UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended March 31, 2019

Or

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

For the transition period from to i

Commission File No. 001-37660

Avangrid, Inc.

(Exact Name of Registrant as Specified in its Charter)

New York	14-1798693
(State or other jurisdiction of incorporation or organization)	(I.R.S. Employer Identification No.)
180 Marsh Hill Road Orange, Connecticut	06477
(Address of principal executive offices)	(Zip Code)

Registrant’s telephone number, including area code: (207) 629-1200

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  ý    No  ¨

Indicate by check mark whether the registrant has submitted electronically every Interactive Data File required to be submitted pursuant to Rule 405 of Regulation S-T (§ 232.405 of this chapter) during the preceding 12 months (or for such shorter period that the registrant was required to submit such files).    Yes  ý    No  ¨

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

Large accelerated filer	ý	Accelerated filer	¨
Non-accelerated filer	¨	Smaller reporting company	¨
Emerging growth company	¨

If an emerging growth company, indicate by check mark if the registrant has elected not to use the extended transition period for complying with any new or revised financial accounting standards provided pursuant to Section 13(a) of the Exchange Act. ☐

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

As of April 30, 2019, the registrant had 309,005,272 shares of common stock, par value $0.01, outstanding.

Avangrid, Inc.

REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2019

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	48
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	59
Item 4.	Controls and Procedures	59
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,” “our” and the “Company” are used to refer to Avangrid, Inc. and its subsidiaries.

Consent order refers to the partial consent order issued by the Connecticut Department of Energy and Environmental Protection in August 2016.

English Station site refers tothe former generation site on the Mill River in New Haven, Connecticut.

Form 10-K refers to Avangrid, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2018, filed with the Securities and Exchange Commission on March 1, 2019.

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

Iberdrola refers to Iberdrola, S.A., which owns 81.5% of the outstanding shares of Avangrid, Inc.

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

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

Joint Proposal refers to the Joint Proposal, filed with the NYPSC on February 19, 2016 by NYSEG, RG&E and certain other signatory parties for a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2016.

Klamath Plant refers to the Klamath gas-fired cogeneration facility located in the city of Klamath, Oregon.

Non-GAAP refers to the financial measures that are not prepared in accordance with U.S. GAAP, including adjusted net income and adjusted earnings per share.

AOCI	Accumulated other comprehensive income
ARHI	Avangrid Renewables Holdings, Inc.
ARP	Alternative Revenue Programs
ASC	Accounting Standards Codification
AVANGRID	Avangrid, Inc.
Bcf	One billion cubic feet
BGC	The Berkshire Gas Company
Cayuga	Cayuga Operating Company, LLC
CfDs	Contracts for Differences
CL&P	The Connecticut Light and Power Company
CMP	Central Maine Power Company
CNG	Connecticut Natural Gas Corporation
DEEP	Connecticut Department of Energy and Environmental Protection
DIMP	Distribution Integrity Management Program
DOE	Department of Energy
DPA	Deferred Payment Arrangements
EBITDA	Earnings before interest, taxes, depreciation and amortization
ESM	Earnings sharing mechanism
Evergreen Power	Evergreen Power, LLC
Exchange Act	The Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FERC	Federal Energy Regulatory Commission
FirstEnergy	FirstEnergy Corp.
Gas	Enstor Gas, LLC
HLBV	Hypothetical Liquidation at Book Value
ISO	Independent system operator
KW	Kilowatts
LDCs	Local distribution companies
LIBOR	The London Interbank Offered Rate
MNG	Maine Natural Gas Corporation
MPUC	Maine Public Utility Commission
MtM	Mark-to-market
MW	Megawatts
MWh	Megawatt-hours
Networks	Avangrid Networks, Inc.
New York TransCo	New York TransCo, LLC.
NYPSC	New York State Public Service Commission
NYSEG	New York State Electric & Gas Corporation
NYSERDA	New York State Energy Research and Development Authority
OCI	Other comprehensive income
PJM	PJM Interconnection, L.L.C.
PURA	Connecticut Public Utilities Regulatory Authority
Renewables	Avangrid Renewables, LLC
RDM	Revenue Decoupling Mechanism
RG&E	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
Tax Act	Tax Cuts and Jobs Act of 2017 enacted by the U.S. federal government on December 22, 2017
TEF	Tax equity financing arrangements
UI	The United Illuminating Company
UIL	UIL Holdings Corporation
U.S. GAAP	Generally accepted accounting principles for financial reporting in the United States.
VIEs	Variable interest entities

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(unaudited)

	Three Months Ended March 31,
	2019			2018
(Millions, except for number of shares and per share data)
Operating Revenues	$	1,842		$	1,865
Operating Expenses
Purchased power, natural gas and fuel used	563			576
Loss from assets held for sale	—			5
Operations and maintenance	553			527
Depreciation and amortization	222			203
Taxes other than income taxes	163			151
Total Operating Expenses	1,501			1,462
Operating Income	341			403
Other Income and (Expense)
Other expense	(7		)	(21		)
Earnings from equity method investments	1			2
Interest expense, net of capitalization	(78		)	(74		)
Income Before Income Tax	257			310
Income tax expense	41			72
Net Income	216			238
Less: Net loss attributable to noncontrolling interests	(1		)	(6		)
Net Income Attributable to Avangrid, Inc.	$	217		$	244
Earnings Per Common Share, Basic	$	0.70		$	0.79
Earnings Per Common Share, Diluted	$	0.70		$	0.79
Weighted-average Number of Common Shares Outstanding:
Basic	309,491,082			309,513,640
Diluted	309,712,308			309,793,064

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 March 31,
	2019			2018
(Millions)
Net Income	$	216		$	238
Other Comprehensive Income (Loss)
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax $(10.9)	(29		)	—
Reclassification to net income of loss (gains) on cash flow hedges, net of income taxes of $0.7 and $(7.5), respectively	2			(10		)
Other Comprehensive Loss	(27		)	(10		)
Comprehensive Income	189			228
Less: Net loss attributable to noncontrolling interests	(1		)	(6		)
Comprehensive Income Attributable to Avangrid, Inc.	$	190		$	234

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

5

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	March 31,		December 31,
As of	2019		2018
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	33	$	36
Accounts receivable and unbilled revenues, net	1,264		1,142
Accounts receivable from affiliates	7		6
Derivative assets	13		16
Fuel and gas in storage	62		109
Materials and supplies	132		126
Prepayments and other current assets	255		229
Regulatory assets	232		299
Total Current Assets	1,998		1,963
Total Property, Plant and Equipment ($715 and $726 related to VIEs, respectively)	23,555		23,459
Operating lease right-of-use assets	81		—
Equity method investments	481		366
Other investments	57		58
Regulatory assets	2,612		2,640
Deferred income taxes regulatory	—		6
Other Assets
Goodwill	3,127		3,127
Intangible assets	321		323
Derivative assets	69		63
Other	307		162
Total Other Assets	3,824		3,675
Total Assets	$	32,608	$	32,167

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

6

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	March 31,			December 31,
As of	2019			2018
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	325		$	394
Notes payable	798			587
Interest accrued	70			62
Accounts payable and accrued liabilities	1,084			1,132
Accounts payable to affiliates	35			58
Dividends payable	137			136
Taxes accrued	68			59
Operating lease liabilities	10			—
Derivative liabilities	64			44
Other current liabilities	304			327
Regulatory liabilities	258			205
Total Current Liabilities	3,153			3,004
Regulatory liabilities	3,253			3,223
Other Non-current Liabilities
Deferred income taxes	1,524			1,530
Deferred income	1,368			1,385
Pension and other postretirement	1,115			1,102
Operating lease liabilities	73			—
Derivative liabilities	99			97
Asset retirement obligations	220			217
Environmental remediation costs	330			339
Other	530			499
Total Other Non-current Liabilities	5,259			5,169
Non-current debt	5,487			5,368
Total Non-current Liabilities	13,999			13,760
Total Liabilities	17,152			16,764
Commitments and Contingencies
Equity
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,752,140 shares issued; 309,005,272 shares outstanding, respectively	3			3
Additional paid in capital	13,658			13,657
Treasury stock	(12		)	(12		)
Retained earnings	1,620			1,528
Accumulated other comprehensive loss	(111		)	(72		)
Total Stockholders’ Equity	15,158			15,104
Non-controlling interests	298			299
Total Equity	15,456			15,403
Total Liabilities and Equity	$	32,608		$	32,167

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)

