with natural gas pipelines or transmission contracts with electricity transmission providers that are subject to FERC regulation, the operating subsidiaries are subject to FERC requirements related to the use of such transportation or transmission capacity. Any failure on the part of

our operating subsidiaries to comply with the regulations and policies of the FERC, the CFTC or the SEC relating to the physical or financial trading and sales of natural gas or other energy commodities, transportation or transmission of these energy commodities or trading or hedging of these commodities could result in the imposition of significant civil and criminal penalties. Failure to comply with such regulations, as interpreted and enforced, could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Renewables’ ability to generate revenue from certain utility-scale wind energy power plants depends on having continuing interconnection arrangements, PPAs, or other market mechanisms and depends upon interconnecting utility and RTO rules, policies, procedures and FERC tariffs that do not present restrictions to current and future wind project operations.

The electric generation facilities owned by Renewables rely on interconnection and/or transmission agreement and transmission networks in order to sell the energy generated by such facility. If the interconnection and/or transmission agreement of an electric generating facility Renewables owns is terminated for any reason, Renewables may not be able to replace it with an interconnection or transmission arrangement on terms as favorable as the existing arrangement, or at all, or it may experience significant delays or costs in securing a replacement. If a transmission network to which one or more of Renewables’ electric generating facilities is connected experiences outages or curtailments, the affected projects may lose revenue. These factors could materially affect Renewables’ ability to forecast operations and negatively affect our business, results of operations, financial condition and cash flow. In addition, certain of Renewables’ operating facilities’ generation of electricity may be physically or economically curtailed, and offtakers or transmission or interconnection providers may be permitted to restrict wind project operations without paying full compensation to Renewables pursuant to power purchase agreements, or PPA or interconnection agreement or FERC tariff provisions or rules, policies or procedures of RTOs, which may reduce our revenues and impair our ability to capitalize fully on a particular facility’s generating potential. Such curtailments or operational limitations could have a material adverse effect on our business, financial condition, results of operations and cash flows. Furthermore, economic congestion on the transmission grid (for instance, a negative price difference between the location where power is put on the grid by a project and the location where power is taken off the grid by the project’s customer) in certain of the bulk power markets in which Renewables operates may occur and its businesses may be responsible for those congestion costs. Similarly, negative congestion costs may require that the wind projects either not participate in the energy markets or bid and clear at negative prices which may require the wind projects to pay money to operate each hour in which prices are negative. If such businesses were liable for such congestion costs or if the wind projects are required to pay money to operate in any given hour when prices are negative, then our financial results could be adversely affected.

Gas’ natural gas storage operations are subject to regulation and reporting obligations by FERC and other federal and state regulatory agencies, including rules and regulations related to the rates its businesses can charge for their services and their ability to construct or abandon facilities. FERC’s rate-making policies could limit Gas’ ability to recover the full cost of operating its facilities, including earning a reasonable return.

Gas’ natural gas storage operations are subject to regulation and reporting obligations by FERC and other federal and state regulatory agencies or commissions, such as the Railroad Commission of Texas for facilities located in Texas. Such regulations and reporting obligations cover rates, the types, operating parameters, operating terms and conditions of services Gas may offer to its customers, the construction of new facilities, the creation, expansion, modification or abandonment of services or facilities, creditworthiness and credit-supporting requirements, recordkeeping and relationships with affiliated companies involved in similarly situated aspects of the natural gas storage business. Gas may also perform certain engineering studies and/or engineering analysis resulting in a reduction of net working gas capacity and the potential reclassification to pad gas. FERC or state regulatory action in any of these areas could adversely affect Gas’ ability to compete for business, construct new facilities, modify or expand existing facilities, offer new services or recover the full cost of operating Gas’ storage facilities. Jurisdiction-specific regulatory oversight could also result in longer lead times to develop and complete any existing or future project than competitors that are not subject to such regulations.

New or amended pipeline safety laws and regulations requiring substantial changes to existing integrity management programs or safety technologies could subject Gas’ natural gas storage operations as well as Networks’ natural gas distribution operating companies to increased capital and operating costs and require them to use more comprehensive and stringent safety controls.

Gas’ natural gas storage operations as well as Networks’ natural gas distribution companies are subject to regulation by the U.S. Department of Transportation’s, or DOT’s, Pipeline and Hazardous Materials Safety Administration, or PHMSA, under the Natural Gas Pipeline Safety Act of 1968, or NGPSA, as amended, which regulates the design, installation, testing, construction, operation, maintenance, repair, inspection, replacement and management of interstate and certain intrastate natural gas pipeline facilities. PHMSA, through NGPSA, has adopted rules under the NGPSA that require natural gas storage and pipeline operators to implement integrity management programs, including more frequent inspections, correction of identified anomalies and other measures to ensure pipeline safety in high consequence areas, such as high population areas, areas unusually sensitive to environmental damage and commercially navigable waterways. These regulations have resulted in an overall increase in maintenance costs for Gas. PHMSA may develop more stringent regulations applicable to integrity management programs and other aspects of our operations, which may be hastened by recently highly-publicized incidents on certain pipelines in the United States. We could incur significant additional costs if new or more stringent pipeline safety requirements are implemented. The Pipeline Safety, Regulatory Certainty, and Job Creation Act of 2011, or the 2011 Act, was enacted and signed into law in early 2012. Under the 2011 Act, maximum civil penalties for certain violations have been increased to $200,000 per violation per day, and from a total cap of $1.0 million to $2.0 million. In addition, the 2011 Act reauthorized the federal pipeline safety programs of PHMSA through September 30, 2015, and directs the Secretary of Transportation to undertake a number of reviews, studies and reports, some of which may result in more stringent safety controls or inspections or additional natural gas and hazardous liquids pipeline safety rulemaking. A number of the provisions of the 2011 Act have the potential to cause owners and operators of pipeline facilities to incur significant capital expenditures and/or operating costs. Gas’ natural gas storage operations, through its wholly-owned direct subsidiary Enstor, Inc., are also regulated by the EPA and state environmental agencies. Therefore, Gas’ natural gas storage operations must comply with certain environmental permits promulgated by the following emissions based standards and regulations: the National Emission Standards for Hazardous Air Pollutants, New Source Performance Standards and National Ambient Air Quality Standards. If we incur additional expenses and expenditures due to increased regulation, our business, results of operation, financial condition and cash flows could be adversely affected.

