Avangrid (AGR) 10-Q 2016 Q2 Quarterly report

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 June 30, 2016

Or

o 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

Avangrid, Inc.

(Exact name of registrant as specified in this charter)

New York	14-1798693
(State of Incorporation)	(I.R.S. Employer Identification No.)
157 Church Street New Haven, Connecticut	06506
(Address of principal executive offices)	(Zip Code)

Telephone: (207) 688-6000

(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  x    No  o

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  o

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):  

Large accelerated filer	o		Accelerated filer	o
Non-accelerated filer	x	(Do not check if a smaller reporting company)	Smaller reporting company	o

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

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 309,003,589 shares of common stock, par value $0.01, were outstanding as of August 1, 2016.

Avangrid, Inc.

REPORT ON FORM 10-Q

For the Quarter Ended June 30, 2016

INDEX

GLOSSARY OF TERMS AND ABBREVIATIONS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	42
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	60
Item 4.	Controls and Procedures	60
PART II. OTHER INFORMATION		61
Item 1.	Legal Proceedings	61
Item 1A.	Risk Factors	61
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds.	61
Item 3.	Defaults Upon Senior Securities.	61
Item 4.	Mine Safety Disclosures.	61
Item 5.	Other Information.	61
Item 6.	Exhibits	61
SIGNATURES		62

2

GLOSSARY OF TERMS AND ABBREVIATIONS

Unless the context indicates otherwise, the terms “we,” and “our” are used to refer to AVANGRID and its subsidiaries.

Form 10-K refers to Avangrid, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2015, filed with the Securities and Exchange Commission on April 1, 2016.

Ginna refers to the Ginna Nuclear Power Plant, LLC and the R.E. Ginna Nuclear Power Plant.

Iberdrola Group refers to the group of companies controlled by Iberdrola, S.A.

Iberdrola refers to Iberdrola, S.A., the 81.5% controlling parent company of Avangrid, Inc.

Installed capacity refers to the production capacity of a power plant or wind farm based either on its rated (nameplate) capacity or actual capacity.

ARHI	Avangrid Renewables Holdings, Inc.
ASC	Accounting Standards Codification
AVANGRID	Avangrid, Inc.
Bcf	One billion cubic feet
BGC	The Berkshire Gas Company
BMG	Bank Mendes Gans, N.V.
Cayuga	Cayuga Operating Company, LLC
CMP	Central Maine Power Company
CNG	Connecticut Natural Gas Corporation
EBITDA	Earnings before interest, taxes, depreciation and amortization
Exchange Act	The Securities Exchange Act of 1934, as amended
FirstEnergy	FirstEnergy Corp.
Gas	Enstor Gas, LLC
ISO	Independent system operator
MNG	Maine Natural Gas Corporation
MPUC	Maine Public Utility Commission
MtM	Mark-to-market
MW	Megawatts
MWh	Megawatt-hours
Networks	Avangrid Networks, Inc.
NYPSC	New York State Public Service Commission
NYSEG	New York State Electric & Gas Corporation
Renewables	Avangrid Renewables LLC
RGE	Rochester Gas and Electric Corporation
ROE	Return on equity
RSSA	Reliability Support Services Agreement
SCG	The Southern Connecticut Gas Company
SEC	United States Securities and Exchange Commission
UI	The United Illuminating Company
UIL	UIL Holdings Corporation
U.S. GAAP	Generally accepted accounting principles for financial reporting in the United States.

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(unaudited)

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

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

4

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(Millions)
Net Income	$	102		$	11		$	314		$	117
Other Comprehensive Income, Net of Tax
Amounts arising during the period:
Gain (loss) on defined benefit plans, net of income taxes    of $0.1 and $(0.1) for the three months ended and $2.9    and $(1.0) for the six months ended, respectively		—			(1	)		4			(2	)
Unrealized (loss) gain during the period on derivatives qualifying    as cash flow hedges, net of income taxes of $(14.2) and    $0.4 for the three months ended and $(13.0) and $0.4 for    the six months ended, respectively		(23	)		1			(21	)		1
Reclassification to net income of (gains) losses on cash flow    hedges, net of income taxes of $0.7 and $1.2 for the    three months ended and $(15.9) and $2.2 for the six    months ended, respectively		1			2			(25	)		4
Other Comprehensive (Loss) Income		(22	)		2			(42	)		3
Comprehensive Income		80			13			272			120
Less: Net income attributable to noncontrolling interests		—			—			—			—
Comprehensive Income Attributable to Avangrid, Inc.	$	80		$	13		$	272		$	120

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

5

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	June 30,			December 31,
As of	2016			2015
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	396		$	427
Accounts receivable and unbilled revenues, net		894			974
Accounts receivable from affiliates		66			70
Notes receivable from affiliates		4			6
Derivative assets		88			88
Fuel and gas in storage		230			307
Materials and supplies		106			98
Prepayments and other current assets		179			285
Regulatory assets		272			219
Total Current Assets		2,235			2,474
Property, plant and equipment, at cost		26,187			25,745
Less: accumulated depreciation		(6,722	)		(6,372	)
Net Property, Plant and Equipment in Service		19,465			19,373
Construction work in progress		1,365			1,338
Total Property, Plant and Equipment		20,830			20,711
Equity method investments		371			385
Other investments		54			64
Regulatory assets		3,141			3,314
Other Assets
Goodwill		3,113			3,115
Intangible assets		547			556
Derivative assets		73			89
Other		47			35
Total Other Assets		3,780			3,795
Total Assets	$	30,411		$	30,743

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

6

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	June 30,			December 31,
As of	2016			2015
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	168		$	206
Tax equity financing arrangements		107			107
Notes payable		3			163
Interest accrued		60			61
Accounts payable and accrued liabilities		814			830
Accounts payable to affiliates		75			90
Dividends payable		133			—
Taxes accrued		50			55
Derivative liabilities		87			91
Other current liabilities		242			285
Regulatory liabilities		183			147
Total Current Liabilities		1,922			2,035
Regulatory liabilities		1,723			1,841
Deferred income taxes regulatory		521			519
Other Non-current Liabilities
Deferred income taxes		2,890			2,798
Deferred income		1,518			1,553
Pension and other postretirement		1,190			1,202
Tax equity financing arrangements		132			185
Derivative liabilities		98			94
Asset retirement obligations		165			184
Environmental remediation costs		383			406
Other		297			330
Total Other Non-current Liabilities		6,673			6,752
Non-current Debt		4,507			4,530
Total Non-current Liabilities		13,424			13,642
Total Liabilities		15,346			15,677
Commitments and Contingencies		—			—
Equity
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,592,620 and    309,491,082 shares issued; 309,003,589 and 308,864,609 shares outstanding,    respectively		3			3
Additional paid in capital		13,651			13,653
Treasury Stock		(4	)		—
Retained earnings		1,496			1,449
Accumulated other comprehensive loss		(94	)		(52	)
Total Stockholders’ Equity		15,052			15,053
Non-controlling interests		13			13
Total Equity		15,065			15,066
Total Liabilities and Equity	$	30,411		$	30,743

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

7

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

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

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

8

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Changes in Equity

(unaudited)

	Avangrid, Inc. Stockholders
(Millions, except for number of shares )	Number of shares (*)			Common Stock		Additional paid-in capital			Treasury Stock			Retained Earnings			Accumulated Other Comprehensive Income (Loss)			Total Stockholders’ Equity			Non controlling Interests		Total
As of December 31, 2014		252,235,232		$	3	$	11,375		$	—		$	1,182		$	(99	)	$	12,461		$	16	$	12,477
Net Income		—			—		—			—			117			—			117			—		117
Other comprehensive income, net of tax of $1.6		—			—		—			—			—			3			3			—		3
Comprehensive income																								120
As of June 30, 2015		252,235,232		$	3	$	11,375		$	—		$	1,299		$	(96	)	$	12,581		$	16	$	12,597
As of December 31, 2015		308,864,609		$	3	$	13,653		$	—		$	1,449		$	(52	)	$	15,053		$	13	$	15,066
Net Income		—			—		—			—		314				—			314			—		314
Other comprehensive (loss), net of tax of $(26.0)		—			—		—			—			—			(42	)		(42	)		—		(42	)
Comprehensive income																								272
Dividends declared		—			—		—			—			(267	)		—			(267	)		—		(267	)
Release of common stock held in trust		134,921			—		—			—			—			—			—			—		—
Issuance of common stock		101,538			—		(2	)		—			—			—			(2	)		—		(2	)
Repurchase of common stock		(97,479	)		—		—			(4	)		—			—			(4	)		—		(4	)
As of June 30, 2016		309,003,589		$	3	$	13,651		$	(4	)	$	1,496		$	(94	)	$	15,052		$	13	$	15,065

(*) Par value of share amounts is $0.01

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

9

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Note 1. Background and Nature of Operations

Avangrid, Inc., formerly Iberdrola USA, Inc. (AVANGRID, we or the Company), is an energy services holding company engaged in the regulated energy distribution business through its principal subsidiary Avangrid Networks, Inc. (Networks). Effective as of April 30, 2016, UIL Holdings Corporation and its subsidiaries (UIL) were transferred to a wholly-owned subsidiary of Networks. AVANGRID is also in the renewable energy generation and gas storage and trading businesses through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables LLC (Renewables) and Enstor Gas, LLC (Gas). AVANGRID is an 81.5% owned subsidiary of Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. AVANGRID was organized in 1997 as NGE Resources, Inc. under the laws of New York as the holding company for the principal operating utility companies.

During the six months ended June 30, 2016, we completed the sale of our interest in Iroquois Gas Transmission System L.P. (Iroquois) to an unaffiliated third party for proceeds of $53.8 million and an impact to net income of $19.0 million.

Note 2. Basis of Presentation

The accompanying notes should be read in conjunction with the notes to the combined and consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2015 and 2014 and for the three years ended December 31, 2015 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2015.

The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries Networks and ARHI. Consolidated accounts of UIL have been included in the consolidated financial statements of AVANGRID since December 16, 2015, the date of acquisition of UIL. Intercompany accounts and transactions have been eliminated in consolidation. The year-end balance sheet data was derived from audited financial statements. The unaudited condensed consolidated financial statements for the interim periods have been prepared in accordance with accounting principles generally accepted in the United States of America (U.S. GAAP) for interim financial information and with the instructions to Form 10-Q and Article 10 of Regulation S-X. Accordingly, the interim condensed consolidated financial statements do not include all the information and note disclosures required by U.S. GAAP for complete financial statements.

We believe the disclosures made are adequate to make the information presented not misleading. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated balance sheets, condensed consolidated statements of income, comprehensive income, cash flows and changes in equity for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and six months ended June 30, 2016, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2016.

Revision of estimated useful lives of wind power station assets at Renewables

Renewables’ wind power station assets in service less salvage value, if any, are depreciated using the straight-line method over their estimated useful lives. Renewables’ effective depreciation rate, excluding decommissioning, was 4.0% in both 2015 and 2014. Renewables reviews the estimated useful lives of its fixed assets on an ongoing basis. In the first quarter of 2016, this review indicated that the actual lives of certain assets at wind power stations are expected to be longer than the previously estimated useful lives used for depreciation purposes. As a result, effective January 1, 2016, Renewables changed the estimates of the useful lives of certain assets from 25 years to 40 years, capped at the lease term if lower, to better reflect the estimated periods during which these assets are expected to remain in service. The weighted average useful life of our wind farm assets is now approximately 30 years. We are continuing to assess lease extensions with leaseholders to potentially increase the average useful life of our wind farm assets to above 30 years.The effect of this change in estimate was to reduce depreciation and amortization expense by approximately $8 million and $25 million, reduce asset retirement obligation accretion expense recorded within operations and maintenance by approximately $0 and $1 million, increase earnings from equity method investments by approximately $1 million and $2 million, increase net income by $6 million and $18 million and increase basic and diluted earnings per share by approximately $0.02 and $0.06 for the three and six months ended June 30, 2016, respectively. For the full year 2016, the effect of this change on income before

10

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

income tax and net income is estimated to be an increase of approximately $57 million and approximately $35 million, respectively, and the impact on earnings per share is estimated to be an increase of approximately $0.11 per share on a basic and diluted basis.

Note 3. Significant Accounting Policies and New Accounting Pronouncements

As of June 30, 2016, there have been no material changes to any significant accounting policies described in our combined and consolidated financial statements as of December 31, 2015 and 2014 and for the three years ended December 31, 2015. There have been no new accounting pronouncements issued since the filing of the combined and consolidated financial statements as of December 31, 2015 and 2014 and for the three years ended December 31, 2015, that we expect to have a material effect on our condensed consolidated interim financial statements.

Note 4. Acquisition of UIL

On December 16, 2015 (acquisition date), we completed our acquisition of UIL, a diversified energy company with its portfolio of regulated utility companies in Connecticut and Massachusetts that is expected to provide us with a greater flexibility to grow the combined regulated businesses through project development and create an enhanced platform to develop transmission and distribution projects in the Northeastern United States. In connection with the acquisition, we issued 309,490,839 shares of common stock of AVANGRID, out of which 252,234,989 shares were issued to Iberdrola through a stock dividend, accounted for as a stock split, with no change to par value, at par value of $0.01 per share and 57,255,850 shares (including those held in trust as Treasury Stock) were issued to UIL shareowners in addition to payment of $595 million in cash. Following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares.

The acquisition was accounted for as a business combination. This method requires, among other things, that assets acquired and liabilities assumed in a business combination, with certain exceptions, be recognized at their fair values as of the acquisition date.

As UIL’s common stock was publicly traded in an active market until the acquisition date, we determined that UIL’s common stock is more reliably measurable than the common stock of AVANGRID to determine the fair value of the consideration transferred in the transaction.

The purchase consideration for UIL under the acquisition method is based on the stock price of UIL on the acquisition date multiplied by the number of shares issued by AVANGRID to the UIL shareowners after applying an equity exchange factor to the shares of vested restricted common stock of UIL (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other shares awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan. The “equity exchange factor” is the sum of one plus a fraction, (i) the numerator of which is the cash consideration and (ii) the denominator of which is the average of the volume weighted averages of the trading prices of UIL common stock on each of the ten consecutive trading days ending on (and including) the trading day that immediately precedes the closing date of the acquisition minus $10.50. The determination of the purchase price is based on a UIL stock price of $50.10 per share, which represents the closing stock price on the acquisition date.

11

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

The fair value of AVANGRID common stock issued to the UIL shareowners in the business combination represents the purchase consideration in the business combination, which was computed as follows:

	(millions, except share and unit data)
Common shares(1)		56,629,377
Price per share of UIL common stock as of the    acquisition date	$	50.10
Subtotal value of common shares	$	2,837
Restricted stock units(2)		476,198
Other shares(3)		12,999
Equity exchange factor		1.2806
Total restricted and other shares(3) after applying    an equity exchange factor		626,473
Price per share used (5)	$	39.60
Subtotal value of restricted and other shares	$	25
Total shares of AVANGRID common stock issued to UIL    shareowners (including held in trust as Treasury Stock)		57,255,850
Performance shares(4)		211,904
Equity exchange factor		1.2806
Total performance shares after applying an equity    exchange factor		271,368
Price per share used (5)	$	39.60
Subtotal value of performance shares	$	11
Total consideration	$	2,873

(1) Based on UIL’s common shares outstanding on December 16, 2015

(2) Based on UIL’s shares of vested restricted stock.

(3) Based on UIL’s restricted shares vested upon the change in control.

(4) Based on UIL’s vested performance shares award.

(5) Based on the closing share price of UIL common stock on December 16, 2015 less the cash component of $10.50, which is not applicable to restricted shares (other than those UIL restricted shares that vest by their terms upon the consummation of the acquisition), performance shares and other awards under UIL 2008 Stock and Incentive Compensation Plan and the UIL Deferred Compensation Plan.

The following is a summary of the components of the consideration transferred to UIL’s shareowners:

	(millions, except share data)
Cash ($10.50 x number of UIL common shares    outstanding at the acquisition date - 56,629,377)	$	595
Equity		2,278
Total consideration	$	2,873

UIL’s financial results have been included in our consolidated financial results for the periods subsequent to the December 16, 2015 acquisition date. The following table represents summarized unaudited pro forma financial information as if UIL had been included in our financial results for the six months ended June 30, 2015. The unaudited pro forma results include: (i) elimination of accrued transaction costs representing non-recurring expenses directly related to the transaction, and (ii) the associated tax impact on this unaudited pro forma adjustment.

The unaudited pro forma results do not reflect any cost saving synergies from operating efficiencies or the effect of the incremental costs incurred in integrating the two companies. Accordingly, these unaudited pro forma results are presented for informational

12

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

purpose only and are not necessarily indicative of what the actual results of operations of the combined company would have been if the acquisition had occurred at the beginning of the periods presented, nor are they indicative of future results of operations:

	Three Months Ended		Six Months Ended
	June 30, 2015
	(millions)
Revenue	$	1,251	$	3,062
Net income	$	31	$	203

The fair value of assets acquired and liabilities assumed from our acquisition of UIL was based on a preliminary valuation and our estimates and assumptions are subject to change within the measurement period. For the majority of UIL’s assets and liabilities, primarily property, plant and equipment, fair value was determined to be the respective carrying amounts of the predecessor entity. UIL’s operations are conducted in a regulated environment where the regulatory authority allows an approved rate of return on the carrying amount of the regulated asset base. Management is in the process of finalizing our detailed analysis of various items, predominantly non-rate regulated activities, to reflect the fair value of certain assets and liabilities. The primary areas of the purchase price that are not yet finalized include, but are not limited to the allocation of the purchase price to the following: equity method investments; debt; contingent liabilities, including those related to certain environmental sites; income taxes; non-regulated property, plant and equipment and goodwill. We will finalize these amounts no later than December 16, 2016. Under U.S. GAAP, the measurement period shall not exceed one year from the acquisition date. Measurement period adjustments that we determine to be material will be recognized in future periods in our consolidated financial statements.