	Three Months Ended March 31,
	2019			2018
(Millions)
Cash Flow from Operating Activities:
Net income	$	216		$	238
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	222			203
Loss from assets held for sale	—			5
Regulatory assets/liabilities amortization and carrying cost	14			21
Pension cost	25			31
Earnings from equity method investments	(1		)	(2		)
Distributions of earnings received from equity method investments	2			3
Unrealized gain on marked-to-market derivative contracts	(3		)	(8		)
Deferred taxes	21			63
Other non-cash items	(2		)	(4		)
Changes in operating assets and liabilities:
Current assets	(43		)	(1		)
Noncurrent assets	(40		)	(45		)
Current liabilities	(44		)	(22		)
Noncurrent liabilities	(52		)	115
Net Cash Provided by Operating Activities	315			597
Cash Flow from Investing Activities:
Capital expenditures	(425		)	(399		)
Contributions in aid of construction	10			7
Proceeds from sale of assets	3			67
Distributions received from equity method investments	2			2
Other investments and equity method investments, net	(116		)	—
Net Cash Used in Investing Activities	(526		)	(323		)
Cash Flow from Financing Activities:
Non-current note issuance	194			—
Repayments of non-current debt	(43		)	(2		)
Receipts (repayments) of other short-term debt, net	211			(124		)
Repayments of financing leases	(21		)	(8		)
Issuance of common stock	—			(2		)
Distributions to noncontrolling interests	(3		)	(11		)
Contributions from noncontrolling interests	3			6
Dividends paid	(135		)	(134		)
Net Cash Provided by (Used in) Financing Activities	206			(275		)
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(5		)	(1		)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	43			46
Cash, Cash Equivalents and Restricted Cash, End of Period	$	38		$	45
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	58		$	49
Cash paid/(refund) for income taxes	$	2		$	(17	)

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 Loss			Total Stockholders’ Equity			Noncontrolling Interests			Total
As of December 31, 2017	309,005,272	$	3	$	13,653	$	(8	)	$	1,475		$	(46	)	$	15,077		$	19		$	15,096
Adoption of accounting standards	—	—		—		—			(3		)	(1		)	(4		)	140			136
Net income (loss)	—	—		—		—			244			—			244			(6		)	238
Other comprehensive loss, net of tax of $(7.5)	—	—		—		—			—			(10		)	(10		)	—			(10		)
Comprehensive income																					228
Dividends declared, $0.432/share	—	—		—		—			(134		)	—			(134		)	—			(134		)
Issuance of common stock	81,208	—		1		—			(3		)	—			(2		)	—			(2		)
Distributions to noncontrolling interests	—	—		—		—			—			—			—			(11		)	(11		)
Contributions from noncontrolling interests	—	—		—		—			—			—			—			6			6
As of March 31, 2018	309,086,480	$	3	$	13,654	$	(8	)	$	1,579		$	(57	)	$	15,171		$	148		$	15,319
As of December 31, 2018	309,005,272	$	3	$	13,657	$	(12	)	$	1,528		$	(72	)	$	15,104		$	299		$	15,403
Adoption of accounting standards	—	—		—		—			11			(12		)	(1		)	—			(1		)
Net income (loss)	—	—		—		—			217			—			217			(1		)	216
Other comprehensive loss, net of tax of $(10.2)	—	—		—		—			—			(27		)	(27		)	—			(27		)
Comprehensive income																					189
Dividends declared, $0.44/share	—	—		—		—			(136		)	—			(136		)	—			(136		)
Stock-based compensation	—	—		1		—			—			—			1			—			1
Distributions to noncontrolling interests	—	—		—		—			—			—			—			(3		)	(3		)
Contributions from noncontrolling interests	—	—		—		—						—			—			3			3
As of March 31, 2019	309,005,272	$	3	$	13,658	$	(12	)	$	1,620		$	(111	)	$	15,158		$	298		$	15,456

(*) 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 transmission and distribution business through its principal subsidiary, Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.5% the outstanding common stock of AVANGRID. The remaining outstanding shares are publicly traded on the New York Stock Exchange and owned by various shareholders. 

Note 2. Basis of Presentation

The accompanying notes should be read in conjunction with the notes to the consolidated financial statements of Avangrid, Inc. and subsidiaries as of December 31, 2018 and 2017 and for the three years ended December 31, 2018 included in AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2018.

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

We believe the disclosures made are adequate to make the information presented not misleading. In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated balance sheets, condensed consolidated statements of income, comprehensive income, cash flows and changes in equity for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three months ended March 31, 2019, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2019.

Note 3. Significant Accounting Policies and New Accounting Pronouncements

As of March 31, 2019, the new accounting pronouncements that we have adopted as of January 1, 2019, and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2018 and 2017, and for the three years ended December 31, 2018, except for the leases accounting policy described below.

Significant Accounting Policies

Leases

We determine if an arrangement is a lease at inception. We classify a lease as a finance lease if it meets any one of specified criteria that in essence transfers ownership of the underlying asset to us by the end of the lease term. If a lease does not meet any of those criteria, we classify it as an operating lease. On our condensed consolidated balance sheets, we include, for operating leases: "Operating lease right-of-use (ROU) assets", and "Operating lease liabilities (current and non-current)"; and for finance leases: finance lease ROU assets in "Other assets," and liabilities in "Other current liabilities" and "Other liabilities."

ROU assets represent our right to use an underlying asset for the lease term and lease liabilities represent our obligation to make lease payments arising from the lease. We recognize lease ROU assets and liabilities at commencement of an arrangement based on the present value of lease payments over the lease term. Most of our leases do not provide an implicit rate, so we use our incremental borrowing rate based on information available at the lease commencement date to determine the present value of future payments. A lease ROU asset also includes any lease payments made at or before commencement date, minus any lease incentives received, and includes initial direct costs incurred. We do not record leases with an initial term of 12 months or less on the balance sheet, for all classes of underlying assets, and we recognize lease expense for those leases on a straight-line basis over the lease term. We include variable lease payments that depend on an index or a rate in the ROU asset and lease liability measurement based on the index or rate at the commencement date, or upon a modification. We do not include variable lease payments that do not depend on an index or a rate in the ROU asset and lease liability measurement. A lease term includes options to extend or terminate the lease when it is reasonably certain that we will exercise that option. We recognize lease (rent) expense for operating

10

lease payments on a straight-line basis over the lease term, or for our regulated companies we recognize the amount eligible for recovery under their rate plans. We amortize finance lease ROU assets on a straight-line basis over the lease term and recognize interest expense based on the outstanding lease liability.

We have lease agreements with lease and nonlease components, and account for lease components and associated nonlease components together as a single lease component, for all classes of underlying assets.

Adoption of New Accounting Pronouncements

(a) Leases

In February 2016, the Financial Accounting Standards Board (FASB) issued Accounting Standards Codification (ASC) Topic 842, Leases, with subsequent amendments issued in 2018. The new leases guidance affects all companies and organizations that lease assets, and requires them to record on their balance sheet ROU assets and lease liabilities for the rights and obligations created by those leases. Under ASC 842, a lease is an arrangement that conveys the right to control the use of an identified asset for a period of time in exchange for consideration. The new guidance retains a distinction between finance leases and operating leases, while requiring companies to recognize both types of leases on their balance sheet. The classification criteria for distinguishing between finance leases and operating leases are substantially similar to the criteria for distinguishing between capital leases and operating leases in legacy U.S. GAAP - ASC 840. Lessor accounting remains substantially the same as ASC 840, but with some targeted improvements to align lessor accounting with the lessee accounting model and with the revised revenue recognition guidance under ASC 606. The new standard and amendments require new qualitative and quantitative disclosures for both lessees and lessors.

We adopted ASC 842 effective January 1, 2019, and elected the optional transition method under which we initially applied the standard on that date without adjusting amounts for prior periods, which we continue to present in accordance with ASC 840, including related disclosures. We recorded the cumulative effect of applying the new leases guidance as an adjustment to beginning retained earnings. In connection with our adoption, we:

• did not elect the package of three practical expedients available under the transition provisions which would have allowed us to not reassess: (i) whether expired or existing contracts were or contained leases, (ii) the lease classification for expired or existing leases, and (iii) whether previously capitalized initial direct costs for existing leases would qualify for capitalization under ASC 842.

• elected the land easement practical expedient and did not reassess land easements that did not meet the definition of a lease prior to adoption.

• used hindsight for determining the lease term and assessing the likelihood that a lease purchase option will be exercised in applying the new leases guidance.

• did not separate lease and associated non-lease components for transitioned leases, but instead are accounting for them together as a single lease component.

In March 2019, the FASB issued additional amendments to ASC 842 for minor codification improvements, which we early applied effective January 1, 2019, with no material effect to our consolidated results of operations, financial position and cash flows.