Risks Relating to Our Business and Operations

Our businesses are subject to general economic, credit and market conditions.

A credit crisis affecting the banking system and the financial markets and the resultant deterioration of macroeconomic conditions, including a global reduction in credit and liquidity in the financial markets and severe volatility in stock and bond markets could impact our financial operating conditions, our day-to-day activities, our liquidity and cash positions, the loss of significant investment opportunities, the value of our business and our financial condition. In addition, during periods of slow or little economic growth, energy conservation efforts often increase and the amount of uncollectible customer accounts increases. These factors may also reduce earnings and cash flow.

If Networks’ electricity and natural gas transmission and distribution systems do not operate as expected, they could require unplanned expenditures, including the maintenance and refurbishment of Networks’ facilities, which could adversely affect our business, results of operations, financial position and cash flows.

Networks’ ability to operate its electricity and natural gas transmission and distribution systems is critical to the financial performance of our business. The ongoing operation of Networks’ facilities involves risks customary to the electric and natural gas industry that include the breakdown, failure, loss of use or destruction of Networks’ facilities, equipment or processes or the facilities, equipment or processes of third parties due to war or acts of terrorism, operational and safety performance below expected levels, errors in the operation or maintenance of these facilities and the inability to transport electricity or natural gas to customers in an efficient

manner. These and other occurrences could reduce potential earnings and cash flows and increase the costs of repairs and replacement of assets. Losses incurred by Networks in respect of such occurrences may not be fully recoverable through insurance or customer rates. Further, certain of Networks’ facilities require periodic upgrading and improvement. Networks continuously updates and improves its facilities. For example, NYSEG and RGE plan to invest a total of $2.75 billion from 2015 to 2019 to upgrade and expand their electricity and natural gas transmission and distribution infrastructure, while CMP is near completion of a $1.4 billion investment plan for the construction of a project to enhance the bulk power transmission grid in Maine. In addition, unplanned outages typically increase Networks’ operation and maintenance expenses. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts, could result in reduced profitability or regulatory penalties. For more information, see “Risks Relating to Our Regulatory Environment” above.

Our businesses’ operations and power production may fall below expectations due to the impact of severe weather or other natural events, which could adversely affect our cash flows, results of operations and financial position.

Weather conditions directly influence the demand for electricity and natural gas and other fuels and affect the price of energy and energy-related commodities. Severe weather, such as ice and snow storms, hurricanes and other natural disasters, such as hurricanes, floods and earthquakes, can be destructive and cause power outages, bodily injury and property damage or affect the availability of fuel and water, which may require Networks and Gas to incur additional costs or loss of revenues, for example, to restore service and repair damaged facilities, to obtain replacement power and to access available financing sources, that may not be recoverable from customers, which could adversely affect our cash flows, results of operations and financial position. Many of our facilities could be placed at greater risk of damage should changes in the global climate produce unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events, abnormal levels of precipitation and a change in sea level. A disruption or failure of electric generation, transmission or distribution systems or natural gas production, transmission, storage or distribution systems in the event of ice and snow storms, long periods of severe weather, hurricane, tornado or other severe weather event, or otherwise, could prevent us from operating our business in the normal course and could result in any of the adverse consequences described above. Because utility companies, including our regulated electric and natural gas utility subsidiaries, have large consumer customer bases, they are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar interruptions caused by storm damage or other unanticipated events. Adverse publicity of this nature could harm our reputations the reputations of our subsidiaries. Furthermore, many of Networks’ and, through its wholly-owned direct subsidiary Enstor, Inc., Gas’ operating facilities are located either in, or close to, densely populated public places. A failure of, or damage to, these facilities, could result in bodily injury or death, property damage, the release of hazardous substances or extended service interruptions. The cost of repairing damage to Networks’ and Gas’ facilities and the potential disruption of their operations due to storms, natural disasters or other catastrophic events could be substantial. In respect of the our businesses where cost recovery is available, recovery of costs to restore service and repair damaged facilities is or may be subject to regulatory approval, and any determination by the regulator not to permit timely and full recovery of the costs incurred could have a material adverse effect on our business, results of operations, financial condition and cash flows.

If wind conditions are unfavorable or below Renewables’ production forecasts, or Renewables’ wind turbines are not available for operation, Renewables projects’ electricity generation and the revenue generated from its projects may be substantially below our expectations.