The following is a summary of the preliminary allocation of the purchase price as of the acquisition date:

	(millions)
Current assets, including cash of $48 million	$	500
Other investments		114
Property, plant and equipment, net		3,552
Regulatory assets		966
Other assets		52
Current liabilities		(493	)
Regulatory liabilities		(493	)
Non-current debt		(1,878	)
Other liabilities		(1,201	)
Total net assets acquired at fair value		1,119
Goodwill – consideration transferred in excess of fair    value assigned		1,754
Total estimated consideration	$	2,873

Goodwill generated from the acquisition of UIL has been assigned to the reporting units under the Networks reportable segment and is primarily attributable to expected future growth of the combined regulated businesses and enhanced platform to develop transmission and distribution projects in the Northeastern United States. The goodwill generated from this acquisition is not deductible for tax purposes. As part of the preliminary allocation of the purchase price we have determined a fair value of contingent liabilities of approximately $44.0 million relating to certain environmental sites.

Note 5. Regulatory Assets and Liabilities

Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific order we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. Substantially all assets or liabilities for which funds have been expended or received

13

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

are either included in the rate base or are accruing a carrying cost until they will be included in the rate base. The primary items that are not included in the rate base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses, debt premium, environmental remediation costs which is primarily the offset of accrued liabilities for future spending, unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded, asset retirement obligations, hedge losses and contracts for differences. The total amount of these items is $2,751 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.

On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal (Proposal) in connection with a three-year rate plan for electric and gas service at New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RGE) effective May 1, 2016. Following the approval of the Proposal most of these items related to NYSEG are amortized over a five-year period, except the portion of storm costs to be recovered over ten years, plant related tax items which are amortized over the life of associated plant. Annual amortization expense for NYSEG is approximately $16.5 million per rate year. RGE items that are being amortized are plant related tax items, which are amortized over the life of associated plant, and unfunded deferred taxes being amortized over a period of fifty years. A majority of the other items related to RGE, which net to a regulatory liability, remains deferred and will not be amortized until future proceedings or will be used to recover costs of the Ginna Reliability Support Services Agreement (Ginna RSSA).

In the approved Proposal the allowed rate of return on common equity is 9.0% for all companies. The equity ratio for each company is 48%; however the equity ratio is set at 50% for earnings sharing purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% ROE, respectively, in the first year. The rate plans also include the implementation of a rate adjustment mechanism designed to return or collect certain defined reconciled revenues and costs; new depreciation rates; and continuation of the existing revenue decoupling mechanisms for each business. Following the approval of the Proposal by the NYPSC, unfunded future income taxes were adjusted for the amount of $126 million to reflect the change from a flow through to normalization method, which has been recorded as an increase to income tax expense and an offsetting increase to revenue, for the three and six month periods ended June 30, 2016. The amounts will be collected over a period of fifty years.

On July 1, 2016, the United Illuminating Company (UI) filed an application with the Connecticut Public Utilities Regulatory Authority (PURA) requesting approval of a three-year rate plan commencing January 1, 2017, and extending through December 31, 2019. We expect PURA to rule on UI’s rate request in December 2016. UI’s application requests an increase of $65.6 million in 2017, an additional $21.1 million in 2018, and an additional $13.4 million in 2019. The application includes a rate levelization proposal to moderate the customer impact of the necessary revenue increases. The proposal defers a portion of the first and second year increases and spreads recovery of the overall increase by approximately equivalent amounts over the three years of the rate plan with carrying charges included. The proposal results in levelized revenue requirement increases of $40.7 million in 2017, $47.4 million in 2018 and $39.1 million in 2019, followed by an offset of $25.6 million at the end of the three year rate plan to equate the levelized recovery to the non-levelized revenue requirement increase.

UI’s rate request is attributable primarily to the amount of capital expenditures devoted to the company’s electric distribution system for the purpose of reliability and system resiliency, both in relation to routine operations and during major storm events. UI’s application also proposes continuation of its revenue decoupling mechanism and proposes a new earnings sharing mechanism (ESM). Under the proposed ESM, 50% of UI’s earnings in excess of the allowed ROE, plus a deadband above the allowed ROE, would be flowed through to the benefit of customers. The proposed ESM includes a 20-basis point deadband in 2017 above the authorized ROE, within which there would be no sharing.  This deadband would be 30 basis points in 2018 and 40 basis points in 2019. UI proposes to continue applying any dollars due to customers to reduce the storm regulatory asset, if one exists. If none exists, then the customer share would be provided through a bill credit.

14

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Current and non-current regulatory assets as of June 30, 2016 and December 31, 2015, respectively, consisted of:

	June 30,		December 31,
As of	2016		2015
(Millions)
Current
Pension and other post-retirement benefits cost deferrals	$	22	$	8
Pension and other post-retirement benefits		7		13
Storm costs		40		8
Temporary supplemental assessment surcharge		5		7
Reliability support services		18		—
Revenue decoupling mechanism		17		6
Hedges losses		4		37
Contracts for differences		18		18
Hardship programs		16		13
Deferred property tax		10		—
Plant decommissioning		7		—
Deferred purchased gas		1		12
Deferred transmission expense		23		12
Environmental remediation costs		17		37
Other		67		48
Total Current Regulatory Assets		272		219
Non-current
Pension and other post-retirement benefits cost deferrals		147		151
Pension and other post-retirement benefits		1,449		1,509
Storm costs		207		251
Deferred meter replacement costs		33		34
Unamortized losses on reacquired debt		21		23
Environmental remediation costs		273		271
Unfunded future income taxes		494		549
Asset retirement obligation		19		24
Deferred property tax		40		45
Federal tax depreciation normalization adjustment		163		158
Merger capital expense target customer credit		12		15
Debt premium		129		141
Contracts for differences		71		50
Hardship programs		21		29
Other		62		64
Total Non-current Regulatory Assets	$	3,141	$	3,314

“Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses. “Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. The recovery of these amounts will be determined in future proceedings.

“Storm costs” for Central Maine Power (CMP), NYSEG and RGE are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. The portion of storm costs for the amount of $123 million is being recovered over ten-year period and the remaining portion is being amortized over five years following the approval of the Proposal by the NYPSC. UI is allowed to defer costs associated with any storm totaling $1 million or greater for future recovery. UI’s storm regulatory asset balance was $0 as of June 30, 2016.

“Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced by advanced metering infrastructure meters. This amount is being amortized over the initial depreciation period of related retired meters.

15

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

“Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt.

“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. Following the approval of the Proposal by the NYPSC, these amounts will be collected over a period of fifty years.

“Asset retirement obligations” (ARO) represent the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.

“Deferred property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The New York (NY) amount is being amortized over a five year period following the approval of the Proposal by the NYPSC.

“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rates years covering 2011 forward. The recovery period in NY is from 27 to 39 years and for CMP this will be determined in future Maine Public Utility Commission (MPUC) rate proceedings.

“Hardship Programs” represent hardship customer accounts deferred for future recovery to the extent they exceed the amount in rates.

“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.

“Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base.

“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts.  The balance fluctuates based upon quarterly market analysis performed on the related derivatives. The amounts, which do not earn a return, are fully offset by a corresponding derivative asset/liability.

“Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments.

“Deferred Transmission Expense” represents deferred transmission income or expense and fluctuates based upon actual revenues and revenue requirements.

16

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Current and non-current regulatory liabilities as of June 30, 2016 and December 31, 2015, respectively, consisted of:

	June 30,		December 31,
As of	2016		2015
(Millions)
Current
Reliability support services (Cayuga)	$	10	$	16
Non by-passable charges		6		7
Energy efficiency portfolio standard		40		33
Gas supply charge and deferred natural gas cost		12		6
Transmission revenue reconciliation mechanism		13		16
Pension and other post-retirement benefits		17		3
Carrying costs on deferred income tax bonus depreciation		15		—
Yankee DOE Refund		—		5
Merger related rate credits		—		20
Revenue decoupling mechanism		22		14
Other		48		27
Total Current Regulatory Liabilities		183		147
Non-current
Accrued removal obligations		1,107		1,084
Asset sale gain account		9		8
Carrying costs on deferred income tax bonus depreciation		101		116
Economic development		36		36
Merger capital expense target customer credit account		15		17
Pension and other post-retirement benefits		78		90
Positive benefit adjustment		43		51
New York state tax rate change		10		17
Post term amortization		3		25
Theoretical reserve flow thru impact		27		31
Deferred property tax		18		15
Net plant reconciliation		10		10
Variable rate debt		30		32
Carrying costs on deferred income tax - Mixed Services    263(a)		28		31
Rate refund – FERC ROE proceeding		21		21
Merger-related rate credits		24		24
Accumulated deferred investment tax credits		12		10
Asset retirement obligation		13		13
Middletown/Norwalk local transmission network service collections		19		19
Excess generation service charge		—		21
Low income programs		45		42
Unfunded future income taxes		—		27
Non-firm margin sharing credits		11		8
Deferred income taxes regulatory		521		519
Other		63		93
Total Non-current Regulatory Liabilities	$	2,244	$	2,360

“Reliability support services (Cayuga)” represents the difference between actual expenses for reliability support services and the amount provided for in rates. This will be refunded to customers within the next year.

“Non by-passable charges” represent the non by-passable charge paid by all customers. An asset or liability is recognized resulting from differences between actual revenues and the underlying cost being recovered. This liability will be refunded to customers within the next year.

17

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

“Energy efficiency portfolio standard” represents the difference between revenue billed to customers through an energy efficiency charge and the costs of our energy efficiency programs as approved by the state authorities. This may be refunded to customers within the next year.

“Accrued removal obligations” represent the differences between asset removal costs recorded and amounts collected in rates for those costs. The amortization period is dependent upon the asset removal costs of underlying assets and the life of the utility plant.

“Asset sale gain account” represents the gain on NYSEG’s 2001 sale of its interest in Nine Mile Point 2 nuclear generating station. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five years following the approval of the Proposal by the NYPSC.

“Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. The amortization period is five years following the approval of the Proposal by the NYPSC

“Economic development” represents the economic development program which enables NYSEG and RGE to foster economic development through attraction, expansion, and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RGE varies in any rate year from the level provided for in rates, the difference is refunded to ratepayers. The amortization period is five years following the approval of the Proposal by the NYPSC.

“Merger capital expense target customer credit” account was created as a result of NYSEG and RGE not meeting certain capital expenditure requirements established in the order approving the purchase of Energy East by Iberdrola. The amortization period is five years following the approval of the Proposal by the NYPSC.

“Pension and other postretirement benefits” represent the actuarial gains on other postretirement plans that will be reflected in customer rates when they are amortized and recognized in future expenses. Because no funds have yet been received for this a regulatory liability is not reflected within rate base. They also represent the difference between actual expense for pension and other postretirement benefits and the amount provided for in rates. Recovery of these amounts will be determined in future proceedings.

“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of Energy East. This is being used to moderate increases in rates. The amortization period is five years following the approval of the Proposal by the NYPSC and included in the Ginna RSSA settlement.

“New York state tax rate change” represents excess funded accumulated deferred income tax balance caused by the 2014 New York state tax rate change from 7.1% to 6.5%. The amortization period is five years following the approval of the Proposal by the NYPSC.

“Post term amortization” represents the revenue requirement associated with certain expired joint proposal amortization items. The amortization period is five years following the approval of the Proposal by the NYPSC.

“Theoretical reserve flow thru impact” represents the differences from the rate allowance for applicable federal and state flow through impacts related to the excess depreciation reserve amortization. It also represents the carrying cost on the differences. The amortization period is five years following the approval of the Proposal by the NYPSC.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. In the three and six month period ended June 30, 2016, respectively, $0 and $20 million of rate credits was applied against customer bills.

“Excess generation service charge” represents deferred generation-related and non by-passable federally mandated congestion costs or revenues for future recovery from or return to customers.  The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.

“Low Income Programs” represent various hardship and payment plan programs approved for recovery.

“Other” includes cost of removal being amortized through rates and various items subject to reconciliation including variable rate debt, Medicare subsidy benefits and stray voltage collections.

18

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Note 6. Fair Value of Financial Instruments and Fair Value Measurements

We determine the fair value of our derivative assets and liabilities and available for sale non-current investments associated with Networks’ activities utilizing market approach valuation techniques:

· We measure the fair value of our noncurrent investments using quoted market prices in active markets for identical assets and include the measurements in Level 1. The available for sale investments, which are Rabbi Trusts for deferred compensation plans, primarily consist of money market funds and are included in Level 1 fair value measurement.

· NYSEG and RGE enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the New York Independent System Operator (NYISO). RGE hedges all its electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value RGE’s open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. NYSEG has a combination of Level 1 and Level 2 fair values for its electric energy derivative contracts. A portion of its electric load obligations are exchange traded contracts in a NYISO location where an active market exists. The forward market prices used to value NYSEG’s open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1. A portion of NYSEG’s electric energy derivative contracts are non-exchange traded contracts that are valued using inputs that are directly observable for the asset or liability, or indirectly observable through corroboration with observable market data and therefore we include the fair value in Level 2.

· NYSEG and RGE enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). Because we use prices quoted in an active market we include the fair value measurements in Level 1.

· NYSEG, RGE and CMP enter into fuel derivative contracts to hedge their unleaded and diesel fuel requirements for their fleet vehicles. Exchange-based forward market prices are used but because an unobservable basis adjustment is added to the forward prices we include the fair value measurement for these contracts in Level 3.

· Contracts for differences (CfDs) entered into by The United Illuminating Company (UI) are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion on CfDs).

We determine the fair value of our derivative assets and liabilities associated with Renewables and Gas activities utilizing market approach valuation techniques. Exchange-traded transactions, such as NYMEX futures contracts, that are based on quoted market prices in active markets for identical product with no adjustment are included in the Level 1 fair value. Contracts with delivery periods of two years or less which are traded in active markets and are valued with or derived from observable market data for identical or similar products such as over-the-counter NYMEX, foreign exchange swaps, and fixed price physical and basis and index trades are included in Level 2 fair value. Contracts with delivery periods exceeding two years or that have unobservable inputs or inputs that cannot be corroborated with market data for identical or similar products are included in Level 3 fair value. The unobservable inputs include historical volatilities and correlations for tolling arrangements and extrapolated values for certain power swaps. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.

19

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

The financial instruments measured at fair value as of June 30, 2016 and December 31, 2015, respectively, consisted of:

As of June 30, 2016	Level 1			Level 2			Level 3			Netting			Total
(Millions)
Securities portfolio (available for sale)	$	41		$	—		$	—		$	—		$	41
Derivative assets
Derivative financial instruments - power		19		48			52				(54	)	65
Derivative financial instruments - gas	138			26			99				(191	)	72
Contracts for differences		—			—		24				—		24
Total	157			74			175				(245	)	161
Derivative liabilities
Derivative financial instruments - power		(26	)		(22	)		(5	)		42			(11	)
Derivative financial instruments - gas		(172	)		(35	)		(55	)		201			(61	)
Contracts for differences		—			—			(112	)		—			(112	)
Derivative financial instruments - other		—			—			(1	)		—			(1	)
Total	$	(198	)	$	(57	)	$	(173	)	$	243		$	(185	)

As of December 31, 2015	Level 1			Level 2			Level 3			Netting			Total
(Millions)
Securities portfolio (available for sale)	$	39		$	—		$	—		$	—		$	39
Derivative assets
Derivative financial instruments - power		10			81			48			(71	)		68
Derivative financial instruments - gas		267			25			68			(280	)		80
Contracts for differences		—			—			29			—			29
Total		277			106			145			(351	)		177
Derivative liabilities
Derivative financial instruments - power		(43	)		(12	)		(14	)		55			(14	)
Derivative financial instruments - gas		(193	)		(40	)		(51	)		212			(72	)
Contracts for differences		—			—			(96	)		—			(96	)
Derivative financial instruments - other		—			—			(3	)		—			(3	)
Total	$	(236	)	$	(52	)	$	(164	)	$	267		$	(185	)

20

Avangrid, Inc. and Subsidiaries

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 three and six months ended June 30, 2016 and 2015, respectively, is as follows:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
(Millions)	2016			2015			2016			2015
Fair Value Beginning of Period,	$	(45	)	$	54		$	(19	)	$	57
Gains recognized in operating revenues		40			31			44			42
(Losses) recognized in operating revenues		—			(4	)		(1	)		(5	)
Total gains (losses) recognized in operating revenues		40			27			43			37
Gains recognized in OCI		—			2			1			3
(Losses) recognized in OCI		—			—			—			(1	)
Total Gains (Losses) Recognized in OCI		—			2			1			2
Net change recognized in regulatory assets and liabilities		3			—			(22	)		—
Purchases		(1	)		22			(1	)		21
Settlements		(2	)		(4	)		(7	)		(7	)
Transfers out of Level 3(a)		7			2			7			(7	)
Fair Value as of June 30,	$	2		$	103		$	2		$	103
Gains (losses) for the period included in operating revenues    attributable to the change in unrealized gains (losses)    relating to financial instruments still held at the reporting date	$	40		$	27		$	43		$	37

(a)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 2 years), using past and current views of prices for those future periods.