11

The cumulative effects of the changes to our condensed consolidated balance sheet as of January 1, 2019, were as follows:

	Balance at December 31, 2018		Adjustments Due to Topic 842			Balance at January 1, 2019
(Millions)
Assets
Total Property, Plant and Equipment	$	23,459	$	(147	)	$	23,312
Operating lease right-of-use assets	—		82			82
Other assets	162		146			308
Liabilities
Current portion of debt	$	394	$	(28	)	$	366
Operating lease liabilities, current	—		8			8
Other current liabilities	327		28			355
Operating lease liabilities, long-term	—		74			74
Other non-current liabilities	499		61			560
Non-current debt	5,368		(61		)	5,307
Equity
Retained earnings	$	1,528	$	(1	)	$	1,527

Our adoption did not change the classification of lease-related expenses in our condensed consolidated statements of income, and we do not expect significant changes to our pattern of expense recognition. Certain contracts previously classified as lessor leases, consisting mainly of Renewables’ power purchase agreements, no longer meet the definition of a lease under ASC 842. As such, these contracts are accounted for under other U.S. GAAP, but there were no changes to our pattern of revenue recognition. As a result, we expect our adoption will not materially affect our cash flows.

In comparison to our operating leases obligations disclosed as of December 31, 2018, certain land easement contracts that previously met the definition of a lease do not meet the ASC 842 definition of a lease, and therefore we excluded them from the transition adjustment. Our accounting for finance (formerly capital) leases is substantially unchanged. Refer to Note 8 for further details.

(b) Targeted improvements to accounting for hedging activities

In August 2017, the FASB issued targeted amendments with the objective to better align hedge accounting with an entity’s risk management activities in the financial statements, and to simplify the application of hedge accounting. The amendments address concerns of financial statement preparers over difficulties with applying hedge accounting and limitations for hedging both nonfinancial and financial risks and concerns of financial statement users over how hedging activities are reported in financial statements. The amended presentation and disclosure guidance is required only prospectively. Changes to the hedge accounting guidance to address those concerns will: 1) expand hedge accounting for nonfinancial and financial risk components and amend measurement methodologies to more closely align hedge accounting with an entity’s risk management activities; 2) eliminate the separate measurement and reporting of hedge ineffectiveness, to reduce the complexity of preparing and understanding hedge results; 3) enhance disclosures and change the presentation of hedge results to align the effects of the hedging instrument and the hedged item in order to enhance transparency, comparability and understandability of hedge results; and 4) simplify the way assessments of hedge effectiveness may be performed to reduce the cost and complexity of applying hedge accounting. The amendments ease the administrative burden of hedge documentation requirements and assessing hedge effectiveness going forward. We adopted the hedge accounting amendments January 1, 2019, and had no cumulative-effect adjustment to retained earnings because there were no amounts of ineffectiveness recorded for any existing hedges as of that date. Concurrently with the above targeted improvements, we adopted the additional amendments the FASB issued in October 2018 that permit use of the Overnight Index Swap rate based on the Secured Overnight Financing Rate as a U.S. benchmark interest rate for hedge accounting purposes. Use of that rate is in addition to the already eligible benchmark interest rates, which are: interest rates on direct Treasury obligations of the U.S. government, the London Interbank Offered Rate swap rate, the OIS Rate based on the Fed Funds Effective Rate and the Securities Industry and Financial Markets Association Municipal Swap Rate.

(c) Reclassification of certain tax effects from accumulated other comprehensive income

In February 2018, the FASB issued amendments to address a financial reporting issue that arose as a consequence of the Tax Cuts and Jobs Act of 2017 (the Tax Act) that the U.S. federal government enacted on December 22, 2017. Under previous guidance, an entity was required to include the adjustment of deferred taxes for the effect of a change in tax laws or rates in income from continuing operations, thus the associated tax effects of items within AOCI (referred to as stranded tax effects) did not reflect the appropriate tax rate. The amendments allow a reclassification from AOCI to retained earnings to eliminate the stranded tax effects

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resulting from the Tax Act. The amendments only relate to the reclassification of the income tax effects of the Tax Act, and do not affect the underlying guidance that requires the effect of a change in tax laws or rates to be included in income from continuing operations. We adopted the amendments effective January 1, 2019, and elected to reclassify the stranded tax effects of the Tax Act from AOCI to retained earnings at the beginning of the period of adoption. As a result, we reclassified approximately $12 million from AOCI to retained earnings within our condensed consolidated statements of changes in equity.

Accounting Pronouncements Issued But Not Yet Adopted

There have been no new accounting pronouncements issued since December 31, 2018, but not yet adopted that have an effect on our condensed consolidated financial statements.

Note 4. Revenue

We recognize revenue when we have satisfied our obligations under the terms of a contract with a customer, which generally occurs when the control of promised goods or services transfers to the customer. We measure revenue as the amount of consideration we expect to receive in exchange for providing those goods or services. Contracts with customers may include multiple performance obligations. For such contracts, we allocate revenue to each performance obligation based on its relative standalone selling price. We generally determine standalone selling prices based on the prices charged to customers. Certain revenues are not within the scope of ASC 606, such as revenues from leasing, derivatives, other revenues that are not from contracts with customers and other contractual rights or obligations, and we account for such revenues in accordance with the applicable accounting standards. We exclude from revenue amounts collected on behalf of third parties, including any such taxes collected from customers and remitted to governmental authorities. We do not have any significant payment terms that are material because we receive payment at or shortly after the point of sale.

The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about reportable segments, refer to Note 14.

Networks Segment

Networks derives its revenue primarily from tariff-based sales of electricity and natural gas service to customers in New York, Connecticut, Maine and Massachusetts, with no defined contractual term. For such revenues, we recognize revenues in an amount derived from the commodities delivered to customers. Other major sources of revenue are electricity transmission and wholesale sales of electricity and natural gas.

Tariff-based sales are subject to the corresponding state regulatory authorities, which determine prices and other terms of service through the ratemaking process. Maine state law prohibits the utility from providing the electricity commodity to customers. In New York, Connecticut and Massachusetts, customers have the option to obtain the electricity or natural gas commodity directly from the utility or from another supplier. For customers that receive their commodity from another supplier, the utility acts as an agent and delivers the electricity or natural gas provided by that supplier. Revenue in those cases is only for providing the service of delivery of the commodity.

Transmission revenue results from others’ use of the utility’s transmission system to transmit electricity and is subject to Federal Energy Regulatory Commission (FERC) regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on individual bilateral contracts. Short-term wholesale sales of electricity are generally on a daily basis based on market prices and are administered by the Independent System Operator-New England (ISO-NE) and the New York Independent System Operator (NYISO), or PJM Interconnection, L.L.C. (PJM), as applicable. Wholesale sales of natural gas are generally short-term based on market prices through contracts with the specific customer.

The performance obligation in all arrangements is satisfied over time because the customer simultaneously receives and consumes the benefits as Networks delivers or sells the electricity or natural gas or provides the delivery or transmission service.

Certain Networks entities record revenue from Alternative Revenue Programs (ARPs), which is not ASC 606 revenue. Such programs represent contracts between the utilities and their regulators. The Networks ARPs include revenue decoupling mechanisms, other ratemaking mechanisms, annual revenue requirement reconciliations and other demand side management programs.

Networks also has various other sources of revenue including billing, collection, other administrative charges, sundry billings, rent of utility property and miscellaneous revenue. It classifies such revenues as other ASC 606 revenues to the extent they are not related to revenue generating activities from leasing, derivatives or ARPs.

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Renewables Segment

Renewables derives its revenue primarily from the sale of energy, transmission, capacity and other related charges from its renewable wind, solar and thermal energy generating sources. For such revenues, we will recognize revenues in an amount derived from the commodities delivered and from services as they are made available. Renewables has bundled power purchase agreements consisting of electric energy, transmission, capacity and/or renewable energy credits (RECs). The related contracts are generally long-term with no stated contract amount, that is, the customer is entitled to all of the unit’s output. Renewables also has unbundled sales of electric energy and capacity, RECs and natural gas, which are generally for periods of less than a year. The performance obligations in substantially all of both bundled and unbundled arrangements for electricity and natural gas are satisfied over time, for which we record revenue based on the amount invoiced to the customer for the actual energy delivered. The performance obligation for stand-alone RECs is satisfied at a point in time, for which we record revenue when the performance obligation is satisfied upon delivery of the REC.

Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of Topic 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other Topic 606 revenue, which we recognize based on the amount invoiced to the customer.