Changing wind patterns or lower than expected wind resource could cause reductions in electricity generation at Renewables’ projects, which could affect the revenues produced by these wind generating facilities. Renewables’ wind projects are sited, developed and operated to maximize wind performance. Prior to siting a wind facility, detailed studies are conducted to measure the wind resource in order to estimate future production. However, wind patterns or wind resource in the future might deviate from historical patterns and are difficult to predict. These events could negatively impact the results of operations of Renewables, which may vary

significantly from period to period, depending on the level of available resources. To the extent that resources are not available at planned levels, the financial results from these facilities may be less than expected. Changing wind patterns or lower than expected wind resources could also degrade equipment or components and the interconnection and transmission facilities’ lives or maintenance costs. Replacement and spare parts for wind turbines and key pieces of electrical equipment may be difficult or costly to acquire or may be unavailable. The loss of any suppliers or service providers or inability to find replacement suppliers or service providers or to purchase turbines at rates currently offered by Renewables’ existing suppliers or a change in the terms of Renewables’ supply or operations and maintenance agreements, such as increased prices for maintenance services or for spare parts, could have a material adverse effect on Renewables’ ability to construct and maintain wind farms or the profitability of wind farm development and operation.

The revenues generated by Renewables’ facilities depend upon Renewables’ ability to maintain the working order of its wind turbines. A natural disaster, severe weather, accident, failure of major equipment, shortage of or inability to acquire critical replacement or spare parts, failure in the operation of any future transmission facilities that Renewables may acquire, including the failure of interconnection to available electricity transmission or distribution networks, could damage or require Renewables to shut down its turbines or related equipment and facilities, leading to decreases in electricity generation levels and revenues. Additionally, Renewables’ operating projects generally do not hold spare substation main transformers in inventory. These transformers are designed specifically for each wind power project, and order lead times can be lengthy. If one of Renewables’ projects had to replace any of its substation main transformers, it would be unable to sell all of its power until a replacement is installed.

If Renewables experiences a prolonged interruption at one of its operating projects due to natural events or operational problems and such events are not fully covered by insurance, Renewables’ electricity generation levels could materially decrease, which could have a material adverse effect on its business, results of operation and financial condition and could adversely affect our cash flows, results of operations and financial position.

Cyber breaches, acts of war or terrorism, grid disturbances or security breaches involving the misappropriation of confidential and proprietary customer, employee, financial or system operating information could negatively impact our business.

Cyber breaches, acts of war or terrorism or grid disturbances resulting from internal or external sources could target our subsidiaries’ generation, transmission and distribution facilities or our information technology systems. In the regular course of business, our subsidiaries maintain sensitive customer, employee, financial and system operating information and are required by various federal and state laws to safeguard this information. Cyber or physical security intrusions could potentially lead to disabling damage to our generation, transmission and distribution facilities and to theft and the release of critical operating information or confidential customer or employee information, which could adversely affect our subsidiaries’ operations or adversely impact our reputation, and could result in significant costs, fines and litigation. Additionally, because our subsidiaries’ generation and transmission facilities are part of an interconnected regional grid, our subsidiaries face the risk of blackout due to a disruption on a neighboring interconnected system. As threats evolve and grow increasingly more sophisticated, we cannot ensure that a potential security breach may not occur or quantify the potential impact of such an event. Any such cyber breaches could result in a significant decrease in revenues, significant expense to repair system damage or security breaches, regulatory penalties and liability claims, which could have a material adverse effect on our cash flows, results of operations and financial condition.

Risks including but not limited to any physical security breach involving unauthorized access, electricity or equipment theft and vandalism could adversely affect our business operations and adversely impact our reputation.

A physical attack on our subsidiaries’ transmission and distribution infrastructure could interfere with normal business operations and affect our subsidiaries’ ability to control their transmission and distribution assets. A physical security intrusion could potentially lead to theft and the release of critical operating information, which could adversely affect our subsidiaries’ operations or adversely impact our reputation, and could result in significant costs, fines and litigation. Additionally, certain of our subsidiaries’ power generation and transmission

and distribution assets and equipment are at risk for theft and damage. For example, Networks is at risk for copper wire theft, especially, due to an increased demand for copper in the United States and internationally. Theft of copper wire or solar panels can cause significant disruption to Networks’ and Renewables’ operations, respectively, and can lead to operating losses at those locations. Furthermore, Renewables can incur damage to wind turbine equipment, either through natural events such as lightning strikes that damage blades or in-ground electrical systems used to collect electricity from turbines, or through vandalism, such as gunshots into towers or other generating equipment. Such damage can cause disruption of operations for unspecified periods which may lead to operating losses at those locations.

Our risk management policies cannot fully eliminate the risk associated with some of our operating subsidiaries’ commodity trading and hedging activities, which may result in significant losses.

Renewables and Gas have exposure to commodity price movements through their “natural” long positions in electricity and natural gas storage in addition to proprietary trading and hedging activities.