As of June 30, 2016					Variability
Instruments	Instrument Description	Valuation Technique	Valuation Inputs	Index	Avg.		Max.		Min.
Fixed price power and gas swaps	Transactionswith deliveryperiods	Transactionsare valuedagainst forward marketprices	Observableand extrapolated forwardgasand powerprices notallofwhich canbe	NYMEX($/MMBtu)	$	4.24	$	7.37	$	1.64
with delivery	exceeding two	on a	corroborated by	SP15($/MWh)	$	44.09	$	80.28	$	14.25
period > two	years	discounted	market data for	Mid C($/MWh)	$	35.32	$	83.93	$	3.60
years		basis	identical or	Cinergy($/MWh)	$	36.29	$	77.49	$	18.53
			similarproducts

Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are traded at liquid hubs in the West and Midwest and are used to hedge merchant wind production in those regions.

We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs and concluded that no material change to the financial statements is expected given the following: (i) any changes in the fair value of the gas swaps

21

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

hedging inventory would be expected to be largely offset by changes in the value of the inventory; (ii) any changes in the fair value of the gas swaps hedging merchant generation would be expected to be significantly offset by changes in the value of future power generation.

Future commodity prices are the significant unobservable inputs to fair value. Any significant increases in prices would result in a lower fair value of derivatives. Conversely, significant reductions in prices would result in a higher fair value of derivatives.

Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in calculation of market value and the models themselves. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products.

Transaction models are valued in part on the basis of forward price, correlation, and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the models are applied to the full duration of transactional models to a maximum of approximately thirty years.

The carrying amounts for cash and cash equivalents, accounts receivable, accounts payable, notes payable and interest accrued approximate their estimated fair values and are considered as Level 1.

The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that extended over the term of the contracts. We believe this methodology provides the most reasonable estimates of the amount of future discounted cash flows associated with the CfDs. Additionally, on a quarterly basis, we perform analytics to ensure that the fair value of the derivatives is consistent with changes, if any, in the various fair value model inputs. Significant isolated changes in the risk of non-performance, the discount rate or the contract term pricing would result in an inverse change in the fair value of the CfDs. Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:

	Range at
Unobservable Input	June 30, 2016
Risk of non-performance	0.05% - 0.77%
Discount rate	0.71% - 1.49%
Forward pricing ($ per MW)	$3.15 - $9.55

Fair Value of Debt

As of June 30, 2016 and December 31, 2015 debt consisted of first mortgage bonds, fixed and variable unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $5,252 million and $4,985 million as of June 30, 2016 and December 31, 2015, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value hierarchy pertaining to the fair value of debt is considered as Level 2, except for unsecured pollution control notes-variable with a fair value of $204 million as of both June 30, 2016 and December 31, 2015, which are considered Level 3. The fair value of these unsecured pollution control notes-variable are determined using unobservable interest rates as the market for these notes is inactive.

Note 7. Derivative Instruments and Hedging

Our Networks, Renewables and Gas activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on the condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities.

(a) Networks activities

NYSEG and RGE have an electric commodity charge that passes through rates costs for the market price of electricity. They use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the

22

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations.

The amount recognized in regulatory assets for electricity derivatives was a loss of $7.3 million as of June 30, 2016, and $34.3 million as of December 31, 2015. The amount reclassified from regulatory assets and liabilities into income, which is included in electricity purchased, was a loss of $13.1 million and $9.4 million, and a loss of $47.9 million and $12.0 million for the three and six months ended June 30, 2016 and 2015, respectively.

NYSEG and RGE have purchased gas adjustment clauses that allow them to recover through rates any changes in the market price of purchased natural gas, substantially eliminating their exposure to natural gas price risk. NYSEG and RGE use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and / or liabilities with an offset to regulatory assets and / or regulatory liabilities in accordance with the accounting requirements for regulated operations.

The amount recognized in regulatory assets for natural gas hedges was a gain of $2.8 million as of June 30, 2016, and a loss of $3.1 million as of December 31, 2015. The amount reclassified from regulatory assets into income, which is included in natural gas purchased, was a loss of $0 and $1.4 million, and a loss of $3.4 million and $3.0 million for the three and six months ended June 30, 2016 and 2015, respectively.

Contracts for Differences

Pursuant to PURA, UI and Connecticut’s other electric utility, The Connecticut Light and Power Company (CL&P), each executed two long-term CfDs with certain incremental capacity resources, each of which specifies a capacity quantity and a monthly settlement that reflects the difference between a forward market price and the contract price. The costs or benefits of each contract will be paid by or allocated to customers and will be subject to a cost-sharing agreement between UI and CL&P pursuant to which approximately 20% of the cost or benefit is borne by or allocated to UI customers and approximately 80% is borne by or allocated to CL&P customers.

PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability). For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of June 30, 2016, UI has recorded a gross derivative asset of $24 million ($0.1 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $88 million, a gross derivative liability of $112 million ($83 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $1 million. As of December 31, 2015, UI had recorded a gross derivative asset of $29 million ($1 million of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $68 million, a gross derivative liability of $96 million ($61 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $1 million.

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets or regulatory liabilities, for the three and six months ended June 30, 2016, respectively, were as follows:

	Three Months Ended			Six Months Ended
	June 30, 2016
(Millions)
Regulatory Assets - Derivative liabilities	$	(2	)	$	(5	)
Regulatory Liabilities - Derivative assets	$	6		$	(16	)

23

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

The net notional volumes of the outstanding derivative instruments associated with Networks activities as of June 30, 2016 and December 31, 2015, respectively, consisted of:

	June 30,		December 31,
As of	2016		2015
(Millions)
Wholesale electricity purchase contracts (MWh)		6.8	6.7
Natural gas purchase contracts (Dth)		5.1	4.8
Fleet fuel purchase contracts (Gallons)		3.0	3.8

The offsetting of derivatives, location and amounts of derivatives designated as hedging instruments associated with Networks activities as of June 30, 2016 and December 31, 2015, respectively, consisted of:

As of June 30, 2016	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	10		$	14		$	—		$	—
Derivative liabilities		—			—			(28	)		(84	)
		10			14			(28	)		(84	)
Designated as hedging instruments
Derivative assets		16			5			14			5
Derivative liabilities		(13	)		(5	)		(20	)		(8	)
		3			—			(6	)		(3	)
Total derivatives before offset of cash collateral		13			14			(34	)		(87	)
Cash collateral receivable (payable)		—			—			4			3
Total derivatives as presented in the balance sheet	$	13		$	14		$	(30	)	$	(84	)

As of December 31, 2015	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	11		$	18		$	(28	)	$	(68	)
Derivative liabilities		—			—			—			—
		11			18			(28	)		(68	)
Designated as hedging instruments
Derivative assets		3			6			3	��		6
Derivative liabilities		(3	)		(6	)		(42	)		(7	)
		—			—			(39	)		(1	)
Total derivatives before offset of cash collateral		11			18			(67	)		(69	)
Cash collateral receivable (payable)		—			—			37			—
Total derivatives as presented in the balance sheet	$	11		$	18		$	(30	)	$	(69	)

24

Avangrid, Inc. and Subsidiaries

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 six months ended June 30, 2016 and 2015, respectively, consisted of:

Three Months Ended  June 30,	(Loss) Recognized in OCI on Derivatives		Location of (Loss) Reclassified from Accumulated OCI into Income	(Loss) Reclassified from Accumulated OCI into Income
(Millions)	Effective Portion (a)		Effective Portion (a)
2016
Interest rate contracts	$	—	Interest expense	$	(2	)
Commodity contracts		—	Operating expenses		—
Total	$	—		$	(2	)
2015
Interest rate contracts	$	—	Interest expense	$	(2	)
Commodity contracts		—	Operating expenses		(1	)
Total	$	—		$	(3	)

Six Months Ended June 30,	(Loss) Recognized in OCI on Derivatives			Location of (Loss) Reclassified from Accumulated OCI into Income	(Loss) Reclassified from Accumulated OCI into Income
(Millions)	Effective Portion (a)			Effective Portion (a)
2016
Interest rate contracts	$	—		Interest expense	$	(4	)
Commodity contracts		—		Operating expenses		(1	)
Total	$	—			$	(5	)
2015
Interest rate contracts	$	—		Interest expense	$	(4	)
Commodity contracts		(1	)	Operating expenses		(2	)
Total	$	(1	)		$	(6	)

(a)Changes in OCI are reported on a pre-tax basis. The reclassified amounts of commodity contracts are included within “Purchase power, natural gas and fuel used” line item within operating expenses in the condensed consolidated statements of income.

The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $80.8 million and $84.9 million as of June 30, 2016 and December 31, 2015, respectively. We recorded $2.0 million and $2.2 million in net derivative losses related to discontinued cash flow hedges for the three months ended June 30, 2016 and 2015, respectively. We recorded $4.0 million and $4.4 million in net derivative losses related to discontinued cash flow hedges for the six months ended June 30, 2016 and 2015, respectively We will amortize approximately $8.0 million of discontinued cash flow hedges in 2016. During the three and six months ended June 30, 2016 and 2015, there was no ineffective portion for cash flow hedges.

The unrealized loss of $1.4 million on hedge activities is reported in OCI because the forecasted transaction is considered to be probable as of June 30, 2016. We expect that $1.1 million of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is eighteen months.

(b) Renewables and Gas activities

We sell fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. We also purchase fixed-price gas and basis swaps and sell fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets. We also enter into tolling arrangements to sell the output of our thermal generation facilities.

Our gas business purchases and sells both fixed-price gas and basis swaps to hedge the value of contracted storage positions. The intent of entering into these swaps is to fix the margin of gas injected into storage for subsequent resale in future periods. We also

25

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

enter into basis swaps to hedge the value of our contracted transport positions. The intent of buying and selling these basis swaps is to fix the location differential between the price of gas at the receipt and delivery point of the contracted transport in future periods.

Both Renewables and Gas have proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.

Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future power sales and gas purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and AECO basis swaps that hedge the fuel requirements of its Klamath facility. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms.

Gas also periodically designates NYMEX fixed price derivative contracts as cash flow hedges related to its firm storage trading activities. To the extent that the derivative contracts are effective in offsetting the variability of cash flows associated with future gas sales and purchases, the fair value changes are recorded in OCI. Any hedge ineffectiveness is recorded in current period earnings. Derivative contracts entered into to hedge the gas transport trading activities are not designated as cash flow hedges, with all changes in fair value of such derivative contracts recorded in current period earnings.

The net notional volumes of outstanding derivative instruments associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of:

	June 30,		December 31,
As of	2016		2015
(MWh/Dth in millions)
Wholesale electricity purchase contracts		3		3
Wholesale electricity sales contracts		6		6
Foreign exchange forward purchase contracts		—		4
Natural gas and other fuel purchase contracts		331		332
Financial power contracts		6		7
Basis swaps – purchases		68		67
Basis swaps – sales		69		80

The fair values of derivative contracts associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of:

	June 30,			December 31,
As of	2016			2015
(Millions)
Wholesale electricity purchase contracts	$	(1	)	$	(13	)
Wholesale electricity sales contracts		11			35
Foreign exchange forward purchase contracts		—			(1	)
Natural gas and other fuel purchase contracts		18			10
Financial power contracts		44			32
Basis swaps – purchases		(5	)		1
Basis swaps – sales		(4	)		(2	)
Total	$	63		$	62

26

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

The effect of trading and non-trading derivatives, respectively, associated with Renewables and Gas activities for the three and six months ended June 30, 2016 and 2015, respectively, consisted of:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(Millions)
Wholesale electricity purchase contracts	$	5		$	3		$	5		$	10
Wholesale electricity sales contracts		(6	)		(13	)		(7	)		(18	)
Financial power contracts		1			11			2			10
Financial and natural gas contracts		(1	)		7			(31	)		(48	)
Total (Loss) Gain	$	(1	)	$	8		$	(31	)	$	(46	)
	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(Millions)
Wholesale electricity purchase contracts	$	11		$	6		$	8		$	5
Wholesale electricity sales contracts		(20	)		(19	)		(14	)		(22	)
Financial power contracts		(17	)		(1	)		(16	)		4
Financial and natural gas contracts		35			6			26			12
Total Gain (Loss)	$	9		$	(8	)	$	4		$	(1	)

Such gains and losses are included in revenues and in “Purchased power, natural gas and fuel used” operating expenses in the condensed consolidated statements of income, depending upon the nature of the transaction.

The offsetting of derivatives, location and amounts of derivatives designated as hedging instruments associated with Renewables and Gas activities as of June 30, 2016 and December 31, 2015, respectively, consisted of:

As of June 30, 2016	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	112		$	103		$	124		$	4
Derivative liabilities		(29	)		(10	)		(186	)		(17	)
		83			93			(62	)		(13	)
Designated as hedging instruments
Derivative assets		8			8			—			—
Derivative liabilities		—			—			(34	)		(10	)
		8			8			(34	)		(10	)
Total derivatives before offset of cash collateral		91			101			(96	)		(23	)
Cash collateral receivable (payable)		(16	)		(42	)		39			9
Total derivatives as presented in the balance sheet	$	75		$	59		$	(57	)	$	(14	)

27

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

As of December 31, 2015	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	186		$	113		$	117		$	4
Derivative liabilities		(85	)		(14	)		(169	)		(29	)
		101			99			(52	)		(25	)
Designated as hedging instruments
Derivative assets		56			13			—			—
Derivative liabilities		—			—			(9	)		—
		56			13			(9	)		—
Total derivatives before offset of cash collateral		157			112			(61	)		(25	)
Cash collateral receivable (payable)		(80	)		(41	)		—			—
Total derivatives as presented in the balance sheet	$	77		$	71		$	(61	)	$	(25	)

The effect of derivatives in cash flow hedging relationships on OCI and income for the three and six months ended June 30, 2016 and 2015, respectively, consisted of:

Three Months Ended  June 30,	(Loss) Recognized in OCI on Derivatives			Location of Gain Reclassified from Accumulated OCI into Income	Gain Reclassified from Accumulated OCI into Income
(Millions)	Effective Portion (a)			Effective Portion (a)
2016
Commodity contracts	$	(38	)	Revenues	$	(2	)
Total	$	(38	)		$	(2	)
2015
Commodity contracts	$	—		Revenues	$	—
Total	$	—			$	—

Six Months Ended June 30,	(Loss) Recognized in OCI on Derivatives			Location of Gain Reclassified from Accumulated OCI into Income	Gain Reclassified from Accumulated OCI into Income
(Millions)	Effective Portion (a)			Effective Portion (a)
2016
Commodity contracts	$	(35	)	Revenues	$	(48	)
Total	$	(35	)		$	(48	)
2015
Commodity contracts	$	1		Revenues	$	—
Total	$	1			$	—

(a) Changes in OCI are reported on a pre-tax basis.

Amounts will be reclassified from accumulated OCI into income in the period(s) during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $25.9 million of losses included in accumulated OCI at June 30, 2016, is expected to be reclassified into earnings within the next 12 months. During the three months ended June 30, 2016 and 2015, we recorded a net loss of $0.4 million and $1.4 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges. During the six months ended June 30, 2016 and 2015, we recorded a net loss of $4.8 million and $1.4 million, respectively, in earnings as a result of ineffectiveness from cash flow hedges.

(c) Counterparty credit risk management

NYSEG and RGE face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are dependent on the counterparty’s or the counterparty’s guarantor’s

28

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

applicable credit rating, normally Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.

The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of June 30, 2016, UI would have had to post an aggregate of approximately $10.2 million in collateral.

We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amounts of cash collateral under master netting arrangements that have not been offset against net derivative positions were $1 million and $11 million as of June 30, 2016 and December 31, 2015, respectively. Derivative instruments settlements and collateral payments are included in “Other assets” and “Other liabilities” of operating activities in the condensed consolidated statements of cash flows.

Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of June 30, 2016 is $7 million, for which we have posted collateral.

Note 8. Contingencies

We are party to various legal disputes arising as part of our normal business activities. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency.

MNG Rate Case

On March 5, 2015, MNG filed a rate case in order to further recover future investments and provide safe and adequate service.  MNG requested a 10.0% ROE and 50.0% equity ratio. The MPUC Staff recommended a separate revenue requirement for MNG’s Augusta customers and MNG’s non-Augusta customers. The Staff also recommended a $19.95 million disallowance of the Augusta Expansion investment based upon the Staff’s conclusion that MNG’s management of the Augusta Expansion Project was imprudent.

On November 6, 2015, a stipulation was filed with the MPUC, which was executed by MNG, the Office of Public Advocate and the City of Augusta. The stipulation contained a combined revenue requirement for Augusta and Non-Augusta based on a 9.55% ROE and 50% equity ratio. The stipulation also provided for an initial Augusta investment disallowance of $6 million and an investment phase-in of $10 million. On December 22, 2015, the MPUC rejected the proposed stipulation as not in the public interest. In January 2016, the Administrative Law Judge established a new litigation schedule. The litigation was suspended at the end of January 2016 for settlement discussions. We reserved $6 million for this case at the end of 2015.