Other

Other, which does not represent a segment, derives its revenues primarily from providing natural gas storage services to customers, gas trading operations generally classified as derivative revenue in accordance with the applicable accounting standards, gas trading contracts not classified as derivatives and other miscellaneous revenues including intersegment eliminations.

Contract Costs and Contract Liabilities

We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid for during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2021 upon commercial operation. We also have a contract asset for costs incurred to cancel a PPA, which we will amortize over the 10-year expected life of a new replacement PPA to be signed for the development project that will commence upon completion of the project. Contract assets totaled $12 million and $9 million at March 31, 2019 and December 31, 2018, respectively, and are presented in "Other non-current assets" on our condensed consolidated balance sheets.

We have contract liabilities for revenue from transmission congestion contract (TCC) auctions, for which we receive payment at the beginning of an auction period, and amortize ratably each month into revenue over the applicable auction period. The auction periods range from six months to two years. TCC contract liabilities totaled $5 million and $9 million at March 31, 2019 and December 31, 2018, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $5 million and $4 million as revenue during the three months ended March 31, 2019 and 2018.

Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2019 and 2018 are as follows:

	Three Months Ended March 31, 2019
	Networks		Renewables			Other (b)			Total
(Millions)
Regulated operations – electricity	$	913	$	—		$	—		$	913
Regulated operations – natural gas	625		—			—			625
Nonregulated operations – wind	—		182			—			182
Nonregulated operations – solar	—		5			—			5
Nonregulated operations – thermal	—		16			—			16
Nonregulated operations – gas storage	—		—			—			—
Other(a)	37		(7		)	(4		)	26
Revenue from contracts with customers	1,575		196			(4		)	1,767
Leasing revenue	1		—			—			1
Derivative revenue	—		41			—			41
Alternative revenue programs	16		—			—			16
Other revenue	12		5			—			17
Total operating revenues	$	1,604	$	242		$	(4	)	$	1,842

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	Three Months Ended March 31, 2018
	Networks		Renewables			Other (b)		Total
(Millions)
Regulated operations – electricity	$	926	$	—		$	—	$	926
Regulated operations – natural gas	572		—			—		572
Nonregulated operations – wind	—		168			—		168
Nonregulated operations – solar	—		2			—		2
Nonregulated operations – thermal	—		13			—		13
Nonregulated operations – gas storage	—		—			4		4
Other(a)	25		(23		)	15		17
Revenue from contracts with customers	1,523		160			19		1,702
Leasing revenue	9		81			—		90
Derivative revenue	—		43			10		53
Alternative revenue programs	19		—			—		19
Other revenue	1		—			—		1
Total operating revenues	$	1,552	$	284		$	29	$	1,865

(a) Primarily includes certain intra-month trading activities, billing, collection, and administrative charges, sundry billings, and other miscellaneous revenue.

(b) Does not represent a segment. Includes Corporate, Gas and intersegment eliminations.

Refer to Note 3 for details on the adoption of ASC 842 including a discussion regarding the classification of lease revenues.

As of March 31, 2019 and December 31, 2018, accounts receivable balances related to contracts with customers were approximately $1,203 million and $1,118 million, respectively, including unbilled revenues of $342 million and $374 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

As of March 31, 2019, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of March 31, 2019	2020		2021		2022		2023		2024		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	1	$	1	$	1	$	1	$	1	$	—	$	5
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	15		13		9		3		1		—		41
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	15		10		5		4		3		9		46
Total operating revenues	$	31	$	24	$	15	$	8	$	5	$	9	$	92

We do not disclose information about remaining performance obligations for contracts with usage-based pricing terms.

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. The primary items that are not included in the rate base or accruing carrying costs are the regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,775 million.

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On August 25, 2014, the Maine Public Utility Commission (MPUC) approved a stipulation agreement that provided for a distribution rate increase for Central Maine Power (CMP) of approximately $24.3 million, effective July 1, 2014, with an allowed return on equity (ROE) of 9.45% and an allowed equity ratio of 50%. The stipulation provided for the implementation of a revenue decoupling mechanism (RDM), reserve accounting and sharing of incremental storm costs, a separate proceeding for recovery of a new billing system and no earning sharing. On May 29, 2018, a ten-person complaint was filed with the MPUC against CMP, Networks and AVANGRID. The complaint requested that the MPUC open a rate case to determine if CMP is making excessive returns on investment and, therefore, whether CMP’s retail rates should be lower. The complaint also requested the MPUC deny certain costs associated with the October 2017 windstorm. On July 24, 2018, the MPUC issued an order dismissing the complaint and its associated request to deny the recovery of costs associated with the October 2017 windstorm. The order initiated an investigation into CMP’s rates and revenue requirement and directed CMP to make a filing consistent with the requirements for a general rate case no later than October 15, 2018. Consistent with the order in the ten-person complaint proceeding, on August 7, 2018, the MPUC issued a Notice of Investigation, opening the proceeding in which CMP would make its rate case filing and through which the MPUC will examine the rates and revenue requirements of CMP. On October 15, 2018, CMP filed a general rate case as directed by the MPUC requesting a ROE of 10% and an equity ratio of 55%. The company is proposing to use savings arising out of changes in federal taxation pursuant to the Tax Act to keep its distribution prices stable while making its electric system more reliable. The MPUC has established a ten-month process to review CMP’s filing and we expect a decision in October of 2019. CMP’s general rate case filing includes a proposal to enhance the resiliency of the energy grid by expanding vegetation management and pursuing additional reliability measures such as pole replacements and addition of tree wire in selected areas. Such investments are designed to strengthen CMP’s power grid so it can better stand up to severe weather. CMP is planning to use savings from the federal Tax Act to pay for the costs of resiliency programs, other investments in infrastructure and certain cost increases since 2014. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 14, 2019, the MPUC issued an Order and Notice of Investigation initiating an investigation of CMP’s metering and billing practices and initiating a separate investigation of the audit of CMP’s customer service and communication practices and incorporating such investigation into the general rate case. On February 22, 2019, the MPUC issued the MPUC staff Bench Analysis (BA) on all revenue requirement issues in this case, including customer service issues. The BA includes, among other things, a proposal to reduce CMP’s existing distribution rates by $2.0 - $3.6 million, inclusive of one-time items from July 2018, and implement a management efficiency adjustment as part of the rate setting process to reduce CMP’s allowed ROE of 9.35% by 75 to 100 basis points. We cannot predict the outcome of this matter.

On June 15, 2016, the New York State Public Service Commission (NYPSC) approved the Joint Proposal filed with the NYPSC by New York State Electric & Gas Corporation (NYSEG) and Rochester Gas and Electric Corporation (RG&E) and by certain other signatory parties on February 19, 2016, in connection with a three-year rate plan for electric and gas service at NYSEG and RG&E effective May 1, 2016. Following the approval of the Joint Proposal most of the regulatory deferrals related to NYSEG are amortized over a five-year period, except the portion of storm costs to be recovered over 10 years, unfunded deferred taxes being amortized over a period of 50 years and plant-related tax items which are amortized over the life of associated plant. Annual amortization expense for NYSEG is approximately $16.5 million per rate year. RG&E items that are being amortized are plant- related tax items, which are amortized over the life of associated plant, and unfunded deferred taxes being amortized over a period of 50 years. A majority of the other items related to RG&E, which net to a regulatory liability, remain deferred and will not be amortized until future proceedings.

The approved Joint Proposal provides for annual rate increases and allowed rates of return on common equity of 9.0% for NYSEG and RG&E. The equity ratio for each company is 48%; however, the equity ratio is set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increases as the ROE increases, with customers receiving 50%, 75% and 90% of earnings over 9.5%, 10.0% and 10.5% ROE, respectively, in the first rate year covering the period May 1, 2016 – April 30, 2017. The earnings sharing levels increase in rate year two (May 1, 2017 – April 30, 2018) to 9.65%, 10.15% and 10.65% ROE, respectively. The earnings sharing levels further increase in rate year three (May 1, 2018 – April 30, 2019) to 9.75%, 10.25% and 10.75% ROE, respectively. The rate plans also include the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates, and continuation of the existing RDM for each company. NYSEG and RG&E intend to file rate cases in New York in May 2019 for new tariffs effective in the second quarter of 2020.

In December 2016, the Connecticut Public Utilities Regulatory Authority (PURA) approved new distribution rate schedules for The United Illuminating Company (UI) for three years, which became effective January 1, 2017, and which, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50% equity ratio, continued UI’s existing earnings sharing mechanism (ESM) pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist.