Networks, Renewables and Gas manage the exposure to risks of commodity price movements through internal risk management policies, enforcement of established risk limits and risk management procedures. These risk policies, risk limits and risk management procedures may not work as planned and cannot eliminate all risks associated with these activities. Even when these risk policies and procedures are followed, and decisions are made based on projections and estimates of future performance, results of operations may be diminished if the judgments and assumptions underlying those decisions prove to be incorrect. Our risk management tools and metrics associated with their hedging and trading procedures, such as daily value at risk, stop loss limits and liquidity guidelines, are based on historical price movements. Due to the inherent uncertainty involved in price movements and potential deviation from historical pricing behavior, we are unable to assure that their risk management tools and metrics will be effective to protect against material adverse effects on our business, financial condition, results of operations and prospects. Factors, such as future prices and demand for power and other energy-related commodities, become more difficult to predict and the calculations become less reliable the further into the future estimates are made. As a result, we cannot fully predict the impact that some of our subsidiaries’ commodity trading and hedging activities and risk management decisions may have on our business, results of operations, financial condition and cash flows.

We expect to invest in development opportunities in all segments of our business, but such opportunities may not be successful and projects may not commence operation as scheduled or at all, or be completed within budget or at all, which could have a material adverse effect on our business prospects.

We are pursuing broader development investment opportunities related to all segments of our business, particularly in respect of additional construction projects in respect of renewable energy generation. The development, construction and expansion of such facilities involve numerous risks. Various factors could result in increased costs or result in delays or cancellation of these projects. Risks include regulatory approval processes, new legislation, economic events or factors, environmental and community concerns, design and siting issues, difficulties in obtaining required rights of way, competition from incumbent facilities and other entities, and actions of strategic partners. Should any of these factors result in such delays or cancellations, our business, financial position, results of operations, and cash flows could be adversely affected or our future growth opportunities may not be realized as anticipated.

The progressive reduction in the costs of distributed energy assets, as a result of technological improvements, large scale deployment in certain jurisdictions and constructive support regimes could result in customer defection.

The emergence of technology and the proliferation and structure of rate incentives to distributed energy assets, such as net energy metering which allows electricity customers who supply their own electricity from on-site generation to pay only for the net energy obtained from the utility, behind-the-meter storage systems and grid integration components such as inverters or electronics, could result in electricity delivery customers abandoning the grid system or replacing part of grid services with self-supply or self-balancing, or could impact the return on current or future Networks’ assets deployed and designed to serve projected load. Such emergence

of alternative sources of energy supply can result in customers relying on the power grid for limited use, such as in the case of a deficit or an emergency, or completely abandoning the grid, which is known as customer defection. While the operating subsidiaries of Networks are protected from reduced volumetric sales by decoupling mechanisms, which delinks a utility’s delivery revenues from volumetric sales, these are temporary in nature and there is no assurance such mechanisms will be extended. The progressive reduction in the costs of distributed energy assets, as a result of technological improvements, large scale deployment in certain jurisdictions and constructive support regimes could result in customer defection (individually or integrated in micro-grids) when a net benefit analysis of investing in self-supply and storage of energy compared to energy provided by utility service appears attractive for certain customer classes. Similarly, some current costs or future investments in Networks could be impacted, such as allocating more costs to certain customer segments, if adequate rate making does not fully contemplate the characteristics of an integrated reliable grid from a unified perspective, regardless of customer disconnection. Further, the interoperability, integration and standard connection of these distributed energy devices and systems could place a burden on the system of Networks’ operating subsidiaries, without adequately compensating them.

Advances in technology could impair or eliminate the competitive advantage of our businesses.

The emergence of initiatives designed to reduce greenhouse gas emissions and control or limit the effects of global warming and overall climate change has increased the incentive for the development of new technologies for power generation and energy efficiency, and for investment in research and development to make those technologies more efficient and cost-effective. There is potential that distributed generation systems and energy efficiency measures could adversely affect the demand for services of our regulated subsidiaries thus impacting revenues, which could adversely affect our cash flows, results of operations and financial condition. Furthermore, the technologies used in the renewable energy sector change and evolve rapidly. Techniques for the production of electricity from renewable sources are constantly improving and becoming more complex. In order to maintain Renewables’ competitiveness and expand its business, Renewables must adjust effectively to changes in technology and further its research and development. If Renewables fails to react effectively to current and future technological changes in the sector or to progress its research and development in a timely manner, Renewables’ future business growth, results of operations and financial condition could be materially adversely affected.

Investments in development opportunities in electricity generation, transmission and distribution and natural gas storage and transportation may not be successful and projects may not commence or complete operation as scheduled or be within budget.

Our operating subsidiaries pursue development opportunities related to electric transmission and renewable energy generation, interconnections to generating resources and other investment opportunities. The development, construction and expansion of projects involve numerous risks. Various factors could result in increased costs or result in delays or cancellation of these projects. Risks include regulatory approval processes, permitting, new legislation, economic events or factors, environmental and community concerns, negative publicity, design and siting issues, difficulties in obtaining required rights of way, construction delays and cost overruns, competition from incumbent utilities and other entities, and actions of strategic partners. If any of these factors result in delays or cancellations to these projects, our growth projections, results of operations and financial position could be adversely affected or our future growth opportunities may not be realized as anticipated. For example, NYSEG and RGE hold approximately 20% ownership interest in New York TransCo, LLC, or New York TransCo, along with other investor owned utilities. In December 2014, New York TransCo filed for regulatory approval of a transmission project. While New York TransCo received an order from FERC in April 2015 accepting the project’s risk mitigation measures, FERC rejected the project’s cost allocation proposal and ordered a settlement and hearing proceeding on the proposed capital structure and the base ROE. Additionally, there may be delays or unexpected developments in completing Renewables’ current and future construction projects, which could cause the construction costs of these projects to exceed our expectations. While most of our subsidiaries’ construction projects are constructed under fixed-price and fixed-schedule contracts with construction and equipment suppliers, these contracts provide for limitations on the liability of these contractors to pay our subsidiaries liquidated damages for cost overruns and construction delays. In respect of Renewables’ wind projects, a delay resulting in a wind project failing to qualify for federal production tax credits could result in losses that would be substantially greater than the amount of liquidated damages paid to Renewables.