On May 3, 2016, all active parties to the case filed a stipulation which settled all matters at issue in the case and reflected a 10-year rate plan through April 30, 2026. The MPUC approved the stipulation on May 17, 2016, for new rates effective June 1, 2016. The settlement structure for non-Augusta customers includes a 34.6% delivery revenue increase over five years with an allowed 9.55% ROE and 50% common equity ratio. The settlement structure for Augusta customers includes a 10-year rate plan with existing Augusta customers being charged rates equal to non-Augusta customers plus a surcharge which increases annually for five years.  New Augusta customers will have rates set based on an alternate fuel market model. In year seven of the rate plan MNG will submit a cost of service filing for the Augusta area to determine if the rate plan should continue. This cost of service filing will exclude $15 million of initial 2012/2013 gross plant investment, however the stipulation allows for accelerated depreciation of these assets. If the Augusta area’s cost of service filing illustrates results above a 14.55% ROE then the rate plan may cease, otherwise the rate plan would continue. A disallowance for the initial 2012/2013 gross plant investment is not part of the approved stipulation. The reserve of $6 million for this case was reversed in May 2016.     

29

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Transmission - ROE Complaint – CMP and UI

On September 30, 2011, the Massachusetts Attorney General, Massachusetts Department of Public Utilities, Connecticut Public Utilities Regulatory Authority, New Hampshire Public Utilities Commission, Rhode Island Division of Public Utilities and Carriers, Vermont Department of Public Service, numerous New England consumer advocate agencies and transmission tariff customers collectively filed a complaint (Complaint I) with the FERC pursuant to sections 206 and 306 of the Federal Power Act. The filing parties seek an order from the FERC reducing the 11.14% base return on equity used in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) to  9.2%. CMP and UI are New England Transmission Owners (NETOs) with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.

On June 19, 2014, the FERC issued its initial decision in this first complaint, establishing a methodology and setting an issue for a paper hearing.  On October 16, 2014, FERC issued its final decision in the first complaint (Complaint I) setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014, and ordered the NETOs to file a refund report. On November 17, 2014, the NETOs filed a refund report.

On March 3, 2015, the FERC issued an order on requests for rehearing of its October 16, 2014 decision. The March order upheld the FERC’s initial decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average return. In June 2015 the NETOs filed an appeal in the U.S. Court of Appeals for the District of Columbia of the FERC’s final order. The appeal is currently pending, and we cannot predict the outcome of this appeal.

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

On July 31, 2014, the Complainants filed a third ROE complaint (Complaint III) for a subsequent rate period requesting the ROE be reduced to 8.84%. On November 24, 2014, FERC accepted the third complaint, established a 15-month refund effective date of July 31, 2014, and set this matter, consolidated with Complaint II, for hearing in June 2015. Hearings were held in June 2015 on Complaints II and III before a FERC Administrative Law Judge, relating to the refund periods and going forward period. On July 29, 2015, post-hearing briefs were filed by parties and on August 26, 2015 reply briefs were filed by parties. On July 13, 2015, the New England transmission owners filed a petition for review of FERC’s orders establishing hearing and consolidation procedures for Complaints II and III with the U.S. Court of Appeals. The FERC Administrative Law Judge issued an Initial Decision on March 22, 2016.  The Initial Decision determined that, 1) for the 15-month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and 2) for the 15-month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The Initial Decision is the Administrative Law Judge’s recommendation to the FERC Commissioners.  The FERC is expected to make its final decision in late 2016 or early 2017.

CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 final Complaint I decision. The CMP and UI total reserve associated with Complaints I, II and III is $21.2 million and $4.2 million, respectively, as of June 30, 2016. If adopted as final, the impact of the initial decision would be an additional aggregate reserve for Complaints II and III of $10.2 million, net of tax, which is based upon currently available information for these proceedings. We cannot predict the outcome of the Complaint II and III proceeding.

On April 29, 2016, the Complainants filed a fourth ROE complaint (Complaint IV) for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%.  The NETOs filed a response to the Complaint IV on June 3, 2016.We cannot predict the outcome of the Complaint IV proceeding.

Yankee Nuclear Spent Fuel Disposal Claim

CMP has an ownership interest in Maine Yankee Atomic Power Company, Connecticut Yankee Atomic Power Company, and Yankee Atomic Electric Company, (the Yankee Companies), three New England single-unit decommissioned nuclear reactor sites, and UI has an ownership interest in Connecticut Yankee Atomic Power Company. Every six years, pursuant to the statute of limitations, the Yankee Companies file a lawsuit to recover damages from the Department of Energy (DOE or Government) for breach of the Nuclear Spent Fuel Disposal Contract to remove Spent Nuclear Fuel (SNF) and Greater than Class C Waste (GTCC) as required by contract

30

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

and the Nuclear Waste Policy Act beginning in 1998. The damages are the incremental costs for the Government’s failure to take the spent nuclear fuel.  

In 2012, the U.S. Court of Appeals issued a favorable decision in the Yankee Companies’ claim for the first six year period (Phase I).  Total damages awarded to the Yankee Companies were nearly $160 million.  The Yankee Companies won on all appellate points in the U.S. Court of Appeals for the Federal Circuit’s unanimous decision.  The Federal Appeals Court affirmed the September 2010 U.S. Court of Federal Claims award of $39.7 million to Connecticut Yankee Atomic Power Company; affirmed the Court of Federal Claims award of $81.7 million to Maine Yankee Atomic Power Company; and increased Yankee Atomic Electric Company’s damages award from $21.4 million to $38.3 million. The Phase I damage award became final on December 4, 2012. The Yankee Companies received payment from the DOE in January 2013. CMP’s share of the award was approximately $36.5 million which was credited back to customers. UI’s share of the award was $3.8 million which was credited back to customers.

In November 2013 the U.S. Court of Claims issued its decision in the Phase II case (the second 6-year period). The court’s decision awarded the Yankee Companies a combined $235.4 million (Connecticut Yankee $126.3 million, Maine Yankee $37.7 million, and Yankee Atomic $73.3 million). The Phase II period covers January 1, 2002, through December 31, 2008, for Connecticut Yankee and Yankee Atomic, and January 1, 2003, through December 31, 2008, for Maine Yankee. Maine Yankee’s damage award was lower because it recovered a larger amount in the Phase I case ($82 million) and its decommissioning was both less expensive and completed sooner than the other Yankee Companies.  The damage awards flow through the Yankee Companies to shareholders (including CMP and UI) to reduce retail customer charges.  In January 2014 the Government informed the Yankee Companies it would not appeal the court’s decision. As a result the Yankee Companies received full payment in April 2014. CMP’s share of the award was approximately $28.2 million which was credited back to customers. UI received approximately $12 million of such award which was applied, in part, against its remaining storm regulatory asset balance. The remaining regulatory liability balance was applied to UI’s generation service charge (GSC) “working capital allowance” and was returned to customers through the non-by-passable federally mandated congestion charge.

In August 2013, the Yankee Companies filed a third round of claims against the Government seeking damages for the years 2009-2014 (Phase III). The Phase III trial was completed in July 2015 and the court issued its decision on March 25, 2016, awarding the Yankee Companies a combined $76.8 million (Connecticut Yankee $32.6 million, Maine Yankee $24.6 million and Yankee Atomic $19.6 million). The damage awards, less any amount retained to reduce future customer charges, will potentially flow through the Yankee Companies to shareholders, including CMP and UI, upon FERC approval, and will reduce retail customer charges or otherwise as specified by law. CMP and UI will receive their proportionate share of the awards that flow through based on percentage ownership. On July 18, 2016, the notice of appeal period expired and the Phase III trial award became final. We cannot predict the timing or amount of damage awards that may ultimately flow through to customers.

NYPSC Staff Review of Earnings Sharing Calculations and Other Regulatory Deferrals

In December 2012, the NYPSC Staff (Staff) informed NYSEG and RGE that the Staff had conducted an audit of the companies’ annual compliance filings (ACF) for 2009 through August 31, 2010, and the first rate year of the current rate plan, September 1, 2010 through August 31, 2011. The Staff’s preliminary findings indicated adjustments to deferred balances primarily associated with storm costs and the treatment of certain incentive compensation costs for purposes of the 2011 ACF. The Staff’s findings approximate $9.8 million of adjustments to deferral balances and customer earnings sharing accruals. NYSEG and RGE reviewed the Staff’s adjustments and work papers and provided a response in early 2013. NYSEG and RGE disagreed with certain Staff conclusions and as a result recorded a $3.4 million reserve in December 2012 in anticipation of settling the Staff issues. In the Proposal approved by the NYPSC (see Note 5) the parties agreed that in full and final resolution of all years through 2012, and in full and final resolution of storm-related deferrals through 2014, the companies will add $2.4 million to the customer share of earnings sharing.

California Energy Crisis Litigation

Two California agencies brought a complaint against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed FERC's dismissal of Renewables.

Joining with two other parties, Renewables filed a petition for certiorari in the United States Supreme Court on May 3, 2007. In an order entered on June 27, 2008, the Supreme Court granted Renewables’ petition for certiorari, vacated the appellate court's judgment, and remanded the case to the appellate court for further consideration in light of the Supreme Court’s decision in a similar case. In

31

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

light of the Supreme Court's order, on December 4, 2008, the Ninth Circuit Court of Appeals vacated its prior opinion and remanded the complaint proceedings to the FERC for further proceedings consistent with the Supreme Court's rulings. In 2014 FERC assigned an administrative law judge to conduct evidentiary hearings. Following discovery, the FERC Trial Staff recommended that the complaint against Renewables be dismissed.

A hearing was held before an administrative law judge of FERC in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016.  The proposed ruling found no evidence that Renewables had engaged in any unlawful market contract that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that price of the power purchase agreements imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by FERC Trial Staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted to FERC briefs on exceptions to the administrative law judge’s proposed ruling. There is no specific timetable to FERC’s ruling, but we presently expect it to be issued in late 2016. We cannot predict the outcome of this proceeding.

Guarantee Commitments to Third Parties

As of June 30, 2016, we had approximately $2.5 billion of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of the company and its subsidiaries in their normal course of business.  The instruments only represent liabilities if the company or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of June 30, 2016, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Note 9. Environmental Liabilities

Environmental laws, regulations and compliance programs may occasionally require changes in our operations and facilities and may increase the cost of electric and natural gas service. We do not provide for accruals of legal costs expected to be incurred in connection with loss contingencies.

Waste sites

The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Fifteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; six sites are included in Maine’s Uncontrolled Sites Program and one site is included on the Massachusetts Non- Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, nine of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and severable for certain sites.

We have recorded an estimated liability of $6 million related to ten of the twenty-four sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another ten sites where we believe it is probable that we will incur remediation costs and or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the portion of remediation attributed to us.

Manufactured Gas Plants

We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Eight sites are included in the New York State Registry; eleven sites are included in the New York Voluntary Cleanup Program; three sites are part of Maine’s Voluntary Response Action Program with two of such sites being part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and where necessary remediate forty-seven of the fifty-three sites.

32

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $235 million to $468 million as of June 30, 2016. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives, and changes to current laws and regulations.

As of June 30, 2016 and December 31, 2015, the liability associated with MGP sites in Connecticut, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $99 million.

The liability to investigate and perform remediation at the known inactive MGP sites was $388 million and $397 million as of June 30, 2016 and December 31, 2015, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2048.

Our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; no liability was recorded in respect of these sites as of June 30, 2016 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites.

FirstEnergy

NYSEG sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at sixteen former manufactured gas sites, which are included in the discussion above. In July 2011, the District Court issued a decision and order in NYSEG’s favor. Based on past and future clean-up costs at the sixteen sites in dispute, FirstEnergy would be required to pay NYSEG approximately $60 million if the decision were upheld on appeal. On September 9, 2011, FirstEnergy paid NYSEG $30 million, representing their share of past costs of $27 million and pre-judgment interest of $3 million.

FirstEnergy appealed the decision to the Second Circuit Court of Appeals. On September 11, 2014, the Second Circuit Court of Appeals affirmed the District Court’s decision in NYSEG’s favor, but modified the decision for nine sites, reducing NYSEG’s damages for incurred costs from $27 million to $22 million, excluding interest, and reducing FirstEnergy’s allocable share of future costs at these sites. NYSEG refunded FirstEnergy the excess $5 million in November 2014.

FirstEnergy remains liable for a substantial share of clean up expenses at nine MPG sites. In January 2015, NYSEG sent FirstEnergy a demand for $16 million representing FirstEnergy’s share of clean-up expenses incurred by NYSEG at the nine sites from January 2010 to November 2014 while the District Court appeal was pending. Nearly all of this amount has been paid by FirstEnergy. FirstEnergy would also be liable for a share of post 2014 costs, which, based on current projections, would be $26 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision.

Century Indemnity and OneBeacon

On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at twenty-two former manufactured gas plants. Based on estimated clean-up costs of $282 million, the carriers’ allocable share could equal or exceed approximately $89 million, excluding pre-judgment interest, although this amount may change substantially depending upon the determination of various factual matters and legal issues during the case. Any recovery will be flowed through to NYSEG ratepayers.

Century and One Beacon have answered admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. We cannot predict the outcome of this matter.

33

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

English Station

In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. In December 2013, Evergreen and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the property; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages. 

On April 8, 2013, the Connecticut Department of Energy and Environmental Protection (DEEP) issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April 2015. Action in the administrative proceeding has been suspended until a status conference scheduled for September 1, 2016.

On September 16, 2015, UI signed a Proposed Partial Consent Order that, when issued by the Commissioner of DEEP, and subject to its terms and conditions, would require UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site.  Under the Proposed Partial Consent Order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut, and the Commissioner of DEEP. Pursuant to the Proposed Partial Consent Order, upon its issuance and subject to its terms and conditions, UI would be obligated to comply with the Proposed Partial Consent Order, even if the cost of such compliance exceeds $30 million. The State will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties, however it is not bound to agree to or support any means of recovery or funding.      

On July 18, 2016, Evergreen Power, Asnat, and certain related parties signed a proposed Consent Order that, when issued by the Commissioner of DEEP, will provide UI access to investigate and remediate the English Station site consistent with the Proposed Partial Consent Order.  The Attorney General filed the Evergreen Power and Asnat Consent Order and the Proposed Partial Consent Order with DEEP on July 22, 2016, and requested the Commissioner of DEEP issue the Consent and Partial Consent Orders as final orders. Upon issuance of the final UI Partial Consent Order and availability of access to the English Station site, UI will begin to investigate and remediate certain environmental conditions within the perimeter of the English Station site consistent with the Proposed Partial Consent Order.

As of December 31, 2015 we reserved $20.5 million for this case and have accrued the remaining $9.5 million in accordance with the settlement with PURA approving the acquisition. As of June 30, 2016 the reserve amount remained unchanged. We cannot predict the outcome of this matter.

Note 10. Post-retirement and Similar Obligations

We made $15 million of pension contributions for the three and six months ended June 30, 2016. We expect to make $28 million of contributions for the remainder of 2016.

The components of net periodic benefit cost for pension benefits for the three and six months ended June 30, 2016 and 2015, respectively, consisted of:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(Millions)
Service cost	$	11		$	9		$	22		$	18
Interest cost		35			24			70			48
Expected return on plan assets		(51	)		(39	)		(102	)		(78	)
Amortization of:
Prior service costs		1			1			1			2
Actuarial loss		37			32			75			64
Net Periodic Benefit Cost	$	33		$	27		$	66		$	54

34

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

The components of net periodic benefit cost for postretirement benefits for the three and six months ended June 30, 2016 and 2015, respectively, consisted of:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
(Millions)
Service cost	$	1		$	1		$	2		$	2
Interest cost		6			4			12			8
Expected return on plan assets		(3	)		(2	)		(6	)		(4	)
Amortization of:
Prior service costs		(2	)		(2	)		(4	)		(4	)
Actuarial loss		2			2			4			4
Net Periodic Benefit Cost	$	4		$	3		$	8		$	6

Note 11. Equity

As of June 30, 2016, our share capital consisted of 500,000,000 shares of common stock authorized, 309,592,620 shares issued and 309,003,589 shares outstanding, 81.5% owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,651 million. As of December 31, 2015, our share capital consisted of 500,000,000 shares of common stock authorized, 309,491,082 shares issued and 308,864,609 shares outstanding, 81.5% owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,653 million. We had 491,552 and 626,473 shares of common stock held in trust and no convertible preferred shares outstanding as of June 30, 2016 and December 31, 2015, respectively. During the six months ended June 30, 2016, we issued 101,538 shares of common stock and released 134,921 shares of common stock held in trust each having a par value of $0.01.

On April 28, 2016, we entered into a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage of Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. During the six months ended June 30, 2016, we repurchased 97,479 shares of common stock of AVANGRID in the open market. The total cost of repurchase, including commissions, was $4 million.

On December 15, 2015, the Board of Directors approved our common stock dividend, accounted for as a stock split. The stock split, effected through a stock dividend, resulted in the issuance of 252,234,989 shares, which in addition to the 243 previously existing shares increased the total shares outstanding to 252,235,232. The stock dividend was effective upon the Board’s approval. All share and per share information included in the condensed consolidated financial statements have been retroactively adjusted to reflect the impact of the stock dividend.