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In December 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with rate increases of $1.5 million, $4.7 million and $5.0 million in 2018, 2019 and 2020, respectively. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism similar to the mechanisms authorized for Connecticut Natural Gas Corporation (CNG), ESM, the amortization of certain regulatory liabilities (most notably accumulated hardship deferral balances and certain accumulated deferred income taxes) and tariff increases based on a ROE of 9.25% and approximately 52% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.

On May 17, 2018, BGC filed a petition with the DPU seeking approval of a distribution rate increase to be effective January 1, 2019. On December 4, 2018, BGC and the Massachusetts Attorney General’s Office filed a settlement agreement with the DPU. The settlement agreement provides for a $1.6 million distribution base rate increase effective January 1, 2019, or February 1, 2019 if the DPU did not approve the settlement agreement prior to January 1, 2019, and an additional $0.7 million base distribution increase effective November 1, 2019, if certain investments are made by BGC. The settlement agreement contained a make-whole provision if the DPU approved the agreement after January 1, 2019. The distribution rate increase is based on a 9.70% ROE and 55% equity ratio. The settlement agreement provides for the implementation of a RDM and pension expense tracker and also provides that BGC will not file to change base distribution to become effective before November 1, 2021. The settlement agreement was approved by the DPU on January 18, 2019.

On June 29, 2018, Connecticut Natural Gas Corporation (CNG) filed an application with PURA for new tariffs to become effective January 1, 2019. On August 30, 2018, CNG entered into a settlement agreement with the Office of Consumer Counsel and PURA prosecutorial staff that provides for new rates effective January 1, 2019. The settlement agreement was approved by PURA on December 19, 2018. The settlement agreement included an increase in rates of $9.9 million in 2019, an increase of $4.6 million in 2020 and an increase of $5.2 million in 2021, for a total increase of $19.7 million over the three-year rate plan. The settlement agreement is based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021.

The regulatory assets and regulatory liabilities shown in the tables below result from various regulatory orders that allow for the deferral and/or reconciliation of specific costs. Regulatory assets and regulatory liabilities are classified as current when recovery or refund in the coming year is allowed or required through a specific order or when the rates related to a specific regulatory asset or regulatory liability are subject to automatic annual adjustment.

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Regulatory assets as of March 31, 2019 and December 31, 2018, respectively, consisted of:

	March 31,		December 31,
As of	2019		2018
(Millions)
Pension and other post-retirement benefits cost deferrals	$	140	$	141
Pension and other post-retirement benefits	1,105		1,138
Storm costs	360		346
Rate adjustment mechanism	12		18
Reliability support services	7		13
Revenue decoupling mechanism	6		7
Transmission revenue reconciliation mechanism	9		11
Electric supply reconciliation	—		2
Contracts for differences	99		97
Hardship programs	22		26
Deferred property tax	—		2
Plant decommissioning	9		11
Deferred purchased gas	6		37
Deferred transmission expense	4		11
Environmental remediation costs	275		278
Debt premium	104		118
Unamortized losses on reacquired debt	22		23
Unfunded future income taxes	371		371
Federal tax depreciation normalization adjustment	156		157
Asset retirement obligation	18		18
Deferred meter replacement costs	27		29
Deferred income taxes regulatory	—		6
Other	92		85
Total regulatory assets	2,844		2,945
Less: current portion	232		299
Total non-current regulatory assets	$	2,612	$	2,646

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

“Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer service restoration costs resulting from major storms when they meet certain criteria for severity and duration. As of March 31, 2019, the significant amounts deferred in storm costs include balances of $87 million and $58 million at NYSEG being recovered over ten-year and five-year periods, respectively, from the approval of the Joint Proposal by the NYPSC, and $144 million and $49 million at NYSEG and RG&E, respectively, not included in the Joint Proposal. The recovery of amounts not included in the Joint Proposal will be determined in future proceedings.

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

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

“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.

“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 deferred income tax liability recorded. The income tax benefits or charges

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for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. Following the approval of the Joint Proposal by the NYPSC, these amounts will be collected over a period of fifty years, and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances.

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

“Deferred property taxes” represents the customer portion of the difference between actual expense for property taxes and the amount provided for in rates. The amount for NYSEG and RG&E is being amortized over a five-year period following the approval of the Joint Proposal by the NYPSC.

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

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

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

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

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

“Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve month period.

“Reliability support services” represents the difference between actual expenses for reliability support services and the amount provided for in rates.

“Other” includes post term amortization deferrals and various items subject to reconciliation including rate change levelization and loss on re-acquired debt.

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Regulatory liabilities as of March 31, 2019 and December 31, 2018, respectively, consisted of:

	March 31,		December 31,
As of	2019		2018
(Millions)
Non by-passable charges	$	—	$	3
Energy efficiency portfolio standard	75		56
Gas supply charge and deferred natural gas cost	20		4
Transmission revenue reconciliation mechanism	8		7
Pension and other post-retirement benefits cost deferrals	93		97
Carrying costs on deferred income tax bonus depreciation	66		72
Carrying costs on deferred income tax - Mixed Services 263(a)	19		20
2017 Tax Act	1,525		1,509
Revenue decoupling mechanism	24		19
Rate adjustment mechanism	—		6
Hedges gains	4		5
Accrued removal obligations	1,161		1,153
Asset sale gain account	10		10
Economic development	29		28
Merger capital expense target customer credit account	6		6
Positive benefit adjustment	39		39
New York state tax rate change	8		7
Theoretical reserve flow thru impact	18		19
Deferred property tax	31		25
Net plant reconciliation	19		19
Variable rate debt	54		49
Rate refund – FERC ROE proceeding	30		29
Transmission congestion contracts	22		21
Merger-related rate credits	17		18
Accumulated deferred investment tax credits	14		14
Asset retirement obligation	13		13
Earning sharing provisions	17		17
Middletown/Norwalk local transmission network service collections	20		19
Excess generation service charge	—		7
Low income programs	37		38
Non-firm margin sharing credits	13		10
Other	119		88
Total regulatory liabilities	3,511		3,428
Less: current portion	258		205
Total non-current regulatory liabilities	$	3,253	$	3,223

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

“Energy efficiency portfolio standard” represents the difference between 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 located in Oswego, New York. The net proceeds from the Nine Mile Point 2 nuclear generating station were placed in this account and will be used to benefit customers. The amortization period is five years following the approval of the Joint Proposal by the NYPSC.

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

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

“Merger capital expense target customer credit account" was created as a result of NYSEG and RG&E not meeting certain capital expenditure requirements established in the order approving the purchase of AVANGRID (formerly Energy East Corporation) by Iberdrola. The amortization period is five years following the approval of the Joint Proposal by the NYPSC.

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

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

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

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

“2017 Tax Act” represents the impact from remeasurement of deferred income tax balances as a result of the Tax Act enacted by the U.S. federal government on December 22, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates from 35% to 21% under the provisions of the Tax Act will result in amounts previously and currently collected from utility customers for these deferred taxes to be refundable to such customers, generally through reductions in future rates. The NYPSC, MPUC, PURA and DPU have instituted separate proceedings in New York, Maine, Connecticut and Massachusetts, respectively, to review and address the implications associated with the Tax Act on the utilities providing service in such states.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. For both the three months ended March 31, 2019 and 2018, $1 million of rate credits were applied against customer bills.

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

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

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

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

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

• Our securities portfolio, consisting of Rabbi Trusts for deferred compensation plans, is primarily equity securities and money market funds. We measure the fair value of our securities portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1.

• NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their

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electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value in Level 1.

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

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

• UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 7 for further discussion of CfDs).

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

We determine the fair value of our interest rate swap derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 7 for further discussion of interest rate swaps).

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

Restricted cash was $5 million and $7 million as of March 31, 2019 and December 31, 2018, respectively, which is included in "Other Assets" on our condensed consolidated balance sheets.