Our subsidiaries may suffer significant construction delays or construction cost increases as a result of regulatory approval processes, environmental and community concerns, negative publicity, design and siting issues, difficulties in obtaining required rights of way or underperformance of these contractors and equipment suppliers, as well as other suppliers, to our subsidiaries’ projects. For example, while RGE’s Rochester Area Reliability Project, which includes the development of a new substation and transmission lines, was approved by the NYSPC, the project has encountered significant delays due to the concerns of landowners. Delays in equipment deliveries, particularly of wind turbines or transformers, or severe weather may result in extended delays in project construction and completion. These circumstances could prevent Renewables’ construction projects from commencing operations or from meeting Renewables’ original expectations about how much electricity it will generate or the returns it will achieve. In addition, for projects that are subject to PPAs, substantial delays could cause defaults under the PPAs, which generally require the completion of project construction by a certain date at specified performance levels.

Renewables’ revenue may be reduced significantly upon expiration of PPAs if the market price of electricity decreases and Renewables is otherwise unable to negotiate more favorable pricing terms.

Renewables’ portfolio of PPAs is made up of PPAs that primarily have fixed or otherwise predetermined electricity prices for the life of the PPA. A decrease in the market price of electricity, including due to lower prices for traditional fossil fuels, could result in a decrease in revenues once a PPA has expired or upon a renewal of a PPA, unless market conditions recover at the time of expiration and/or Renewables is able to negotiate more favorable pricing terms. Any decrease in the price payable to Renewables under new PPAs could materially adversely affect our business, results of operations, financial conditions and cash flows. In the majority of Renewables’ wind energy generation projects, upon the expiration of a PPA, the project becomes a merchant project subject to market risks, unless Renewables can negotiate a renewal of the PPA. If Renewables is not able to replace an expiring PPA with a contract on equivalent terms and conditions or otherwise obtain prices that permit operation of the related facility on a profitable basis, the affected site may temporarily or permanently cease operations.

There are a limited number of purchasers of utility-scale quantities of electricity, which exposes Renewables’ utility-scale projects to additional risk.

Since the transmission and distribution of electricity is highly concentrated in most jurisdictions, there are a limited number of possible purchasers for utility-scale quantities of electricity in a given geographic location, including transmission grid operators, state and investor-owned power companies, public utility districts and cooperatives. As a result, there is a concentrated pool of potential buyers for electricity generated by Renewables’ businesses, which may restrict their ability to negotiate favorable terms under new PPAs and could impact their ability to find new customers for the electricity generated by their generation facilities should this become necessary. Furthermore, if the financial condition of these utilities and/or power purchasers deteriorated or the RPS programs, climate change programs or other regulations to which they are currently subject and that compel them to source renewable energy supplies change, demand for electricity produced by Renewables’ businesses could be negatively impacted.

Lower prices for other fuel sources may reduce the demand for wind and solar energy development.

Wind and solar energy demand is affected by the price and availability of other fuels, including nuclear, coal, natural gas and oil, as well as other sources of renewable energy. To the extent renewable energy, particularly wind and solar energy, becomes less cost-competitive due to reduced government targets, increases in the cost of wind and solar energy, as a result of new regulations, and incentives that favor alternative renewable energy, cheaper alternatives or otherwise, demand for wind and solar energy and other forms of renewable energy could decrease. Slow growth or a long-term reduction in the demand for renewable energy could have a material adverse effect on Renewables’ ability to grow its business.

Our subsidiaries do not own all of the land on which their projects are located and their use and enjoyment of real property rights for their projects may be adversely affected by the rights of lienholders and leaseholders that are superior to those of the grantors of those real property rights to our subsidiaries’ projects.

Our subsidiaries do not own all of the land on which their projects are located. For example, Renewables does not own all of the land on which its wind projects are located and Gas does not own all of the land on which its natural gas storage projects are located. Such projects generally are, and future projects may be, located on land occupied under long-term easements, leases and rights of way. The ownership interests in the land subject to these easements, leases and rights of way may be subject to mortgages securing loans or other liens and other easements, lease rights and rights of way of third parties that were created previously. As a result, some of the rights under such easements, leases or rights of way held by our operating subsidiaries may be subject to the rights of these third parties, and the rights of our operating subsidiaries to use the land on which their projects are or will be located and their projects’ rights to such easements, leases and rights of way could be lost or curtailed. Any such loss or curtailment of the rights of our operating subsidiaries to use the land on which their projects are or will be located could have a material adverse effect on their business, results of operations, financial condition and cash flows.

We and our subsidiaries are subject to litigation or administrative proceedings.

Our operating subsidiaries have been and continue to be involved in legal proceedings, administrative proceedings, claims and other litigation that arise in the ordinary course of business. These actions may include environmental claims, employment-related claims and contractual disputes or claims for personal injury or property damage that occur in connection with services performed relating to the operation of our businesses, or actions by regulatory or tax authorities. Unfavorable outcomes or developments relating to these proceedings or future proceedings, such as judgments for monetary damages, injunctions or denial or revocation of permits, could have a material adverse effect on our business, financial condition and results of operations. In addition, settlement of claims could adversely affect our business, results of operations, financial condition and cash flows.