35

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Accumulated Other Comprehensive Income (Loss)

Accumulated OCI for the three months ended June 30, 2016 and 2015, respectively, consisted of:

	As of    March 31			Three Months Ended  June 30,			As of June 30,			As of     March 31			Three Months Ended  June 30,			As of June 30,
Accumulated Other Comprehensive Income (Loss)	2015			2015			2015			2016			2016			2016
(Millions)
Loss on revaluation of defined benefit plans, net of    income tax expense (benefit) of $(0.1) for 2015 and    $0.1 for 2016	$	(26	)	$	(1	)	$	(27	)	$	(17	)	$	—		$	(17	)
Loss for nonqualified pension plans		(11	)		—			(11	)		(8	)		—			(8	)
Unrealized gain (loss) during period on derivatives    qualifying as cash flow hedges, net of income tax    expense (benefit) of $0.4 for 2015 and $(14.2) for 2016		(2	)		1			(1	)		33			(23	)		10
Reclassification to net income of losses (gains) on    cash flow hedges, net of income tax expense    of $1.2 for 2015 and $0.7 for 2016(a)		(59	)		2			(57	)		(80	)		1			(79	)
Gain (loss) on derivatives qualifying as cash flow    hedges		(61	)		3			(58	)		(47	)		(22	)		(69	)
Accumulated Other Comprehensive (Loss) Income	$	(98	)	$	2		$	(96	)	$	(72	)	$	(22	)	$	(94	)

Accumulated OCI for the six months ended June 30, 2016 and 2015, respectively, consisted of:

	As of December 31,			Six Months Ended June 30,			As of June 30,			As of December 31,			Six Months Ended June 30,			As of June 30,
Accumulated Other Comprehensive Income (Loss)	2014			2015			2015			2015			2016			2016
(Millions)
Gain (loss) on revaluation of defined benefit plans, net of    income tax expense (benefit) of $(1.0) for 2015 and    $2.9 for 2016	$	(25	)	$	(2	)	$	(27	)	$	(21	)	$	4		$	(17	)
Loss for nonqualified pension plans		(11	)		—			(11	)		(8	)		—			(8	)
Unrealized gain (loss) during period on derivatives    qualifying as cash flow hedges, net of income tax    expense (benefit) of $0.4 for 2015 and $(13.0) for 2016		(2	)		1			(1	)		31			(21	)		10
Reclassification to net income of losses (gains) on    cash flow hedges, net of income tax expense    (benefit) of $2.2 for 2015 and $(15.9) for 2016(a)		(61	)		4			(57	)		(54	)		(25	)		(79	)
Gain (loss) on derivatives qualifying as cash flow    hedges		(63	)		5			(58	)		(23	)		(46	)		(69	)
Accumulated Other Comprehensive (Loss) Income	$	(99	)	$	3		$	(96	)	$	(52	)	$	(42	)	$	(94	)

(a) Reclassification is reflected in the operating expenses line item in the condensed consolidated statements of income

Note 12. Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three and six months ended June 30, 2016, while we did have securities that were dilutive, these securities did not result in a change on our earnings per share calculation result for the three and six months ended June 30, 2016. We did not have any potentially-dilutive securities for the three and six months ended June 30, 2015. In accordance with Accounting Standards Codification (ASC) Topic 260, Earnings per Share, we retroactively applied the stock split to prior period.

36

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

The calculations of basic and diluted earnings per share attributable to AVANGRID, including a reconciliation of the numerators and denominators for the three and six months ended June 30, 2016 and 2015, respectively, consisted of:

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

Note 13. Segment Information

Our segment reporting structure uses our management reporting structure as its foundation to reflect how AVANGRID manages the business internally and is organized by type of business. We report our financial performance based on the following three reportable segments:

· Networks: including all the energy transmission and distribution activities, and any other regulated activity originating in New York and Maine, and regulated electric distribution, electric transmission and gas distribution activities originating in Connecticut and Massachusetts. The Networks reportable segment includes eight rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment.

· Renewables: activities relating to renewable energy, mainly wind energy generation and trading related with such activities.

· Gas: including gas trading and storage businesses carried on by the AVANGRID Group.

Products and services are sold between reportable segments and affiliate companies at cost. The chief operating decision maker evaluates segment performance based on segment adjusted EBITDA (Earnings Before Interest, Taxes, Depreciation and Amortization) defined as net income adding back net income attributable to other noncontrolling interests, income tax expense, depreciation and amortization, impairment of non-current assets and interest expense net of capitalization, and then subtracting other income and (expense) and earnings from equity method investments per segment. Segment income, expense, and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the condensed consolidated financial statements.

Segment information for the three months ended June 30, 2016, consisted of:

Three Months Ended June 30, 2016	Networks		Renewables			Gas			Other (a)			AVANGRID Consolidated
(Millions)
Revenue - external	$	1,211	$	242		$	(14	)	$	—		$	1,439
Revenue - intersegment		2		2			3			(7	)		—
Depreciation and amortization		126		81			6			—			213
Operating income (loss)		299		58			(28	)		(7	)		322
Adjusted EBITDA		425		139			(22	)		(7	)		535
Earnings (losses) from equity method investments	$	3	$	(3	)	$	—		$	—		$	—

(a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

Included in revenue-external for the three months ended June 30, 2016, are: $949 million from regulated electric operations, $263 million from regulated gas operations and $(1) million amounts from other operations of Networks; $242 million from renewable energy generation of Renewables; $5 million from gas storage services and $(19) million from gas trading operations of Gas.

37

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Segment information for the three months ended June 30, 2015, consisted of:

Three Months Ended June 30, 2015	Networks		Renewables			Gas			Other (a)			AVANGRID Consolidated
(Millions)
Revenue - external	$	715	$	243		$	(19	)	$	—		$	939
Revenue – intersegment		—		8			9			(17	)		—
Impairment of non-current assets		—		7			—			—			7
Depreciation and amortization		94		89			4			—			187
Operating income (loss)		100		8			(26	)		(9	)		73
Adjusted EBITDA		194		104			(22	)		(9	)		267
Earnings (losses) from equity method investments	$	—	$	(3	)	$	—		$	2		$	(1	)

(a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

Included in revenue-external for the three months ended June 30, 2015, are: $608 million from regulated electric operations, $110 million from regulated gas operations and $(3) million amounts from other operations of Networks; $243 million from renewable energy generation of Renewables; $4 million from gas storage services and $(23) million from gas trading operations of Gas.

Segment information as of and for the six months ended June 30, 2016, consisted of:

Six Months Ended June 30, 2016	Networks		Renewables			Gas			Other (a)			AVANGRID Consolidated
(Millions)
Revenue - external	$	2,601	$	518		$	(11	)	$	1		$	3,109
Revenue - intersegment		2		4			12			(18	)		—
Depreciation and amortization		244		161			13			—			418
Operating income (loss)		611		107			(38	)		(9	)		671
Adjusted EBITDA		855		268			(25	)		(9	)		1,089
Earnings (losses) from equity method investments		6		(4	)		—			—			2
Capital expenditures	$	470	$	203		$	1		$	—		$	674
As of June 30, 2016
Property, plant and equipment		12,525		7,800			505			—			20,830
Equity method investments		131		240			—			—			371
Total assets	$	19,871	$	10,437		$	1,034		$	(931	)	$	30,411

(a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

Included in revenue-external for the six months ended June 30, 2016, are: $1,862 million from regulated electric operations, $740 million from regulated gas operations and $(1) million amounts from other operations of Networks; $518 million from renewable energy generation of Renewables; $12 million from gas storage services and $(23) million from gas trading operations of Gas.

38

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Segment information for the six months ended June 30, 2015, consisted of:

Six Months Ended June 30, 2015	Networks		Renewables			Gas			Other (a)			AVANGRID Consolidated
(Millions)
Revenue - external	$	1,713	$	482		$	(29	)	$	—		$	2,166
Revenue – intersegment		—		9			18			(27	)		—
Impairment of non-current assets		—		7			—			—			7
Depreciation and amortization		180		172			9			1			362
Operating income (loss)		289		34			(41	)		(13	)		269
Adjusted EBITDA		469		213			(32	)		(12	)		638
Earnings (losses) from equity method investments		—		(2	)		—			2			—
Capital expenditures	$	355	$	172		$	3		$	—		$	530
As of December 31, 2015
Property, plant and equipment		12,363		7,835			513			—			20,711
Equity method investments		110		253			—			22			385
Total assets	$	20,126	$	10,685		$	1,265		$	(1,333	)	$	30,743

(a) Does not represent a segment. It mainly includes Corporate and intersegment eliminations.

Included in revenue-external for the six months ended June 30, 2015, are: $1,336 million from regulated electric operations, $382 million from regulated gas operations and $(5) million from other operations of Networks; $482 million from renewable energy generation of Renewables; $6 million from gas storage services and $(35) million from gas trading operations of Gas.

Reconciliation of consolidated Adjusted EBITDA to the AVANGRID consolidated Net Income for the three and six months ended June 30, 2016 and 2015, respectively, is as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016		2015			2016		2015
(Millions)
Consolidated Adjusted EBITDA	$	535	$	267		$	1,089	$	638
Less:
Impairment of non-current assets		—		7			—		7
Depreciation and amortization		213		187			418		362
Interest expense, net of capitalization		68		66			152		127
Income tax expense		172		5			276		47
Add:
Other income and (expense)		20		10			69		22
Earnings (losses) from equity method investments		—		(1	)		2		—
Consolidated Net Income	$	102	$	11		$	314	$	117

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Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Note 14. Related Party Transactions

We engage in related party transactions which are generally billed at cost and in accordance with applicable state and federal commission regulations.

Related party transactions for the three months ended June 30, 2016 and 2015, respectively, consisted of:

Three Months Ended June 30,	2016					2015
(Millions)	Sales To		Purchases From			Sales To		Purchases From
Iberdrola Canada Energy Services, Ltd	$	—	$	(14	)	$	1	$	(19	)
Iberdrola Renovables Energía, S.L.		—		(2	)		—		(3	)
Iberdrola, S.A.		—		(10	)		—		(12	)
Other		1		(1	)		—		(3	)

Related party transactions for the six months ended June 30, 2016 and 2015, respectively, consisted of:

Six Months Ended June 30,	2016					2015
(Millions)	Sales To		Purchases From			Sales To		Purchases From
Iberdrola Canada Energy Services, Ltd	$	—	$	(19	)	$	1	$	(31	)
Iberdrola Renovables Energía, S.L.		—		(5	)		—		(5	)
Iberdrola, S.A.		—		(18	)		—		(18	)
Other		2		(1	)		—		(4	)

In addition to the statements of income items above, we made purchases of turbines for wind farms from Gamesa Corporación Tecnológica, S.A. (Gamesa), in which our ultimate parent Iberdrola has a 20% ownership. The amounts capitalized for these transactions were $57 million and $70 million as of June 30, 2016 and December 31, 2015, respectively. In June 2016, Siemens AG and Gamesa signed binding agreement to merge wind power business. After completion of the merger, which is expected in the first quarter of 2017, Iberdrola will have 8.1% ownership of the new combined company.  

Related party balances as of June 30, 2016 and December 31, 2015, respectively, consisted of:

As of	June 30, 2016					December 31, 2015
(Millions)	Owed By		Owed To			Owed By		Owed To
Iberdrola Canada Energy Services, Ltd.	$	4	$	(4	)	$	7	$	(5	)
Gamesa Corporación Tecnológica, S.A.		61		(48	)		68		(77	)
Iberdrola, S.A.		—		(17	)		—		(3	)
Iberdrola Energy Projects, Inc.		1		—			1		(3	)
Iberdrola Renovables Energía, S.L.		—		(5	)		—		—
Other		4		(1	)		—		(2	)

Transactions with our parent company, Iberdrola, relate predominantly to allocation of corporate services and management fees. Also included within the Purchases From category are charges for credit support relating to guarantees Iberdrola has provided to third parties guaranteeing our performance. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID any costs remaining after direct charge are allocated using agreed upon cost allocation methods designed to allocate those costs. We believe that the allocation method used is reasonable.

Transactions with Iberdrola Canada Energy Services predominantly relate to the purchase of gas for ARHI’s gas-fired generation facility at Klamath.

There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances, other than a $7 million write-off related to an arrangement to purchase turbines from Gamesa during the three months ended June 30, 2015, which was recorded in impairment of non-current assets in the statements of income. The collectability of amounts receivable from Gamesa are contingent upon other related parties fulfilling certain payments to Gamesa.

Networks holds an approximate 20% ownership interest in the regulated New York TransCo, LLC (New York TransCo). Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison,

40

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. In the second quarter of 2016, Networks has increased its equity method investment in the New York TransCo by approximately $21 million (included in “Other investments and equity method investments, net” of investing activities in the condensed consolidated statements of cash flows) for a total equity method investment of $22 million. Additionally, in the second quarter of 2016, Networks has received approximately $67 million from the New York TransCo in the form of $43 million for assets constructed and transferred to the New York TransCo (included in “Proceeds from asset sale” of investing activities in the condensed consolidated statements of cash flows), $22 million in contributions in aid of construction and approximately $2 million in advanced lease payments for a 99 year lease of land and attachment rights.

AVANGRID manages its overall liquidity position as part of the broader Iberdrola Group and is a party to a notional cash pooling agreement with Bank Mendes Gans, N.V., similar to other Iberdrola subsidiaries.  Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited in the cash pooling account where such funds are available to meet the liquidity needs of other affiliates within the Iberdrola Group. Under the cash pooling agreement, affiliates with credit balances have pledged those balances to cover the debit balances of the other affiliated parties to the agreement.

Note 15. Accounts Receivable

Accounts receivable include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. The utility company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within thirty days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as current.

We establish provisions for uncollectible accounts for DPA’s by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collection efforts have been exhausted. DPA receivable balances were $61 million and $62 million at June 30, 2016 and December 31, 2015, respectively. The allowance for doubtful accounts for DPAs at June 30, 2016 and December 31, 2015, were $34 million and $35 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for the three months ended June 30, 2016 and 2015 were $0 and $(5) million, respectively, and for the six months ended June 30, 2016 and 2015 approximated $(1) million and $(4) million, respectively.

Note 16. Income Tax Expense

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

Note 17. Subsequent Events

Quarterly Dividends

On July 14, 2016, the Board of Directors of AVANGRID declared a quarterly dividend of $0.432 per share on its common stock. This dividend is payable on October 3, 2016, to shareholders of record at the close of business on September 9, 2016.

Performance Stock Unit Grant Agreement

On July 14, 2016, the Board of Directors of AVANGRID approved the form of performance stock unit grant agreement, pursuant to which performance stock units (PSUs) will be granted under the Avangrid, Inc. Omnibus Incentive Plan for certain officers and employees of AVANGRID. Officers and employees of AVANGRID may be granted up to 2.5 million PSUs in the aggregate, which will vest upon achievement of certain performance and market metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020, 2021 and 2022.

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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 combined and consolidated financial statements as of December 31, 2015 and 2014, and for the three years ended December 31, 2015, included in our Annual Report on Form 10-K for the year ended December 31, 2015, filed with the Securities and Exchange Commission, or the SEC, on April 1, 2016, which we refer to as our “Form 10-K.” 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. The foregoing and other factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC.

Overview

We are a direct, majority owned subsidiary of Iberdrola, S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of The Kingdom of Spain, one of the world’s leading energy companies.  Our direct, wholly-owned subsidiaries include Avangrid Networks, Inc., or Networks, and Avangrid Renewables Holdings, Inc., or ARHI. ARHI in turn holds subsidiaries including Avangrid Renewables LLC, or Renewables, and Enstor Gas, LLC, or Gas. Networks, owns and operates our regulated utility businesses through its subsidiaries, including electric transmission and distribution and natural gas distribution, transportation and sales. Avangrid Service Company, a subsidiary of Networks, provides corporate and back-office services on a consolidated basis to our subsidiaries. Renewables operates a portfolio of renewable energy generation facilities primarily using onshore wind power and also solar, biomass and thermal power.  Gas operates our natural gas storage facilities and gas trading businesses through Enstor Energy Services LLC (gas trading) and Enstor Inc. (gas storage).

On December 16, 2015, we completed our acquisition of UIL Holdings Corporation, or UIL. Immediately following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares.  The acquisition was accounted for as a business combination. The results of operations of UIL since December 16, 2015, the acquisition date, have been included in the consolidated results of AVANGRID. Effective as of April 30, 2016, UIL and its subsidiaries were transferred to a wholly-owned subsidiary of Networks.

Through Networks, we own electric generation, transmission and distribution companies and natural gas distribution, transportation and sales companies in New York, Maine, Connecticut and Massachusetts, delivering electricity to approximately 2.2 million electric utility customers and delivering natural gas to approximately 987,000 natural gas public utility customers as of June 30, 2016.

Networks, a Maine corporation, along with UIL, a Connecticut corporation, holds our regulated utility businesses, including electric transmission and distribution and natural gas distribution, transportation and sales. Networks serves as a super-regional energy services and delivery company through eight regulated utilities it owns directly or through UIL:

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

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

· The United Illuminating Company, or UI: serves electric customers in southwestern Connecticut;

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

· The Southern Connecticut Gas Company, or SCG: serves natural gas customers in Connecticut;

· Connecticut Natural Gas Corporation, or CNG: serves natural gas customers in Connecticut;

· The Berkshire Gas Company, or BGC: serves natural gas customers in western Massachusetts; and

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

Through Renewables, we had a combined wind, solar and thermal installed capacity of 6,330 megawatts, or MW, as of June 30, 2016, including Renewables’ share of joint projects, of which 5,643 MW was installed wind capacity. Approximately 62% of the capacity was contracted for an average period of 10.0 years as of June 30, 2016. As the second largest wind operator in the United States based on installed capacity as of June 30, 2016, Renewables strives to lead the transformation of the U.S. energy industry to a competitive, clean energy future. Renewables currently operates 53 wind farms in 18 states across the United States. During the six months ended June 30, 2016, the production of wind was approximately 10% lower than the average  wind production

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in 2011 through 2014. This decrease resulted in approximately $45 million to $50 million of lower adjusted gross margin for Renewables. For additional information, please see the risk factors disclosed in our Form 10-K for the fiscal year ended December 31, 2015.