The financial instruments measured at fair value as of March 31, 2019 and December 31, 2018, respectively, consisted of:

As of March 31, 2019	Level 1			Level 2			Level 3			Netting			Total
(Millions)
Equity investments with readily determinable fair values	$	34		$	—		$	—		$	—		$	34
Derivative assets
Derivative financial instruments - power	12			25			99			(58		)	78
Derivative financial instruments - gas	—			15			35			(50		)	—
Contracts for differences	—			—			4			—			4
Total	12			40			138			(108		)	82
Derivative liabilities
Derivative financial instruments - power	(11		)	(57		)	(49		)	100			(17		)
Derivative financial instruments - gas	—			(14		)	(7		)	16			(5		)
Contracts for differences	—			—			(103		)	—			(103		)
Derivative financial instruments – other	—			(37		)	(1		)	—			(38		)
Total	$	(11	)	$	(108	)	$	(160	)	$	116		$	(163	)

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As of December 31, 2018	Level 1			Level 2			Level 3			Netting			Total
(Millions)
Equity investments with readily determinable fair values	$	37		$	—		$	—		$	—		$	37
Derivative assets
Derivative financial instruments - power	17			23			91			(59		)	72
Derivative financial instruments - gas	1			20			36			(55		)	2
Contracts for differences	—			—			5			—			5
Total	18			43			132			(114		)	79
Derivative liabilities
Derivative financial instruments - power	(12		)	(41		)	(36		)	77			(12		)
Derivative financial instruments - gas	(1		)	(23		)	(7		)	22			(9		)
Contracts for differences	—			—			(102		)	—			(102		)
Derivative financial instruments - other	—			(16		)	(2		)	—			(18		)
Total	$	(13	)	$	(80	)	$	(147	)	$	99		$	(141	)

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2019 and 2018, respectively, is as follows:

	March 31,
(Millions)	2019			2018
Fair Value Beginning of Period,	$	(15	)	$	6
Gains recognized in operating revenues	25			5
(Losses) recognized in operating revenues	(13		)	(4		)
Total gains recognized in operating revenues	12			1
Gains recognized in OCI	1			—
(Losses) recognized in OCI	(15		)	(2		)
Total gains recognized in OCI	(14		)	(2		)
Net change recognized in regulatory assets and liabilities	(2		)	(11		)
Purchases	—			(2		)
Settlements	(3		)	(1		)
Fair Value as of March 31,	$	(22	)	$	(9	)
Gains for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$	12		$	1

For assets and liabilities that are recognized in the condensed consolidated financial statements at fair value on a recurring basis, we determine whether transfers have occurred between levels in the hierarchy by re-assessing categorization based on the lowest level of input that is significant to the fair value measurement as a whole at the end of each reporting period. There have been no transfers between Level 1 and Level 2 during the periods reported.

Level 3 Fair Value Measurement

The tables below illustrate the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives.

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As of March 31, 2019
Instruments	Instrument Description	Valuation Technique	Valuation Inputs	Index	Avg.		Max.		Min.
Fixed price power and gas swaps with delivery period > two years	Transactions with delivery periods exceeding two years	Transactions are valued against forward market prices on a discounted basis	Observable and extrapolated forward gas and power prices not all of which can be corroborated by market data for identical or similar products	NYMEX ($/MMBtu)	$	2.93	$	4.90	$	2.40
				Indiana hub ($/MWh)	$	30.74	$	61.12	$	19.10
				Mid C ($/MWh)	$	24.66	$	105.00	$	(0.50	)
				Minn hub ($/MWh)	$	25.29	$	52.17	$	12.51
				NoIL hub ($/MWh)	$	27.49	$	55.39	$	15.50

Our Level 3 valuations primarily consist of NYMEX gas and fixed price power swaps with delivery periods extending through 2024 and 2032, respectively. The gas swaps are used to hedge both gas inventory in firm storage and merchant wind positions. The power swaps are used to hedge merchant wind production in the West and Midwest.

We performed a sensitivity analysis around the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the only material input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The gas swaps are economic hedges of merchant generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.

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

Transactions are valued in part on the basis of forward price, correlation and volatility curves. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction.

The determination of 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	March 31, 2019
Risk of non-performance	0.37% - 0.63%
Discount rate	2.23% - 2.40%
Forward pricing ($ per KW-month)	$3.80 - $9.55

Fair Value of Debt

As of March 31, 2019 and December 31, 2018, 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 $6,183 million and $5,952 million as of March 31, 2019 and December 31, 2018, respectively. The estimated fair value was determined, in most cases, by

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discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy.

On January 15, 2019, UI, CNG, SCG and BGC issued $195 million in aggregate amount of notes and bonds with maturity dates ranging from 2029 to 2049 and interest rates ranging from 4.07% to 4.52%.

On April 1, 2019, NYSEG issued $12 million of Indiana County Industrial Development Authority Pollution Control Revenue Bonds in a private placement with a 2.65% interest rate and maturing in 2024.

Note 7. Derivative Instruments and Hedging

Our Networks and Renewables 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 our condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities.

(a) Networks activities

The tables below present Networks' derivative positions as of March 31, 2019 and December 31, 2018, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:

As of March 31, 2019	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	13		$	4		$	7		$	2
Derivative liabilities	(7		)	(2		)	(18		)	(95		)
	6			2			(11		)	(93		)
Designated as hedging instruments
Derivative assets	—			—			—			—
Derivative liabilities	—			—			(1		)	—
	—			—			(1		)	—
Total derivatives before offset of cash collateral	6			2			(12		)	(93		)
Cash collateral receivable	—			—			—			2
Total derivatives as presented in the balance sheet	$	6		$	2		$	(12	)	$	(91	)

As of December 31, 2018	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	18		$	6		$	10		$	3
Derivative liabilities	(10		)	(3		)	(21		)	(93		)
	8			3			(11		)	(90		)
Designated as hedging instruments
Derivative assets	—			—			—			—
Derivative liabilities	—			—			(2		)	—
	—			—			(2		)	—
Total derivatives before offset of cash collateral	8			3			(13		)	(90		)
Cash collateral receivable	—			—			—			—
Total derivatives as presented in the balance sheet	$	8		$	3		$	(13	)	$	(90	)

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The net notional volumes of the outstanding derivative instruments associated with Networks activities as of March 31, 2019 and December 31, 2018, respectively, consisted of:

	March 31,	December 31,
As of	2019	2018
(Millions)
Wholesale electricity purchase contracts (MWh)	4.5	4.9
Natural gas purchase contracts (Dth)	7.0	7.8
Fleet fuel purchase contracts (Gallons)	2.1	2.1

Derivatives not designated as hedging instruments

NYSEG and RG&E have an electric commodity charge that passes through rates costs for the market price of electricity. They use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and /or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations.

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

The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2019 and December 31, 2018 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2019 and 2018 are as follows:

(Millions)	Loss (Gain) Recognized in Regulatory Assets/Liabilities					Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As of						Three Months Ended March 31,
March 31, 2019	Electricity			Natural Gas		2019	Electricity			Natural Gas
Regulatory assets	$	2		$	—	Purchased power, natural gas and fuel used	$	4		$	—
Regulatory liabilities	$	(4	)	$	—
December 31, 2018						2018
Regulatory assets	$	5		$	—	Purchased power, natural gas and fuel used	$	(6	)	$	2
Regulatory liabilities	$	—		$	—

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

PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2019, UI has recorded a gross derivative asset of $4 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $99 million, a gross derivative liability of $103 million ($98 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2018, UI had recorded a gross derivative asset of $5 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $97 million, a gross derivative

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liability of $102 million ($96 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2019 and 2018, respectively, were as follows:

	Three Months Ended March 31,
	2019			2018
(Millions)
Derivative assets	$	(1	)	$	(2	)
Derivative liabilities	$	(1	)	$	(9	)

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2019 and 2018, respectively, consisted of:

Three Months Ended March 31,	Gain Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2019
Interest rate contracts	$	—	Interest expense	$	2	$	78
Commodity contracts	1		Purchased power, natural gas and fuel used	—		563
Total	$	1		$	2
2018
Interest rate contracts	$	—	Interest expense	$	2	$	74
Total	$	—		$	2

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

The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $58.8 million and $60.8 million as of March 31, 2019 and December 31, 2018, respectively. We recorded $2.0 million in net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2019 and 2018. We will amortize approximately $3.8 million of discontinued cash flow hedges for the remainder of 2019.

The unrealized loss of $0.9 million on hedge derivatives is reported in OCI because the forecasted transaction is considered to be probable as of March 31, 2019. We expect that $0.9 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 twelve months.

(b) Renewables 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.

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

Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms.