Long-term low natural gas prices and/or seasonal natural gas price spreads could have a negative impact on the demand for Gas’ natural gas storage services.

Storage businesses benefit from price volatility and temporal price spreads, which impacts the level of demand for services and the rates that can be charged for natural gas storage services. On a system-wide basis, natural gas is typically injected into storage between April and October when natural gas prices are generally lower and withdrawn during the winter months of November through March when natural gas prices are typically higher. Largely due to the abundant supply of natural gas made available by hydraulic fracturing techniques, natural gas prices have dropped significantly to levels that are near historic lows. If prices and volatility remain low or prices decline further, then the demand for natural gas storage services, and the prices that Gas will be able to charge for those services, may decline or be depressed for a prolonged period of time. A sustained decline in these prices and volatility could have an adverse impact on our business, results of operation, financial condition and cash flows. Furthermore, low gas prices drive down electricity prices and may lower prices in certain power markets, which may have a potentially adverse impact on prices for uncontracted generation and future PPAs for our businesses.

Storing and transporting natural gas involves inherent risks that could cause us to incur significant financial losses.

There are inherent hazards and operation risks in gas distribution activities, such as leaks, accidental explosions and mechanical problems that could cause the loss of human life, significant damage to property, environmental pollution and impairment of operations. The location of pipelines and storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages resulting from these risks. These activities may subject us to litigation and administrative proceedings that could result in substantial monetary judgments, fines or penalties. To the extent that the occurrence of any of these events is not fully covered by insurance, they could adversely affect our revenue, earnings and cash flow.

We are not able to insure against all potential risks and may become subject to higher insurance premiums, and our ability to obtain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers.

Our businesses and activities are exposed to the risks inherent in the construction and operation of their respective assets, such as electrical power plants, wind power plants and other renewable energy projects and natural gas storage facilities, including breakdowns, manufacturing defects, natural disasters, terrorist attacks, cyber attacks and sabotage. Our subsidiaries are also exposed to third party liability risks and environmental risks. While our operating subsidiaries maintain insurance coverage, such insurance may not continue to be offered on an economically feasible basis and may not cover all events that could give rise to a loss or claim involving the assets or operations of our subsidiaries. For example, Renewables currently has 409 megawatts, or MW, of installed capacity in California subject to known earthquake risks and approximately 600 MW of installed capacity on the Texas Gulf Coast subject to known hurricane and windstorm risks. Further, while insurance coverage applies to property damages and business interruptions, this coverage is limited as a result of severe insurance market restrictions and we are generally not fully insured against all significant losses. In addition, our subsidiaries’ insurance policies are subject to annual review by their insurers. Our ability to obtain insurance and the terms of any available insurance coverage could be materially adversely affected by international, national, state or local events and company-specific events, as well as the financial condition of insurers. If insurance coverage is not available or obtainable on acceptable terms, we may be required to pay costs associated with adverse future events. If one of our operating subsidiaries were to incur a serious uninsured loss or a loss significantly exceeding the limits of their insurance policies, the results could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Furthermore, Networks’ gas distribution activities and Gas’ natural gas storage activities involve a variety of inherent hazards and operating risks, such as leaks, accidents, explosions, and mechanical problems and could result in serious injury to employees and non-employees, loss of human life, significant damage to property, environmental pollution and impairment of our subsidiaries’ operations. In accordance with customary industry practice, our subsidiaries maintain insurance against some, but not all, of these risks and losses. The location of natural gas pipelines and natural gas storage facilities near populated areas, including residential areas, commercial business centers and industrial sites, could increase the level of damages that could potentially result from these risks. The occurrence of any of these events not fully covered by insurance could adversely affect our business, results of operations, financial position and cash flows.

The benefits of any warranties provided by the suppliers of equipment for Networks and Renewables’ projects may be limited by the ability of a supplier to satisfy its warranty obligations, or if the term of the warranty has expired or has liability limits.

Networks and Renewables expect to benefit from various warranties, including product quality and performance warranties, provided by suppliers in connection with the purchase of equipment. The suppliers of our operating subsidiaries may fail to fulfill their warranty obligations or a particular defect may not be covered by a warranty. Even if a supplier fulfills its obligations, the warranty may not be sufficient to compensate the operating subsidiary for all of its losses. In addition, these warranties generally expire within two to five years after the date each equipment item is delivered or commissioned and are subject to liability limits. If installation is delayed, the operating subsidiaries may lose all or a portion of the benefit of a warranty. If Networks or Renewables seeks warranty protection and a supplier is unable or unwilling to perform its warranty obligations, whether as a result of its financial condition or otherwise, or if the term of the warranty has expired or a liability limit has been reached, there may be a reduction or loss of warranty protection for the affected equipment, which could have a material adverse effect on our business, results of operation, financial condition and cash flows.

A disruption in the wholesale energy markets or failure by an energy supplier could adversely affect us.

Almost all the electricity and gas Networks sells to full-service customers is purchased through the wholesale energy markets or pursuant to contracts with energy suppliers. A disruption in the wholesale energy markets or a failure on the part of energy suppliers or operators of energy delivery systems that connect to Networks’ energy facilities could adversely affect Networks’ ability to meet its customers’ energy needs and adversely affect us.