Through Gas, as of June 30, 2016, we own approximately 67.5 billion cubic feet, or Bcf, of net working gas storage capacity. Gas operates 52.4 Bcf of contracted or managed natural gas storage capacity in North America through Enstor Energy Services, LLC, as of June 30, 2016.

Our operating revenues increased by 53%, from $0.9 billion for the three months ended June 30, 2015 to $1.4 billion for the three months ended June 30, 2016.

The increase in operating revenues was largely due to the inclusion of UIL, which was not in the comparable period, adding $333 million in revenues for the three months ended June 30, 2016. The Networks business revenues increased on the impact of favorable operating conditions partially offset by slight decreases in Renewables and Gas operating revenues as a result of movements in prices.

Net income increased primarily due to the additional contribution of UIL.  Networks net income improved as higher electricity and gas revenues offset increases in costs resulting from higher transmission support expense. Renewables net income decreased as a result of unfavorable interest and income taxes, with underlying operating income increasing as a result of lower operating expenses due to decreases in purchased power and operations and maintenance expenses. Gas net income remained flat for the periods.

Adjusted earnings before interest, tax, depreciation and amortization, or adjusted EBITDA, increased by 100% from $267 million for the three months ended June 30, 2015, to $535 million for the three months ended June 30, 2016, primarily as a result of a 120% increase in adjusted EBITDA at Networks due to addition of UIL. Renewables increased 34%, primarily as a result of the increase in revenues from higher output. For additional information and reconciliation of adjusted EBITDA to net income, see “—Non-GAAP Financial Measures”.

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 our Form 10-K for the year ended December 31, 2015.

MNG rate case

On May 3, 2016, all active parties to the case filed a stipulation which settled all matters at issue in the case and reflected a 10-year rate plan through April 30, 2026. The MPUC approved the stipulation on May 17, 2016, for new rates effective June 1, 2016. The settlement structure for non-Augusta customers includes a 34.6% delivery revenue increase over five years with an allowed 9.55% ROE and 50% common equity ratio. The settlement structure for Augusta customers includes a 10-year rate plan with existing Augusta customers being charged rates equal to non-Augusta customers plus a surcharge which increases annually for five years.  New Augusta customers will have rates set based on an alternate fuel market model. In year seven of the rate plan MNG will submit a cost of service filing for the Augusta area to determine if the rate plan should continue. This cost of service filing will exclude $15 million of initial 2012/2013 gross plant investment, however the stipulation allows for accelerated depreciation of these assets. If the Augusta area’s cost of service filing illustrates results above a 14.55% ROE then the rate plan may cease, otherwise the rate plan would continue. A disallowance for the initial 2012/2013 gross plant investment is not part of the approved stipulation. The reserve of $6 million for this case was reversed in May 2016.

Transmission - ROE Complaint

On April 29, 2016, the Eastern Massachusetts Consumer Owned Systems filed a fourth, ROE complaint (Complaint IV) for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%. The NETOs filed a response to the Complaint IV on June 3, 2016. We cannot predict the outcome of the Complaint IV proceeding.

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NYSEG and RGE Joint Proposal Approval

On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal (Proposal) in connection with a three-year rate plan for electric and gas service at NYSEG and RGE effective May 1, 2016. Following the approval of the Proposal most of these items related to NYSEG are amortized over a five-year period, except the portion of storm costs to be recovered over ten years, plant related tax items which are amortized over the life of associated plant. Annual amortization expense for NYSEG is approximately $16.5 million per rate year. RGE items that are being amortized are plant related tax items, which are amortized over the life of associated plant, and unfunded deferred taxes being amortized over a period of fifty years. A majority of the other items related to RGE, which net to a regulatory liability, remains deferred and will not be amortized until future proceedings or will be used to recover costs of the Ginna Reliability Support Services Agreement (Ginna RSSA).

In the approved Proposal the allowed rate of return on common equity is 9.0% for all companies. The equity ratio for each company is 48%; however the equity ratio is set at 50% for earnings sharing purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% ROE, respectively, in the first year. The rate plans also include the implementation of a rate adjustment mechanism designed to return or collect certain defined reconciled revenues and costs; new depreciation rates; and continuation of the existing revenue decoupling mechanisms for each business. Following the approval of the Proposal by the NYPSC, unfunded future income taxes were adjusted for the amount of $126 million to reflect the change from a flow through to normalization method, which has been recorded as an increase to income tax expense and an offsetting increase to revenue for the three and six month periods ended June 30, 2016. The amounts will be collected over a period of fifty years.

UI rate case

On July 1, 2016, UI filed an application with the Connecticut Public Utilities Regulatory Authority, or PURA, requesting approval of a three-year rate plan commencing January 1, 2017, and extending through December 31, 2019. We expect PURA to rule on UI’s rate request in December 2016. UI’s application requests an increase of $65.6 million in 2017, an additional $21.1 million in 2018, and an additional $13.4 million in 2019. The application includes a rate levelization proposal to moderate the customer impact of the necessary revenue increases. The proposal defers a portion of the first and second year increases and spreads recovery of the overall increase by approximately equivalent amounts over the three years of the rate plan with carrying charges included. The proposal results in levelized revenue requirement increases of $40.7 million in 2017, $47.4 million in 2018 and $39.1 million in 2019, followed by an offset of $25.6 million at the end of the three year rate plan to equate the levelized recovery to the non-levelized revenue requirement increase.

UI’s rate request is attributable primarily to the amount of capital expenditures devoted to the company’s electric distribution system for the purpose of reliability and system resiliency, both in relation to routine operations and during major storm events. UI’s application also proposes continuation of its revenue decoupling mechanism and proposes a new earnings sharing mechanism (ESM). Under the proposed ESM, 50% of UI’s earnings in excess of the allowed ROE, plus a deadband above the allowed ROE, would be flowed through to the benefit of customers. The proposed ESM includes a 20-basis point deadband in 2017 above the authorized ROE, within which there would be no sharing. This deadband would be 30 basis points in 2018 and 40 basis points in 2019. UI proposes to continue applying any dollars due to customers to reduce the storm regulatory asset, if one exists. If none exists, then the customer share would be provided through a bill credit.

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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												Six Months Ended
	June 30,												June 30,
	2016			%			2015			%			2016			%			2015			%
	(in millions)
Operating Revenues	$	1,439			100	%	$	939			100	%	$	3,109			100	%	$	2,166			100	%
Operating Expenses
Purchased power, natural gas and fuel used		221			15			151			16			649			21			543			25
Operations and maintenance		558			39			434			46			1,109			36			814			38
Impairment of non-current assets		—			—			7			1			—			—			7			—
Depreciation and amortization		213			15			187			20			418			13			362			17
Taxes other than income taxes		125			9			87			9			262			8			171			8
Total Operating Expenses		1,117			78			866			92			2,438			78			1,897			88
Operating income		322			22			73			8			671			22			269			12
Other Income (Expense)
Other income (expense)		20			1			10			1			69			2			22			1
Earnings (losses) from equity method investments		—			—			(1	)		—			2			—			—			—
Interest expense, net of capitalization		(68	)		(5	)		(66	)		(7	)		(152	)		(5	)		(127	)		(6	)
Income Before Income Tax		274			18			16			2			590			19			164			7
Income tax expense		172			12			5			1			276			9			47			2
Net Income		102			3			11			1			314			10			117			5
Less: Net income attributable to noncontrolling interests		—			—			—			—			—			—			—			—
Net Income	$	102			3	%	$	11			1	%	$	314			10	%	$	117			5	%

Comparison of Period to Period Results of Operations

Three Months Ended June 30, 2016 Compared to Three Months Ended June 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 June 30, 2016	Total		Networks			Renewables			Gas			Other(1)
	(in millions)
Operating revenues	$	1,439	$	1,214		$	244		$	(11	)	$	(8	)
Operating revenues %				84	%		17	%		(1	)%		—
Operating expenses	$	1,117	$	915		$	186		$	17		$	(1	)
Operating expenses %				82	%		17	%		2	%		—

Three Months Ended June 30, 2015	Total		Networks			Renewables			Gas				Other(1)
	(in millions)
Operating revenues	$	939	$	726		$	251		$	(10	)		$	(28	)
Operating revenues %				77	%		27	%		—		��		(2	)%
Operating expenses	$	866	$	627		$	243		$	15			$	(19	)
Operating expenses %				72	%		28	%		2	%			(1	)%

(1)Other amounts represent corporate and company eliminations.

Operating Revenues

Our operating revenues increased by 53% from $0.9 billion for the three months ended June 30, 2015, to $1.4 billion for the three months ended June 30, 2016, as detailed by segment below:

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Networks

Operating revenues increased by $487 million, or 67%, from $726 million for the three months ended June 30, 2015 to $1.2 billion for the three months ended June 30, 2016. The addition of UIL added $333 million to revenues, for an underlying increase of $154 million. Higher average retail rates achieved improved electricity revenues by $24 million.  Retail volume changes increased revenues by $2 million, with increases in heating demand negated by reductions in cooling demand. Wholesale electricity revenues declined $5 million due to a combination of lower volumes combined with lower wholesale market prices, which were lower in 2016 as a result of the milder weather lowering demand. Other decreases of $24 million related to reductions in transmission congestion revenue of $18 million and lower retail rates of $6 million. Regulatory recoveries increased by $139 million primarily due to adjustment of $126 million of unfunded future income tax to reflect the change from a flow through to normalization method, which has been recorded as an increase to revenue, with an offsetting and equal increase to income tax expense, and remaining increase relating to recoveries on Ginna RSSA, revenue decoupling mechanisms and pension transition charges.

Renewables

Operating revenues decreased by $7 million, or 3%, from $251 million for the three months ended June 30, 2015 to $244 million for the three months ended June 30, 2016. Renewable production increased 5% or 177GWh, with a corresponding increase to revenues of $11 million, but was partially offset by a 3%, or $1.60/MWh reduction in prices realized, reducing revenues by $6 million. Revenues were $5 million unfavorable from mark-to-market, or MtM, derivatives and other revenues were $7 million lower.

Gas

Operating revenues decreased by $1 million from negative $10 million for the three months ended June 30, 2015 to negative $11 million for the three months ended June, 2016 due to lower spreads in contracted storage being insufficient to cover fixed costs.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used increased by 46%, from $151 million for the three months ended June 30, 2015 to $221 million for the three months ended June 30, 2016, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used increased by $86 million, or 65%, from $132 million for the three months ended June 30, 2015 to $218 million for the three months ended June 30, 2016. Excluding the $87 million from UIL, underlying expense was consistent compared with the same period of 2015 with only a $1 million reduction.

Renewables

Purchased power, natural gas and fuel used decreased by $24 million, or 80%, from $30 million for the three months ended June 30, 2015 to $6 million for the three months ended June 30, 2016. The decrease was primarily due to $21 million of favorable MtM change on derivatives, and $3 million related to fuel expense for Klamath gas generation facility

Gas

The gas business had no purchased power, natural gas and fuel used for the three months ended June 30, 2016 and 2015. As a predominantly trading business, such expenses are required to be netted with revenues.

Operations and Maintenance

Our operations and maintenance increased by 28% from $434 million for the three months ended June 30, 2015 to $558 million for the three months ended June 30, 2016, as detailed by segment below:

Networks

Operations and maintenance increased by $129 million or 39% from $333 million for the three months ended June 30, 2015 to $461 million for the three months ended June 30, 2016. UIL accounts for $127 million of this increase, with a $2 million increase attributable to the underlying business.

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Renewables

Operations and maintenance expenses decreased by $13 million or 13% from $100 million for the three months ended June 30, 2015 to $87 million for the three months ended June 30, 2016. Bad debt expense decreased $9 million due to disputed amounts in the three months ended June 30, 2015. In addition, labor costs were lower by $4 million due to an unfavorable adjustment in the same period of 2015.

Gas

Operations and maintenance increased by $1 million, or 10%, from $10 million for the three months ended June 30, 2015 to $11 million for the three months ended June 30, 2016. Increases in credit guarantee expenses and audit expenses account for the increase in the three months ended June 30, 2016.

Depreciation, Amortization and Impairment of Non-current Assets

Depreciation, amortization and impairment expenses for the three months ended June 30, 2016 was $213 million compared to $194 million for the three months ended June 30, 2015, an increase of $19 million. The primary movements were UIL contributing $41 million of expense and Renewables decreasing by $8 million due to revision of useful lives of wind power station assets during the second quarter of 2016 and decreasing $7 million from a reduction in project impairment costs, with no projects impaired in the three months ended June 30, 2016.

Other Income and (Expense) and Equity Earnings

Other income and (expense) and equity earnings increased by $11 million from $9 million for the three months ended June 30, 2015 to $20 million for the three months ended June 30, 2016. UIL contributed $4 million of income, Networks increased $4 million resulting from interest income on regulatory deferrals and Renewables increased $3 million as a result of the sale of other investment.

Interest Expense, Net of Capitalization

Interest expense for the three months ended June 30, 2016 and June 30, 2015 were $68 million and $66 million, respectively. Excluding the impact of UIL, which added $21 million of expense, underlying expense was $19 million lower for the three months ended June 30, 2016 as compared to the same period of 2015. Networks was $12 million lower, arising from lower interest expense on regulatory deferrals. Renewables was $6 million lower primarily as a result of lower tax equity investment obligation levels.

Income Tax Expense

The effective tax rate for the three months ended June 30, 2016 was 62.9% due to impact of adjustment to unfunded future income tax following the approval of the Proposal by the NYPSC. After elimination of the effect of the adjustment of $126 million to unfunded future income tax reflect the change from a flow through to normalization method, which has been recorded as an increase to income tax expense and an offsetting increase to revenue, the effective tax rate for the three month period ended June 30, 2016 is 31.7% compared to 31.2% tax rate for the three months ended June 30, 2015. The rates in both periods are lower than the 35% statutory federal income tax rate predominately due to the recognition of production tax credits associated with wind production.

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Six Months Ended June 30, 2016 Compared to Six Months Ended June 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:

Six Months Ended June 30, 2016	Total		Networks			Renewables			Gas			Other(1)
	(in millions)
Operating revenues	$	3,109	$	2,604		$	522		$	1		$	(18	)
Operating revenues %				84	%		17	%		—			(1	)%
Operating expenses	$	2,438	$	1,993		$	415		$	39		$	(9	)
Operating expenses %				82	%		17	%		2	%		—

Six Months Ended June 30, 2015	Total		Networks			Renewables			Gas			Other(1)
	(in millions)
Operating revenues	$	2,166	$	1,729		$	491		$	(11	)	$	(43	)
Operating revenues %				80	%		23	%		—			(2	)%
Operating expenses	$	1,897	$	1,441		$	457		$	29		$	(30	)
Operating expenses %				76	%		24	%		2	%		(1	)%

(1) Other amounts represent corporate and company eliminations.

Operating Revenues

Our operating revenues increased by 44% from $2.2 billion for the six months ended June 30, 2015 to $3.1 billion for the six months ended June 30, 2016, as detailed by segment below:

Networks

Operating revenues increased by $875 million, or 50%, from $1.7 billion for the six months ended June 30, 2015 to $2.6 billion for the six months ended June 30, 2016. The addition of UIL added $831 million to revenues, for an underlying increase of $44 million. The milder winter weather in 2016 lowered demand for both electricity and gas, with a corresponding revenue impact of $108 million. Wholesale electricity revenues also declined $48 million due to a combination of lower volumes and wholesale market prices, which were down in 2016 as a result of the milder weather reducing demand. Other decreases of $24 million related to reductions in transmission congestion revenue of $18 million and lower retail rates of $6 million. Regulatory recoveries increased by $212 million primarily due to adjustment of $126 million to unfunded future income tax to reflect the change from a flow through to normalization method, which has been recorded as an increase to revenue, with an offsetting and equal increase to income tax expense, increase of $32 million relating to recoveries on Ginna RSSA together with other increases for items such as revenue decoupling mechanisms and pension transition charges.

Renewables

Operating revenues increased by $31 million, or 6%, from $491 million for the six months ended June 30, 2015 to $522 million for the six months ended June 30, 2016. The increase in operating revenues was due to an increase of $38 million from existing wind assets with output increasing 9%, or 621GWh, partly offset by a 2%, $1.40/MWh, reduction in prices realized, reducing  revenues by $11 million. Additional revenue of $12 million were realized from sales of transmission rights, offset by $1 million in unfavorable changes on MtM derivatives and $6 million in various other unfavorable changes.

Gas

Operating revenues increased by $12 million from negative $11 million for the six months ended June 30, 2015 to $1 million for the six months ended June 30, 2016. The increase in operating revenues was due predominantly to $11 million of improved performance in the owned and contracted storage businesses, with both capturing higher spreads relative to the same period of previous year.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used increased by 19%, from $543 million for the six months ended June 30, 2015 to $649 million for the six months ended June 30, 2016, as detailed by segment below:

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Networks

Purchased power, natural gas and fuel used increased by $108 million, or 6%, from $491 million for the six months ended June 30, 2015 to $599 million for the six months ended June 30, 2016. Excluding the $268 million from UIL, underlying expense decreased by $160 million. Purchase volume requirements were 13% lower for electricity and 14% lower for gas for the same reasons outlined under Networks revenues, namely the milder weather in winter 2016.  In addition, market prices were down 50% for electricity and 26% for gas.  