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The net notional volumes of outstanding derivative instruments associated with Renewables activities as of March 31, 2019 and December 31, 2018, respectively, consisted of:

	March 31,	December 31,
As of	2019	2018
(MWh/Dth in millions)
Wholesale electricity purchase contracts	5	5
Wholesale electricity sales contracts	7	6
Natural gas and other fuel purchase contracts	29	29
Financial power contracts	11	11
Basis swaps – purchases	41	42
Basis swaps – sales	3	4

The fair values of derivative contracts associated with Renewables activities as of March 31, 2019 and December 31, 2018, respectively, consisted of:

	March 31,			December 31,
As of	2019			2018
(Millions)
Wholesale electricity purchase contracts	$	32		$	11
Wholesale electricity sales contracts	(32		)	(12		)
Natural gas and other fuel purchase contracts	(2		)	(2		)
Financial power contracts	57			55
Basis swaps – purchases	(4		)	(6		)
Total	$	51		$	46

The tables below present Renewables' derivative positions as of March 31, 2019 and December 31, 2018, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:

As of March 31, 2019	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	21		$	103		$	29		$	16
Derivative liabilities	(3		)	(5		)	(53		)	(36		)
	18			98			(24		)	(20		)
Designated as hedging instruments
Derivative assets	—			1			1			2
Derivative liabilities	(3		)	—			(9		)	(20		)
	(3		)	1			(8		)	(18		)
Total derivatives before offset of cash collateral	15			99			(32		)	(38		)
Cash collateral receivable (payable)	(8		)	(32		)	17			30
Total derivatives as presented in the balance sheet	$	7		$	67		$	(15	)	$	(8	)

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As of December 31, 2018	Current Assets			Noncurrent Assets			Current Liabilities			Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	19		$	96		$	29		$	17
Derivative liabilities	(5		)	(3		)	(48		)	(35		)
	14			93			(19		)	(18		)
Designated as hedging instruments
Derivative assets	2			1			2			4
Derivative liabilities	—			—			(7		)	(10		)
	2			1			(5		)	(6		)
Total derivatives before offset of cash collateral	16			94			(24		)	(24		)
Cash collateral receivable (payable)	(8		)	(34		)	9			17
Total derivatives as presented in the balance sheet	$	8		$	60		$	(15	)	$	(7	)

Derivatives not designated as hedging instruments

The effects of trading and non-trading derivatives associated with Renewables activities for the three months ended March 31, 2019, consisted of:

	Three Months Ended
	March 31, 2019
	Trading			Non-trading			Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	1		$	—
Wholesale electricity sales contracts	—			(9		)
Financial power contracts	(1		)	(13		)
Financial and natural gas contracts	(1		)	(2		)
Total loss included in operating revenues	$	(1	)	$	(24	)	$	1,842
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	—			20
Wholesale electricity sales contracts	—			—
Financial power contracts	—			1
Financial and natural gas contracts	—			7
Total gain included in purchased power, natural gas and fuel used	$	—		$	28		$	563
Total (Loss) Gain	$	(1	)	$	4

The effects of trading and non-trading derivatives associated with Renewables activities for the three months ended March 31, 2018, consisted of:

	Three Months Ended
	March 31, 2018
(Millions)	Trading			Non-trading
Wholesale electricity purchase contracts	$	1		$	1
Wholesale electricity sales contracts	1			—
Financial power contracts	(1		)	3
Financial and natural gas contracts	3			5
Total Gain	$	4		$	9

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Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2019 and 2018, respectively, consisted of:

Three Months Ended March 31,	(Loss) Recognized in OCI on Derivatives (a)			Location of Loss (Gain) Reclassified from Accumulated OCI into Income	(Gain) Loss Reclassified from Accumulated OCI into Income			Total amount per Income Statement
(Millions)
2019
Commodity contracts	$	(20	)	Operating revenues	$	—		$	1,842
Total	$	(20	)		$	—
2018
Commodity contracts	$	(1	)	Operating revenues	$	(19	)	$	1,865
Total	$	(1	)		$	(19	)

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

Amounts are reclassified from accumulated OCI into income in the period during which the transaction being hedged affects earnings or when it becomes probable that a forecasted transaction being hedged would not occur. Notwithstanding future changes in prices, approximately $10.6 million of loss included in accumulated OCI at March 31, 2019, is expected to be reclassified into earnings within the next twelve months. The net loss in accumulated OCI related to a discontinued cash flow hedge is $0.4 million as of March 31, 2019, out of which no amount will be amortized in the remainder of 2019. We did not record any net derivative losses related to discontinued cash flow hedges for both the three months ended March 31, 2019 and 2018.

(c) Interest rate swaps

AVANGRID uses financial derivative instruments from time to time to alter its fixed and floating rate debt balances or to hedge fixed rates in anticipation of future fixed rate issuances. In 2018, AVANGRID entered into two forward interest rate swaps, with a total notional amount of $500 million, to hedge the issuance of forecasted fixed rate debt in 2019. In the first quarter of 2019, AVANGRID entered into one additional interest rate swap, with a notional amount of $250 million, for the same purpose. The forward interest rate swaps are designated and qualify as cash flow hedges, have mandatory termination dates of June 28, 2019, and are expected to be settled upon the forecasted debt issuance. The gain or loss on the interest rate swap derivative is reported as a component of accumulated OCI and reclassified into earnings in the period or periods during which related payments of the forecasted debt will occur.

The tables below present our interest rate swap derivative positions as of March 31, 2019 and December 31, 2018, respectively, including the location of the net derivative positions on our condensed consolidated balance sheets:

As of March 31, 2019	Current Liabilities
(Millions)
Designated as hedging instruments
Derivative liabilities	$	(36	)
As of December 31, 2018
Designated as hedging instruments
Derivative liabilities	$	(16	)

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The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2019 and 2018, respectively, consisted of:

Three Months Ended March 31,	Loss Recognized in OCI on Derivatives (a)
(Millions)
2019
Interest rate contracts	$	(20	)
2018
Interest rate contracts	$	—

(a) Changes in OCI are reported on a pre-tax basis. The amount in accumulated OCI is expected to be reclassified into earnings upon interest rate swap settlement over the underlying debt maturity period.

(d) Counterparty credit risk management

NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.

The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit rating on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2019, UI would have had to post an aggregate of approximately $18 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 a 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 $35 million and $26 million as of March 31, 2019 and December 31, 2018, respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our 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 March 31, 2019 is $2.5 million, for which we have posted collateral.

Note 8. Leases

We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation, and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 64 years, some of which may include options to extend the leases for up to 30 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option.

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The components of lease cost and other information related to leases were as follows:

	Three Months Ended March 31, 2019
(Millions)
Lease cost
Finance lease cost
Amortization of right-of-use assets	$	3
Interest on lease liabilities	1
Total finance lease cost	4
Operating lease cost	5
Short-term lease cost	1
Total lease cost	$	10

As of	March 31, 2019
(Millions, except lease term and discount rate)
Operating Leases
Operating lease right-of-use assets	$	81
Operating lease liabilities, current	10
Operating lease liabilities, long-term	73
Total operating lease liabilities	83
Finance Leases
Other assets	142
Other current liabilities	7
Other non-current liabilities	61
Total finance lease liabilities	$	68
Weighted-average Remaining Lease Term (years):
Finance leases	8.24
Operating leases	11.65
Weighted-average Discount Rate:
Finance leases	5.54		%
Operating leases	3.68		%

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Supplemental cash flow information related to leases was as follows:

	Three Months Ended March 31, 2019
(Millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	4
Operating cash flows from finance leases	$	—
Financing cash flows from finance leases	$	21
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	$	—
Operating leases	$	3

As of March 31, 2019, maturities of lease liabilities were as follows:

	Finance Leases			Operating Leases
(Millions)
Year ending December 31,
April 1, 2019 - December 31, 2019	$	8		$	10
2020	10			14
2021	6			13
2022	2			10
2023	50			8
Thereafter	4			58
Total lease payments	80			113
Less: imputed interest	(12		)	(30		)
Total	$	68		$	83

Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $52 million at both March 31, 2019 and December 31, 2018. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility.

Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments. We used the incremental borrowing rate on January 1, 2019, for operating leases that commenced prior to that date.

Comparative 2018 and 2017 Leases Disclosures

The following are the 2018 annual lease disclosures, presented in accordance with ASC 840.

Operating lease expense relating to operational facilities, office building leases and vehicle and equipment leases was $59.0 million, $71.5 million and $70.6 million for the years ended December 31, 2018, 2017 and 2016, respectively. Amounts related to contingent payments predominantly linked to electricity generation at the respective facilities were $10.6 million, $18.6 million and $22.2 million for the years ended December 31, 2018, 2017 and 2016, respectively. Leases for most of the land on which wind farm facilities are located have various renewal and termination clauses.

On January 16, 2014, as required by the NYPSC, NYSEG renewed a Reliability Support Services Agreement (RSS Agreement) with Cayuga Operating Company, LLC (Cayuga) for Cayuga to provide reliability support services to maintain necessary system reliability through June 2017. Cayuga owns and operates the Cayuga Generating Facility (Facility), a coal-fired generating station that includes two generating units. Cayuga operates and maintains the RSS units and manages and complies with scheduling deadlines and requirements for maintaining the Facility and the RSS units as eligible energy and capacity providers and complies with dispatch instructions. NYSEG paid Cayuga a monthly fixed price and also paid for capital expenditures for specified capital projects. NYSEG was entitled to a share of any capacity and energy revenues earned by Cayuga. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $17.6 million for the year ended December 31, 2017, and $37.8 million for the year ended December 31, 2016.