The increased cost of purchasing natural gas during periods in which natural gas prices are rising significantly could adversely impact our earnings and cash flow.

The rates that are permitted to be charged by our regulated utilities that allow for rate recovery generally allow such businesses to recover their cost of purchasing natural gas. In general, the various regulatory agencies allow our regulated utilities to recover the costs of natural gas purchased for customers on a dollar-for-dollar basis (in the absence of disallowances), without a profit component. Networks’ regulated utilities periodically adjust customer rates for increases and decreases in the cost of gas purchased by Networks’ regulated utilities for sale to its customers. Under the regulatory body-approved gas cost recovery pricing mechanisms, the gas commodity charge portion of gas rates charged to customers may be adjusted upward on a periodic basis. If the cost of purchasing natural gas increases and Networks’ regulated utilities is unable to recover these costs from its customers immediately, or at all, Networks may incur increased costs associated with higher working capital requirements. In addition, any increases in the cost of purchasing natural gas may result in higher customer bad debt expense for uncollectible accounts and reduced sales volume and related margins due to lower customer consumption.

Renewables owns, and in the future may acquire, certain projects in joint ventures, and such joint venture partners’ interests may conflict with our and our shareholders’ interests.

Renewables owns, and in the future may acquire, certain projects in joint ventures. For example, Renewables owns 50% of the Flat Rock Windpower LLC and Flat Rock Wind Power II LLC projects, which are jointly owned and operated with Horizon Wind Energy LLC. Renewables also owns 50% of Colorado Wind Ventures LLC in conjunction with Shell Wind Energy Inc. Under these structured institutional partnership investment arrangements, a variety of third-party institutional investors invest in the equity of a holding company that owns wind farm facilities. In return, the investors receive profit/loss, cash distributions and tax benefits resulting from the wind farm energy generation. In each of these cases, a non-controlling stake is offered and the company retains total control of the operations of the facilities.

In the future, Renewables may invest in other projects with a joint venture partner. Joint ventures inherently involve a lesser degree of control over business operations, which could result in an increase in the financial, legal, operational or compliance risks associated with a project, including, but not limited to, variances in accounting and internal control requirements. To the extent Renewables does not have a controlling interest in a project, Renewables’ joint venture partners could take actions that decrease the value of Renewables’ investment and lower its overall return. In addition, conflicts of interest may arise in the future between us, Renewables and our shareholders, on the one hand, and the joint venture partners of Renewables, on the other hand, where Renewables’ joint venture partners’ business interests are inconsistent with our interests and the interests of Renewables and our shareholders. Further, disagreements or disputes between Renewables and its joint venture partners could result in litigation, which could increase expenses and potentially limit the time and effort Renewables’ officers and directors are able to devote to its business, all of which could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Pension and post-retirement benefit plans could require significant future contributions to such plans.

We provide defined benefit pension plans and other post-retirement benefits administered by our subsidiaries for a significant number of employees, former employees and retirees. Financial market disruptions and significant declines in the market values of the investments held to meet the pension and post-retirement obligations, discount rate assumptions, participant demographics and increasing longevity, and changes in laws and regulations may require us to make significant contributions to the plans. Large funding requirements or significant increases in expenses could adversely impact our business, results of operations, financial condition and cash flows.

If we and/or certain of our subsidiaries fail to maintain our credit ratings, our cost of long-term debt and equity capital may increase and preclude access to the debt and equity capital markets.

We, NYSEG, RGE and CMP are parties to revolving credit facilities which contain facility fees and borrowing spread pricing that are a function of the credit rating of the borrower. A lower credit rating automatically increases the cost of these facilities. A downgrade to the lowest investment grade rating of the borrower would likely preclude access to the commercial paper market for NYSEG and CMP, which each have commercial paper programs. Lower credit ratings increase the cost of long-term debt and equity capital and, depending on the rating and market conditions, can preclude access to the debt and equity capital markets. Any of these events could have a materially adverse effect on our business, results of operations, financial condition and cash flows.

Our existing credit facilities contain, and agreements that we may enter into in the future may contain, covenants that could restrict our financial flexibility.

Our existing credit facilities, and the credit facilities of our subsidiaries, contain covenants imposing certain requirements on our business including covenants regarding the ratio of indebtedness to total capitalization. Furthermore, our subsidiaries periodically issue long-term debt, historically consisting of both secured and unsecured indebtedness. These third-party debt agreements also contain covenants, including covenants regarding the ratio of indebtedness to total capitalization. These requirements may limit our ability and the ability of our subsidiaries to take advantage of potential business opportunities as they arise and may adversely affect our conduct and our operating subsidiaries’ current business, including restricting our ability to finance future operations and capital needs and limiting the subsidiaries’ ability to engage in other business activities. Other covenants place or could place restrictions on our ability and the ability of our operating subsidiaries to, among other things:

•

incur additional debt or issue some types of preferred shares;

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create liens;

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enter into transactions with affiliates;

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sell or transfer assets; and

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consolidate or merge

Agreements we and our operating subsidiaries enter into in the future may also have similar or more restrictive covenants, especially if the general credit market deteriorates. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration of payment of the underlying obligations or may trigger acceleration of payment if not remedied within a specified period. Events of default under one agreement may trigger events of default under other agreements, although our regulated utilities are not subject to the risk of default of affiliates. Should payments become accelerated as the result of an event of default, the principal and interest on such borrowing would become due and payable immediately. If that should occur, we may not be able to make all of the required payments or borrow sufficient funds to refinance the accelerated debt obligations. Even if new financing were then available, it may not be on terms that are acceptable to us.