Renewables

Purchased power, natural gas and fuel used decreased by $9 million, or 13%, from $71 million for the six months ended June 30, 2015 to $62 million for the six months ended June 30, 2016. Klamath power plant expense was $3 million lower and MtM derivatives were favorable $8 million, partially offset by transmission and energy purchases up $2 million.

Gas

The gas business had no purchased power, natural gas and fuel used for the six months ended June 30, 2016 and 2015. As a predominantly trading business, such expenses are required to be netted with revenues.

Operations and Maintenance

Our operations and maintenance increased by 36% from $814 million for the six months ended June 30, 2015 to $1.1 billion for the six months ended June 30, 2016, as detailed by segment below:

Networks

Operations and maintenance increased by $291 million or 46% from $631 million for the six months ended June 30, 2015 to $922 million for the six months ended June 30, 2016. UIL accounts for $253 million of this increase, with the remaining $38 million attributable to the underlying business. The regulatory adjustment for the Ginna RSSA, which has offsets in revenue, accounts for a $64 million increase. Partially offsetting this are reductions of $14 million from lower expenditures on various state mandated energy efficiency programs, and $12 million of reductions spread over various areas, such as lower storm related expenditures, lower insurance claim expenses, and renewable energy credit purchases.

Renewables

Operations and maintenance expenses decreased by $11 million or 6% from $177 million for the six months ended June 30, 2015 to $166 million for the six months ended June 30, 2016.  Bad debt expense decreased $9 million due to a disputed amounts in the six months ended June 30, 2015.  Asset retirement related expenses were $2 million lower, as a result of the extension of the windfarm useful life in combination with revisions to expense estimates.

Gas

Operations and maintenance increased by $6 million, or 35%, from $17 million for the six months ended June 30, 2015 to $23 million for the six months ended June 30, 2016. Increases in credit guarantee expenses and external services account for the increase in the six month period ended June 30, 2016.

Depreciation, Amortization and Impairment of Non-current Assets

Depreciation, amortization and impairment expenses for the six months ended June 30, 2016 was $418 million compared to $369 million for the six months ended June 30, 2015, an increase of $49 million. The primary movements were UIL contributing $80 million, with the underlying business $31 million lower. Networks depreciation expense was $17 million lower, mainly as a result of classification of excess depreciation and updates to asset lives. Renewables expense was $17 million lower as a result of no project impairment expenses in the six month period ended June 30, 2016 and $25 million lower depreciation expense due to revision of useful lives of wind farm assets offset by $15 million due to increases from Baffin Bay wind asset only being operational for part of the prior period, combined with additional expense from salvage values and from asset retirement obligation estimations.

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Other Income and (Expense) and Equity Earnings

Other income and (expense) and equity earnings increased by $49 million from $22 million for the six months ended June 30, 2015 to $71 million for the six months ended June 30, 2016. UIL accounts for contributing $11 million of income. Of the remaining $38 million, $33 million was as a result of the sale of the Iroquois equity investment, and $3 million was as a result of the sale of other investment. An additional $6 million of income is for the reversal of the Maine Natural Gas provision in the current period that was initially recorded at the end of 2015.  Partially offsetting this are reductions of $4 million in equity income, primarily as a result of low energy prices in Renewables joint ventures.

Interest Expense, Net of Capitalization

Interest expense for the six months ended June 30, 2016 and 2015 were $152 million and $127 million, respectively. Excluding the impact of UIL, which added $41 million of expense, underlying expense was $16 million favorable.  Networks was $8 million favorable, mainly as a result of lower interest expense on regulatory deferrals, and Renewables was $8 million favorable, as a result of lower tax equity investment obligations.

Income Tax Expense

The effective tax rate for the six months ended June 30, 2016 was 46.8% due to impact of adjustment to unfunded future income tax following the approval of the Proposal by the NYPSC, and sale of the Iroquois equity investment. After elimination of the effect of the adjustment to unfunded future income tax amount of $126 million to reflect the change from a flow through to normalization method, which has been recorded as an increase to income tax expense and an offsetting increase to revenue, and sale of the Iroquois equity investment, the effective tax rate for the six month period ended June 30, 2016 is 31.9% compared to 28.6% tax rate for the six months ended June 30, 2015. The rates in both periods are lower than the 35% statutory federal income tax rate predominately due to the recognition of production tax credits associated with wind production.  

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented in accordance with U.S. GAAP, we consider certain non-GAAP financial measures that are not prepared in accordance with U.S. GAAP, adjusted gross margin, adjusted EBITDA, adjusted net income and adjusted earnings per share, or adjusted EPS. We use these non-GAAP financial measures, in addition to U.S. GAAP measures, to establish operating budgets and operational goals to manage and monitor our business, evaluate our operating and financial performance and to compare such performance to prior periods and to the performance of our competitors. The non-GAAP financial measures we use are specific to AVANGRID and the non-GAAP financial measures of other companies may not be calculated in the same manner. In addition, we present 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 define adjusted EBITDA as net income attributable to AVANGRID, adding back net income attributable to other noncontrolling interests, income tax expense, depreciation, amortization, impairment of non-current assets and interest expense, net of capitalization, and then subtracting other income and (expense) and earnings from equity method investments. We define adjusted net income as excluding gain on sale of equity method and other investment, impairment of investment, costs related to merger with UIL and reflecting a full six month period ended June 30, 2015 for UIL, or a full six month period of 2015 UIL results, as we believe it is more useful in understanding and evaluating actual and projected financial performance and contribution of AVANGRID and to more fully compare and explain our results without including the impact of the above described items and with reflecting pro forma information to reflect a full period of results for merged entities. Additionally, we evaluate the nature of our revenues and expenses and adjust to reflect classification by nature for evaluation of our non-GAAP financial measures as opposed to by function. The most directly comparable U.S. GAAP measure to adjusted EBITDA and adjusted net income is net income. We also define adjusted gross margin as adjusted EBITDA adding back operations and maintenance and taxes other than income taxes and then subtracting transmission wheeling. We also define adjusted EPS as adjusted net income converted to an earnings per share amount.

The use of non-GAAP financial measures is not intended to be considered in isolation or as a substitute for, or superior to, AVANGRID’s U.S. GAAP financial information, and investors are cautioned that the non-GAAP financial measures are limited in their usefulness, may be unique to AVANGRID, should be considered only as a supplement to AVANGRID’s U.S. GAAP financial measures. The non-GAAP financial measures may not be comparable to other similarly titled measures of other companies and have limitations as analytical tools.

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Non-GAAP financial measures are not primary measurements of our performance under U.S. GAAP and should not be considered as alternatives to operating income, net income or any other performance measures determined in accordance with U.S. GAAP.

Reconciliation of the Net Income attributable to AVANGRID to adjusted EBITDA and adjusted gross margin before reflecting a full six month period of 2015 UIL results, excluding gain on sale of equity method and other investment, impairment of investment, costs related to merger with UIL and before adjustments to reflect classification of revenues and expenses by nature for the three and six months ended June 30, 2016 and 2015, respectively, is as follows:

	Three Months Ended					Six Months Ended
	June 30,					June 30,
	2016		2015			2016		2015
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	102	$	11		$	314	$	117
Add: Income tax expense		172		5			276		47
Impairment of non-current assets		—		7			—		7
Depreciation and amortization		213		187			418		362
Interest expense, net of capitalization		68		66			152		127
Less:  Other income and (expense)		20		10			69		22
Earnings from equity method investments		—		(1	)		2		—
Adjusted EBITDA (2)	$	535	$	267		$	1,089	$	638
Add: Operations and maintenance (1)		558		434			1,109		814
Taxes other than income taxes		125		87			262		171
Less: Transmission wheeling (1)		61		33			122		66
Adjusted gross margin (2)	$	1,157	$	755		$	2,338	$	1,557

(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.

(2) Adjusted EBITDA and adjusted gross margin are presented before reflecting a full six month period of 2015 UIL results, excluding gain on sale of equity method and other investment, impairment of investment, costs related to merger with UIL and before adjustments to reflect classification of revenues and expenses by nature. For additional details of these adjustments and reconciliation of net income to adjusted EBITDA and adjusted gross margin that reflect these adjustments see the table on page 54 of this Form 10-Q.

Three Months Ended June 30, 2016 Compared to Three Months Ended June 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 June 30, 2016	Total		Networks			Renewables			Gas			Other(1)
	(in millions)
Adjusted gross margin (2)	$	1,157	$	934		$	239		$	(11	)	$	(5	)
Adjusted gross margin %				77	%		98	%		100	%		63	%
Adjusted EBITDA (2)	$	535	$	426		$	138		$	(22	)	$	(7	)
Adjusted EBITDA %				35	%		57	%		200	%		88	%

Three Months Ended June 30, 2015	Total		Networks			Renewables			Gas			Other(1)
	(in millions)
Adjusted gross margin (2)	$	755	$	563		$	221		$	(11	)	$	(18	)
Adjusted gross margin %				78	%		88	%		110	%		64	%
Adjusted EBITDA (2)	$	267	$	194		$	104		$	(22	)	$	(9	)
Adjusted EBITDA %				27	%		41	%		—			32	%

(1) Other amounts represent corporate and company eliminations.

(2) Adjusted EBITDA and adjusted gross margin are presented before reflecting a full six month period of 2015 UIL results, excluding gain on sale of equity method and other investment, impairment of investment, costs related to merger with UIL and before adjustment to reflect classification of revenues and expenses by nature. For additional details of these adjustments and reconciliation of net income to adjusted EBITDA and adjusted gross margin that reflect these adjustments see the table on page 54 of this Form 10-Q.

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Our adjusted gross margin increased by $403 million, or 53%, from $755 million for the three months ended June 30, 2015 to $1,157 million for the three months ended June 30, 2016.

Our adjusted EBITDA increased by $268 million, or 100%, from $267 million for the three months ended June 30, 2015 to $535 million for the three months ended June 30, 2016.

Details of the period to period comparison are described below at the segment level.

Networks

Adjusted gross margin increased by $371 million from $563 for the three months ended June 30, 2015 to $934 million for the three months ended June 30, 2016. The increase is associated primarily with the addition of UIL which added $224 million to the second quarter of 2016.  Underlying margins increased by $148 million.  The primary driver of the improvement is the increase in revenues, which is being driven by increases in regulatory recoveries for items such as Ginna RSSA and unfunded future income taxes.

Adjusted EBITDA increased by $232 million or 120% from $194 million for the three months ended June 30, 2015 to $426 million for the three months ended June 30, 2016. The impact of UIL added $85 million of EBITDA in 2016, with underlying business EBITDA increasing by $109 million.  The increase in the underlying EBITDA relates to the items mentioned above for adjusted gross margin, partially offset by increases in operations and maintenance expense driven by regulatory adjustments, such as the Ginna RSSA expense.

Renewables

Adjusted gross margin increased by $18 million, or 9%, from $221 million for the three months ended June 30, 2015 to $239 million for the three months ended June 30, 2016. The increase was due to a combination of increases in wind production and favorable MtM movement on derivatives.

Adjusted EBITDA increased by $34 million, or 34%, from $104 million for the three months ended June 30, 2015 to $138 million for the three months ended June 30, 2016. The increase was primarily due to the same reasons discussed above for adjusted gross margin in combination with decreases in operations and maintenance expenses relating to bad debt expense and cost management.

Gas

Adjusted gross margin stayed flat at $11 million for the three months ended June 30, 2015 and June 30, 2016.

Adjusted EBITDA also remained flat at negative $22 million for the three months ended June 30, 2015 and June 30, 2016.

Six Months Ended June 30, 2016 Compared to Six Months Ended June 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:

Six Months Ended June 30, 2016	Total		Networks			Renewables			Gas			Other(1)
	(in millions)
Adjusted gross margin (2)	$	2,338	$	1,883		$	460		$	1		$	(6	)
Adjusted gross margin %				72	%		88	%		100	%		33	%
Adjusted EBITDA (2)	$	1,089	$	856		$	267		$	(25	)	$	(9	)
Adjusted EBITDA %				33	%		51	%		(2500	)%		50	%

Six Months Ended June 30, 2015	Total		Networks			Renewables			Gas			Other(1)
	(in millions)
Adjusted gross margin (2)	$	1,557	$	1,173		$	420		$	(13	)	$	(23	)
Adjusted gross margin %				68	%		86	%		118	%		53	%
Adjusted EBITDA (2)	$	638	$	469		$	213		$	(32	)		(12	)
Adjusted EBITDA %				27	%		43	%		—			28	%

(1) Other amounts represent corporate and company eliminations.

(2) Adjusted EBITDA and adjusted gross margin are presented before reflecting a full six month period of 2015 UIL results, excluding gain on sale of equity method and other investment, impairment of investment, costs related to merger with UIL and before adjustments to reflect classification of revenues and expenses by nature. For additional details of these adjustments and reconciliation of net income to adjusted EBITDA and adjusted gross margin that reflect these adjustments see the table on page 54 of this Form 10-Q.

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Our adjusted gross margin increased by $782 million, or 50%, from $1.6 billion for the six months ended June 30, 2015 to $2.3 billion for the six months ended June 30, 2016.

Our adjusted EBITDA increased by $453 million, or 71%, from $638 million for the six months ended June 30, 2015 to $1.0 billion for the six months ended June 30, 2016.

Details of the period to period comparison are described below at the segment level.

Networks

Adjusted gross margin increased by $710 million from $1.2 billion for the six months ended June 30, 2015 to $1.9 billion for the six months ended June 30, 2016. The increase is associated primarily with the addition of UIL which added $518 million of gross margin.  Underlying margins increased by $192 million. Although volume of both sales and purchased power were lower due to the mild winter in 2016, purchased power rates decreased comparatively more, due to declines in market prices in 2016, which, combined with increases in regulatory recoveries, increased margins in 2016, partly offset by increases in the cost of transmission wheeling year over year.

Adjusted EBITDA increased by $387 million or 83% from $469 million for the six months ended June 30, 2015 to $856 million for the six months ended June 30, 2016. The impact of UIL added $233 million of EBITDA in 2016, with underlying business EBITDA increasing by $154 million for the six months ended June 30, 2016 as compared to the same period of 2015. The increase was due to the same reasons discussed above for adjusted gross margin, partly offset by an increase in operations and maintenance expenses for transmission system reliability support.

Renewables

Adjusted gross margin increased by $40 million, or 10%, from $420 million for the six months ended June 30, 2015 to $460 million for the six months ended June 30, 2016. The increase was due to the increase in revenues from increases in wind production and sales of transmission rights.

Adjusted EBITDA increased by $54 million, or 26%, from $213 million for the six months ended June 30, 2015 to $267 million for the six months ended June 30, 2016. In addition to the same reasons discussed above for adjusted gross margin, operations and maintenance expenses were lower, related to reductions in bad debt and asset retirement obligation expenses.

Gas

Adjusted gross margin increased by $14 million, or 100%, from negative $13 million for the six months ended June 30, 2015 to $1 million for the six months ended June 30, 2016. The increase is associated with the increase in operating revenues due to improved performance in capturing spreads in the owned storage and gas transportation areas in the current period as compared to the same period of 2015.

Adjusted EBITDA increased by $7 million, or 1%, from negative $32 million for the six months ended June 30, 2015 to negative $25 million for the six months ended June 30, 2016. The increase was due primarily to the same reasons discussed above for adjusted gross margin combined with operations and maintenance expense increases in the six months period ended June 30, 2016 resulting from higher credit support costs and external services.

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The following table provides a reconciliation between Net Income attributable to AVANGRID and adjusted gross margin and adjusted EBITDA after reflecting a full six month period of 2015 UIL results, excluding gain on sale of equity method and other investment, impairment of investment, costs related to merger with UIL and after adjustments to reflect classification of revenues and expenses by nature for the three and six months ended June 30, 2016 and 2015, respectively:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	102		$	11		$	314		$	117
Adjustments:
Add: Net Income representing a full six month period of 2015 for UIL		—			15			—			73
Merger costs		—			9			—			23
Sale of equity method and other investment		(3	)		—			(36	)		—
Impairment of investment		—			—			3			—
�� Income tax impact of adjustments (6)		1			(4	)		14			(10	)
Adjusted Net Income	$	100		$	31		$	295		$	203
Add: Income tax expense (2)		52			28			154			108
Depreciation and amortization (3)		260			293			509			546
Impairment of non-current assets		—			7			—			7
Interest expense, net of capitalization (4)		34			57			91			109
Less: Earnings from equity method investments		—			3			1			8
Adjusted EBITDA (7)	$	446		$	413		$	1,048		$	965
Add: Operations and maintenance (1) (5)		363			331			669			671
Taxes other than income taxes		124			119			262			249
Adjusted gross margin (7)	$	932		$	862		$	1,979		$	1,885

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

(2) 2016: Adjustments have been made for production tax credit adjustments for the amount of $9 million and $18 million for three and six months ended June 30, 2016, respectively, as they have been included in operating revenues and $126 million for Unfunded Future Income Taxes as amounts have been reclassified from revenues based on the by nature classification.

2015: In addition to adjustments to include a full six month period of 2015 results for UIL, adjustments have been made for production tax credit adjustments for the amount of $10 million and $17 million for the three and six month ended June 30, 2015, as they have been included in operating revenues based on the by nature classification.