We may be unable to meet our financial obligations and to pay dividends on our common stock if our subsidiaries are unable to pay dividends or repay loans from us.

We are a holding company and, as such, have no revenue-generating operations of our own. We are dependent on dividends and the repayment of loans from our subsidiaries and on external financings to provide the cash that is necessary to make future investments, service debt we have incurred, pay administrative costs and pay dividends. Our subsidiaries are separate legal entities and have no independent obligation to pay us dividends. Prior to paying us dividends, the subsidiaries have financial obligations that must be satisfied, including among others, their operating expenses and obligations to creditors. Furthermore, our regulated utilities

are required by regulation to maintain a minimum equity-to-total capital ratio that may restrict their ability to pay dividends to IUSA or may require that we contribute capital. The future enactment of laws or regulations may prohibit or further restrict the ability of our subsidiaries to pay upstream dividends or to repay funds. In addition, in the event of a subsidiary’s liquidation or reorganization, our right to participate in a distribution of assets is subject to the prior claims of the subsidiary’s creditors. As a result, our ability to pay dividends on our common stock and meet our financial obligations is reliant on the ability of our subsidiaries to generate sustained earnings and cash flows and pay dividends to and repay loans from us.

Our investments and cash balances are subject to the risk of loss.

Our cash balances and cash balances at our subsidiaries may be deposited in banks, may be invested in liquid securities such as commercial paper or money market funds or may be deposited in a cash pooling account in which we are a participant along with other affiliates of the Iberdrola Group. Bank deposits in excess of federal deposit insurance limits would be subject to risks in the counter-party bank. Liquid securities and money market funds are subject to loss of principal, more likely in an adverse market situation, and to the risk of illiquidity. Moreover, under the cash pooling agreement governing the cash pooling account mentioned above, credit balances in the cash pooling account are pledged as collateral for the debit balances of other cash pooling participants. We are therefore subject to the credit risk of the affiliated parties to the cash pooling agreement and to Iberdrola’s ability to manage the overall liquidity of the Iberdrola Group.

We and our subsidiaries may suffer the loss of key personnel or the inability to hire and retain qualified employees.

The operations of our operating subsidiaries depend on the continued efforts of our employees and our subsidiaries’ employees. Retaining key employees and maintaining the ability to attract new employees are important to our financial performance and for our subsidiaries’ operations and financial performance. We cannot guarantee that any member of our management or of our subsidiaries’ management will continue to serve in any capacity for any particular period of time. In addition, a significant portion of our and our subsidiaries’ workforce, including many workers with specialized skills maintaining and servicing the electrical infrastructure, will be eligible to retire over the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform. We and our subsidiaries cannot predict the impact of these plans on the ability to hire and retain key employees.

We and our subsidiaries face the risk of strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms.

A majority of the employees at Networks’ facilities are subject to collective bargaining agreements with various unions. Additionally, unionization activities, including votes for union certification, could occur among non-union employees. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strike or disruption, our subsidiaries could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor is uncertain, though risks are reduced by rigorous contingency planning. Strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms could have a material adverse effect on our business, results of operations, financial condition and cash flows.

Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could materially adversely affect our business, results of operations, financial condition and cash flows.

Our provision for income taxes and reporting of tax-related assets and liabilities require significant judgments and the use of estimates. Amounts of tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions and tax credits, including, but not limited to, estimates for potential adverse outcomes regarding tax positions that have been taken and the ability to utilize tax benefit carryforwards, such as net operating loss, or NOL, and tax credit carryforwards. Actual income taxes could vary significantly from estimated amounts due to the future impacts of, among other things, changes in tax

laws, regulations and interpretations, our financial condition and results of operations, and the resolution of audit issues raised by taxing authorities. Ultimate resolution of income tax matters may result in material adjustments to tax-related assets and liabilities, which could materially adversely affect our business, results of operations, financial conditions and cash flows.

Item 2. Unregistered Sales of Equity Securities and Use of Proceeds.

None.

Item 3. Defaults Upon Senior Securities.

None.

Item 4. Mine Safety Disclosures.

Not applicable.

Item 5. Other Information.

None.

Item 6. Exhibits

The following documents are included as exhibits to this Form 10-Q:


Exhibit Number		Description

31.1		Chief Corporate Officer Certification pursuant to Rule 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

31.2		Chief Financial Officer Certification pursuant to Rule 13a-14(a) and 15d-14(a), as adopted pursuant to Section 302 of the Sarbanes-Oxley Act of 2002.

32.1		Certification pursuant to 18 United States Code Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.

101.INS		XBRL Instance Document.

101.SCH		XBRL Taxonomy Extension Schema Document.

101.CAL		XBRL Taxonomy Extension Calculation Linkbase Document.

101.DEF		XBRL Taxonomy Extension Definition Linkbase Document.

101.LAB		XBRL Taxonomy Extension Label Linkbase Document.

101.PRE		XBRL Taxonomy Extension Presentation Linkbase Document.

SIGNATURES

Pursuant to the requirements of the Securities Exchange Act of 1934, the registrant has duly caused this report to be signed on its behalf by the undersigned thereunto duly authorized.