(3) 2016: Adjustments have been made for the inclusion of vehicle depreciation and bad debt provision within depreciation and amortization from operations and maintenance based on the by nature classification. Vehicle depreciation of $6 million and $10 million and bad debt provision of $8 million and $12 million, for the three and six months ended June 30, 2016, respectively.  Additionally, government grants and investment tax credits amortization have been presented within other operating income and not within depreciation and amortization based on the by nature classification.  Government grants of $1.7 million and $3.4 million and investment tax credits of $26 million and $45 million, for the three and six month periods ended June 30, 2016, respectively.

2015: In addition to adjustments to include a full six month period of 2015 results for UIL, adjustments have been made for the inclusion of vehicle depreciation and bad debt provision within depreciation and amortization from operations and maintenance based on the by nature classification. Vehicle depreciation of $3 million and $7 million and bad debt provision of $10 million and $22 million, for the three and six months ended June 30, 2015, respectively.  Additionally, government grants and investment tax credits amortization have been presented within other operating income and not within depreciation and amortization based on the by nature classification. Government grants of $1.7 million and $3.4 million and investment tax credits of $20 million and $51 million, for the three and six month periods ended June 30, 2015, respectively.

(4) 2016: Adjustments have been made for allowance for funds used during construction, debt portion, to reflect these amounts within other income and expenses.

2015: In addition to adjustments to include a full six month period of 2015 results for UIL, adjustments have been made for allowance for funds used during construction, debt portion, to reflect these amounts within other income and expenses.

(5) 2016: Adjustments have been made for regulatory amounts to reflect amounts in revenues based on the by nature classification of these items.  In addition, the vehicle depreciation and bad debt provision have been reflected within depreciation and amortization.  

2015: In addition to adjustments to include a full six month period of 2015 results for UIL, adjustments have been made for regulatory amounts to reflect amounts in revenues based on the by nature classification of these items. In addition, the vehicle depreciation and bad debt provision have been reflected within depreciation and amortization.

(6) 2016: Income tax impact of adjustments: $14 million from sale of equity method investment, $1 million from sale of other investment and $(1) million on impairment of investment.

(7) Adjusted EBITDA and adjusted gross margin are presented after reflecting a full six month period of 2015 UIL results, excluding gain on sale of equity method and other investment, impairment of investment, costs related to merger with UIL and after adjustments to reflect classification of revenues and expenses by nature explained in notes (2)-(6) above.

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The following table provides a reconciliation between EPS attributable to AVANGRID and adjusted EPS after reflecting a full six month period of 2015 UIL results, excluding gain on sale of equity method and other investment, impairment of investment and costs related to merger with UIL for the three and six months ended June 31, 2016 and 2015, respectively:

	Three Months Ended						Six Months Ended
	June 30,						June 30,
	2016			2015			2016			2015
Networks	$	0.25		$	0.11		$	0.79		$	0.47
Renewables		0.13			0.27			0.27			0.37
Other (1)		(0.06	)		(0.33	)		(0.04	)		(0.38	)
Earnings Per Share		0.33			0.04			1.01			0.46
Adjustments:
Reduction for acquisition of UIL shares		—			(0.01	)		—			(0.08	)
Net income representing a full six month    period of 2015 UIL results		—			0.05			—			0.24
Merger costs		—			0.03			—			0.07
Sale of equity method and other investment		(0.01	)		—			(0.12	)		—
Impairment of investment		—			—			0.01			—
Income tax impact of adjustments		—			(0.01	)		0.05			(0.03	)
Adjusted Earnings Per Share	$	0.32		$	0.10		$	0.95		$	0.66

(1) Other includes Gas business and other non-regulated entities, including corporate.

Liquidity and Capital Resources

Our operations, capital investment and business development require significant short-term liquidity and long-term capital resources. 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 us. Risks may increase due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions.

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 financing agreements, and we and our subsidiaries were in compliance with such covenants as of June 30, 2016.

Liquidity Position

At June 30, 2016 and December 31, 2015, available liquidity was approximately $1,896 million and $1,546 million, respectively.

We manage our overall liquidity position as part of the group of companies controlled by Iberdrola, or the Iberdrola Group, and are a party to a notional cash pooling agreement with Bank Mendes Gans, N.V., BMG, along with other Iberdrola, S.A. subsidiaries. The notional cash pooling agreement aids the Iberdrola Group in efficient cash management and reduces the need for external borrowing by the pool participants. Parties to the agreement, including us, may deposit funds with or borrow from BMG, provided that the net balance of funds deposited or borrowed by all pool participants in the aggregate is not less than zero. Deposits are available for next day withdrawal. Deposit in the cash pooling account was $353 million at December 31, 2015. In advance of the United Kingdom “BREXIT” vote, we took steps to reposition our liquidity and our deposits with BMG were withdrawn and reinvested in money market accounts. The BMG balance at June 30, 2016 was zero. The deposit amounts are reflected in our consolidated balance sheet under cash and cash equivalents because our deposited surplus funds under the cash pooling agreement are highly-liquid short-term investments.

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The following table provides the components of our liquidity position as of June 30, 2016 and December 31, 2015, respectively:

	As of    June 30,		As of     December 31,
	2016		2015
	(in millions)
Cash and cash equivalents	$	396	$	427
AVANGRID Credit Facility		1,500		—
Less: borrowings		—		—
AVANGRID Revolving Credit Facility		—		300
Less: borrowings		—		—
Joint Utility Revolving Credit Facility		—		600
Less: borrowings		—		(14	)
UIL Credit Facility		—		400
Less: borrowings		—		(167	)
Total	$	1,896	$	1,546

AVANGRID Commercial Paper Program

On May 13, 2016, AVANGRID entered into (i) a Commercial Paper/Certificates of Deposit Issuing and Paying Agent Agreement, or Agency Agreement, with Bank of America, National Association, or BOA to facilitate AVANGRID’s Commercial Paper Program, and (ii) Commercial Paper Dealer Agreements, or Dealer Agreements with each of J.P. Morgan Securities Inc., Merrill Lynch, Pierce, Fenner & Smith Incorporated, Citigroup Global Markets, Inc., Mizuho Securities, Inc. and Mitsubishi UFJ Securities (USA), Inc., each a Dealer, under which each of these Dealers may act as dealer of the commercial paper issued under AVANGRID’s Commercial Paper Program. The AVANGRID commercial paper program is backstopped by the AVANGRID Credit Facility and has a limit of $1 billion.

The Agency Agreement provides that BOA shall act as agent for AVANGRID in connection with the issuance and payment of commercial paper notes, which are unsecured short-term promissory notes, or Notes, that may be issued or sold by AVANGRID in transactions exempt from registration under federal or state securities laws. The Notes will be book-entry obligations evidenced by a master note. In addition to providing for the issuance and payment of the Notes, the Agency Agreement also contains customary representations, warranties and indemnification provisions. The Notes will be the direct financial obligation of AVANGRID upon their issuance pursuant to the Agency Agreement. As of August 3, 2016, AVANGRID had not issued any Notes.

AVANGRID Credit Facility

On April 5, 2016, AVANGRID and its subsidiaries, NYSEG, RGE, CMP, UI, CNG, SCG and BGC entered into a revolving credit facility with a syndicate of banks, or the AVANGRID Credit Facility, that provides for maximum borrowings of up to $1.5 billion in the aggregate.

Under the terms of the AVANGRID Credit Facility, each joint borrower has a maximum borrowing entitlement, or sublimit, which can be periodically adjusted to address specific short-term capital funding needs, subject to the maximum limit established by the banks. AVANGRID’s maximum sublimit is $1 billion, NYSEG, RGE, CMP and UI have maximum sublimits of $250 million, CNG, and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $25 million. Under the AVANGRID Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating.  The facility fees will range from 10.0 to 17.5 basis points. The maturity date for the AVANGRID Credit Facility is April 5, 2021.

As a condition of closing on the AVANGRID Credit Facility, the AVANGRID Revolving Credit Facility, the Joint Utility Revolving Credit Facility, and the UIL Credit Facility, each described below, were terminated and all amounts payable under the terminated facilities were repaid in full. 

As of August 3, 2016 the AVANGRID Credit Facility is undrawn.

AVANGRID Revolving Credit Facility

The AVANGRID Revolving Credit Facility provided for maximum borrowings of up to $300 million and had a termination date in May 2019. As of December 31, 2015, this facility was undrawn. The facility was terminated on April 5, 2016, as a condition of closing on the AVANGRID Credit Facility.

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Joint Utility Revolving Credit Facility

The Joint Utility Revolving Credit Facility provided for maximum borrowings at NYSEG, RG&E and CMP of up to $600 million in the aggregate and had a termination date in July 2018.  This facility served as a backstop for CMP and NYSEG’s commercial paper programs. As of December 31, 2015, there was $586 million available under this facility. The facility was terminated on April 5, 2016, as a condition of closing on the AVANGRID Credit Facility.

UIL Credit Facility

The UIL Credit Facility provided for maximum borrowings at UIL, UI, CNG, SCG, and BGC of up to $400 million in the aggregate and had a termination date in November 2016. As of December 31, 2015, there was $233 million available under this facility. The facility was terminated on April 5, 2016, as a condition of closing on the AVANGRID Credit Facility.

Liquidity Management

We manage our overall liquidity position as part of the broader Iberdrola Group and are a party to a notional cash pooling agreement with BMG along with other Iberdrola, S.A. subsidiaries. We optimize our liquidity within the United States through a series of arms’-length intercompany lending arrangements with our subsidiaries and among the regulated utilities to provide for lending of surplus cash to subsidiaries with liquidity needs, subject to the limitation that the regulated utilities may not lend to unregulated affiliates. These arrangements minimize overall short-term funding costs and maximize returns on the temporary cash investments of the subsidiaries. Effective with the execution of the AVANGRID Credit Facility on April 5, 2016, we have the capacity to borrow up to $1.5 billion from the lenders committed to the facility. This represents an increase of $200 million in borrowing capacity relative to the amounts previously available under the three separate facilities – the AVANGRID Revolving Credit Facility, the Joint Utility Revolving Credit Facility and the UIL Credit Facility.

Capital Requirements

We expect to fund any quarterly shareholder dividends primarily from the cash provided by operations of our businesses in the future. We have a revolving credit facility, as described above, to fund short-term liquidity needs and we believe that we will have access to the capital markets should additional, long-term growth capital be necessary.

We expect to incur approximately $1.1 billion in capital expenditures through the end of 2016.

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 six months ended June 30, 2016 and 2015, respectively:

	Six Months Ended
	June 30,
	2016			2015
	(in millions)
Net cash provided by operating activities	$	908		$	782
Net cash used in investing activities		(537	)		(492	)
Net cash (used in) provided by financing activities		(402	)		213
Net (decrease) increase in cash and cash equivalents	$	(31	)	$	503

Operating Activities

For the six months ended June 30, 2016, net cash provided by operating activities was $908 million. During the six months ended June 30, 2016, Renewables contributed $268 million of operating cash flow associated with wholesale sales of energy, Networks contributed $487 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas, and Gas used $18 million in cash associated with losses on marketing of wholesale gas and gas storage services. Additionally, $17 million in cash was provided in support of the operating segments and changes in working capital provided $154 million in cash. The cash from operating activities for the six months ended June 30, 2016 compared to the six months ended June 30, 2015 increased by $126 million, primarily attributable to the increased operating revenues. The $204 million net change in operating assets and liabilities during the six months ended June 30, 2016 was primarily attributable to a net decrease of $73 million in accounts

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payable and receivable due to impacts from sales and purchases, decrease in inventories and other assets of $65 million and $330 million, respectively, offset by decrease in other liabilities and regulatory assets/liabilities of $430 million and $235 million, respectively.

For the six months ended June 30, 2015, net cash provided by operating activities was $782 million. During the six months ended June 30, 2015, Renewables contributed $385 million of operating cash flow associated with wholesale sales of energy, Networks contributed $513 million of operating cash as the result of regulated transmission and distribution sales of electricity and natural gas, and Gas used $23 million in cash associated with losses on marketing of wholesale gas and gas storage services. Additionally, $76 million in cash was used associated with corporate operating expenses in support of the operating segments and changes in working capital used $17 million in cash. The $153 million net change in net operating assets and liabilities during the six months ended June 30, 2015 was primarily attributable to increases in taxes accrued of $21 million and regulatory assets/liabilities of $95 million, offset by decreases in accounts receivable of $91 million, inventories of $73 million, other assets of $93 million, accounts payable of $131 million, and other liabilities of $89 million.

Investing Activities

For the six months ended June 30, 2016, net cash used in investing activities was $537 million, which was comprised of $470 million associated with capital expenditures at Networks and $203 million of capital expenditures at Renewables primarily associated with payments in support of the Desert Wind construction project. This was offset by $41 million of contributions in aid of construction, proceeds of $57 million from the sale of our equity method investment in Iroquois and other investment and $43 million from asset sale to the New York TransCo.

For the six months ended June 30, 2015, net cash used in investing activities was $492 million, primarily attributable to $355 million associated with capital expenditures at Networks. The remaining capital expenditure related cash outflows represent principally capital expenditures in Renewables, which is driven by significant progress in construction of the Baffin Bay wind asset in 2014. Under a turbine supply agreement, with Gamesa Corporación Tecnológica, S.A, payment for the supplied turbines did not take place until the first quarter of 2015.

Financing Activities

For the six months ended June 30, 2016, financing activities used $402 million in cash reflecting primarily a net decrease in non-current and current notes payable of $205 million, payments on the tax equity financing arrangements of $53 million, repurchase of common stock of $4 million and dividends of $134 million.

For the six months ended June 30, 2015, net cash provided by financing activities was $213 million. 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 and $20 million of long-term debt matured at CMP. This was offset by payment on the tax equity financing arrangements of $54 million.

Off-Balance Sheet Arrangements

There have been no material changes in the off-balance sheet arrangements during the six months ended June 30, 2016 as compared to those reported for the fiscal year ended December 31, 2015 in our Form 10-K.

Contractual Obligations

There have been no material changes in contractual and contingent obligations during the six months ended June 30, 2016  as compared to those reported for the fiscal year ended December 31, 2015 in our Form 10-K.

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 Form 10-K are those that depend most heavily on these judgments and estimates. As of June 30, 2016, there have been no material changes to any of the policies described therein, except as discussed below for the revision of the estimated useful lives of wind power station assets at Renewables.

Renewables’ wind power station assets in service less salvage value, if any, are depreciated using the straight-line method over their estimated useful lives. Renewables’ effective depreciation rate, excluding decommissioning, was 4.0% in both 2015 and 2014.

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Renewables reviews the estimated useful lives of its fixed assets on an ongoing basis. In the first quarter of 2016, this review indicated that the actual lives of certain assets at wind power stations are expected to be longer than the previously estimated useful lives used for depreciation purposes. As a result, effective January 1, 2016, Renewables changed the estimates of the useful lives of certain assets from 25 years to 40 years, capped at the lease term if lower, to better reflect the estimated periods during which these assets are expected to remain in service. The weighted average useful life of our wind farm assets is now approximately 30 years. We are continuing to assess lease extensions with leaseholders to potentially increase the average useful life of our wind farm assets to above 30 years.The effect of this change in estimate was to reduce depreciation and amortization expense by approximately $8 million and $25 million, reduce asset retirement obligation accretion expense recorded within operations and maintenance by approximately $0 and $1 million, increase earnings from equity method investments by approximately $1 million and $2 million, increase net income by $6 million and $18 million and increase basic and diluted earnings per share by approximately $0.02 and $0.06 for the three and six months ended June 30, 2016, respectively. For the full year 2016, the effect of this change on income before income tax and net income is estimated to be an increase of approximately $57 million and approximately $35 million, respectively, and the impact on earnings per share is estimated to be an increase of approximately $0.11 per share on a basic and diluted basis.

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 Form 10-K that we expect to have a material impact on our consolidated financial position, results of operations or liquidity.

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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 our plans, objectives and intentions, 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 business and other statements that are not historical facts. Such statements are based upon the current beliefs and expectations of our management and are subject to significant risks and uncertainties that could cause actual outcomes and results to differ materially. The foregoing and other factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC.Specifically, forward-looking statements may include statements relating to:

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

· success in retaining or recruiting, or changes required in, our officers, key employees or directors;

· 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 acquisition of UIL 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 six months ended June 30, 2016 as compared to those reported for the fiscal year ended December 31, 2015 in our Form 10-K.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer, or CEO, and our Chief Financial Officer, or 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 CEO 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.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please read “Note 8—Contingencies” and “Note 9—Environmental Liability” to the accompanying unaudited condensed consolidated financial statements under Part I, Item 1of this report for a discussion of the legal proceedings that we believe could be material to us.

Item 1A. Risk Factors

Shareholders and prospective investors should carefully consider the risk factors disclosed in our Form 10-K for the fiscal year ended December 31, 2015. There have been no material changes to such risk factors.

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
10.1	Commercial Paper/Certificates of Deposit Issuing and Paying Agent Agreement dated May 13, 2016 among Avangrid, Inc., as Issuer, and Bank of America, National Association, as Issuing and paying Agent.*
10.2	Form of Commercial Paper Dealer Agreement among Avangrid, Inc., as Issuer, and various Dealers.*
31.1	Chief Executive 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	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.*

*Filed herewith.

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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.

		Avangrid, Inc.
Date: August 4, 2016	By:	/s/ James P. Torgerson
		James P. Torgerson
		Director and Chief Executive Officer

Date: August 4, 2016	By:	/s/ Richard J. Nicholas
		Richard J. Nicholas
		Chief Financial Officer

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