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On October 21, 2015, RG&E, GNPP and multiple intervenors filed a joint proposal with the regulator for approval of the modified RSS Agreement for the continued operation of the Ginna Facility. On February 23, 2016, the NYPSC unanimously adopted the joint proposal, which provided for a term of the RSSA from April 1, 2015, through March 31, 2017 and RG&E monthly payments to GNPP in the amount of $15.4 million. RG&E was entitled to 70% of revenues from GNPP’s sales into the energy and capacity markets, while GNPP was entitled to 30% of such revenues. We accounted for this arrangement as an operating lease. The net expense incurred under this operating lease was $5.6 million for the year ended December 31, 2017, and $114.9 million for the year ended December 31, 2016.

Total future minimum lease payments as of December 31, 2018 consisted of:

Year	Operating Leases		Capital Leases		Total
	(Millions)
2019	$	31	$	30	$	61
2020	39		10		49
2021	38		7		45
2022	35		2		37
2023	33		50		83
Thereafter	735		2		737
Total	$	911	$	101	$	1,012

Note 9. Contingencies

We are party to various legal disputes arising as part of our normal business activities. We assess our exposure to these matters and record estimated loss contingencies when a loss is likely and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency.

Transmission - ROE Complaint – CMP and UI

On September 30, 2011, the Massachusetts Attorney General, DPU, PURA, 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 joint complaint with the FERC pursuant to sections 206 and 306 of the Federal Power Act, against several New England Transmission Owners (NETOs) claiming that the approved base ROE of 11.14% used by NETOs in calculating formula rates for transmission service under the ISO-New England Open Access Transmission Tariff (OATT) was not just and reasonable and seeking a reduction of the base ROE with refunds to customers for the 15-month refund periods beginning October 1, 2011 (Complaint I), December 27, 2012 (Complaint II), July 31, 2014 (Complaint III) and April 29, 2016 (Complaint IV).

On October 16, 2014, the FERC issued its decision in Complaint I setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen 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 fifteen 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 in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners.

CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $23.7 million and $6.4 million, respectively, as of March 31, 2019, which has not changed since December 31, 2018, except for the accrual of carrying costs. If adopted as final by the FERC, the impact of the initial decision by the FERC administrative law judge would be an additional aggregate reserve for Complaints II and III of $17.1 million, which is based upon currently available information for these proceedings.

Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the FERC issued an order directing briefs and proposing a new methodology to calculate the NETOs ROE that is contained in NETOs’ transmission formula rate on file at the FERC (the October 2018 Order). The FERC proposes to use this new methodology to resolve Complaints I, II, III and IV filed by the New England state consumer advocates.

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The new proposed ROE methodology set forth in the October 2018 Order considers more than just the two-step discounted cash flow (DCF) analysis adopted in the FERC order on Complaint I vacated by the Court. The new proposed ROE methodology uses three financial analyses (i.e., DCF, the capital-asset pricing model and the expected earnings analysis) to produce a range of returns to narrow the zone of reasonableness when assessing whether a complainant has met its initial burden of demonstrating that the utility’s existing ROE is unjust and unreasonable. The new proposed ROE methodology establishes a range of just and reasonable ROEs of 9.60% to 10.99% and proposes a just and reasonable base ROE of 10.41% with a new ROE cap of 13.08%. Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replies to the initial briefs on March 8, 2019. We cannot predict the outcome of this proceeding.

New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm

On March 11, 2017, the New York State Department of Public Service (the Department) commenced an investigation of NYSEG’s and RG&E’s preparation for and response to the March 2017 windstorm, which affected more than 219,000 NYSEG and RG&E customers. The Department Staff issued a report (the Staff Report) of the findings from their investigation on November 16, 2017. The Staff Report made several recommendations for future storm response and also alleged that NYSEG and RG&E had violated their own emergency response plan in a number of respects.

Also on November 16, 2017, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Order) requiring the companies to address whether the NYPSC should mandate, reject or modify, in whole or in part the recommendations made in the Staff Report. The Order also required the companies to show cause why the NYPSC should not commence an administrative penalty proceeding. On May 18, 2018, NYSEG and RG&E filed a settlement joint proposal and investment joint proposal before the NYPSC to settle potential penalties and avoid litigation related to the March 2017 windstorm, pursuant to which, among other things, NYSEG and RG&E have agreed to make $3.9 million in investments designed to increase resiliency and improve emergency response in the areas impacted by the storm. The investments will not be reflected in rate base or operating expenses in establishing future delivery rates. On April 18, 2019, the NYPSC approved the joint proposals.

New York State Department of Public Service Investigation of the Preparation for and Response to the March 2018 Winter Storms

In March 2018, following two severe winter storms that impacted more than one million electric utility customers in New York, including 520,000 NYSEG and RG&E customers, the NYPSC initiated a comprehensive investigation of all the New York electric utilities’ preparation and response to those events. The investigation was expanded to include other 2018 New York spring storm events.

On April 18, 2019 the Department Staff issued a report (the 2018 Staff Report) of the findings from their investigation. The 2018 Staff Report identifies 94 recommendations for corrective actions to be implemented in the utilities Emergency Response Plans (ERP). The report also identified potential violations by several of the utilities, including NYSEG and RG&E.

Also on April 18, 2019, the NYPSC issued an Order Instituting Proceeding and to Show Cause directed to all major electric utilities in New York, including NYSEG and RG&E. The order directs the utilities, including NYSEG and RG&E, to show cause why the NYPSC should not pursue civil penalties, and / or administrative penalties for the apparent failure to follow their respective ERPs as approved and mandated by the NYPSC. The NYPSC also directs the utilities, within 30 days, to address whether the NYPSC should mandate, reject or modify in whole or in part, the 94 recommendations contained in the 2018 Staff Report. We cannot predict the final outcome of this matter. 

NYPSC Directs Counsel to Commence Judicial Enforcement Proceeding Against NYSEG

On April 18, 2019, the NYPSC issued an Order Directing Counsel to the Commission to commence a special proceeding or an action in New York State Supreme Court to stop and prevent ongoing future violations by NYSEG of NYPSC regulations and orders. As of the date hereof, a special proceeding or an action has not been commenced. Therefore, NYSEG cannot respond to or assess the merits of claims which may be brought and we cannot predict the final outcome of this matter.

California Energy Crisis Litigation

Two California agencies brought a complaint in 2001 against a long-term power purchase agreement entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the power purchase agreement were unjust and unreasonable. The FERC dismissed Renewables from the proceedings; however, the Ninth Circuit Court of Appeals reversed the FERC's dismissal of Renewables from the proceeding.

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

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

A hearing was held before a FERC administrative law judge in November and early December 2015. A preliminary proposed ruling by the administrative law judge was issued on April 12, 2016. The proposed ruling found no evidence that Renewables had engaged in any unlawful market conduct that would justify finding the Renewables power purchase agreements unjust and unreasonable. However, the proposed ruling did conclude that the 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 the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. There is not specific timetable for the FERC's ruling. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. We cannot predict the outcome of this proceeding.

Class Actions Regarding LDC Gas Transportation Service on Algonquin Gas Transmission

Breiding et al. v. Eversource and Avangrid - Class Action. On November 16, 2017, a class action lawsuit was filed in the U.S. District Court for the District of Massachusetts on behalf of customers in New England against the Company and Eversource alleging that certain of their respective subsidiaries that take gas transportation service over the Algonquin Gas Transmission (AGT), which for AVANGRID would be its indirect subsidiaries SCG and CNG, engaged in pipeline capacity scheduling practices on AGT that resulted in artificially increased electricity prices in New England. These allegations were based on the conclusions of a whitepaper issued by the Environmental Defense Fund (EDF), an environmental advocacy organization, on October 10, 2017, purporting to analyze the relationship between the New England electricity market and the New England local gas distribution companies. The plaintiffs assert claims under federal antitrust law, state antitrust, unfair competition and consumer protection laws, and under the common law of unjust enrichment. They seek damages, disgorgement, restitution, injunctive relief, and attorney fees and costs. On February 27, 2018, the FERC released the results of a FERC staff inquiry into the pipeline capacity scheduling practices on the AGT. The inquiry arose out of the allegations made by the EDF in its whitepaper. The FERC announced that, based on an extensive review of public and non-public data, it had determined that the EDF study was flawed and led to incorrect conclusions. FERC also stated that the staff inquiry revealed no evidence of anticompetitive withholding of natural gas pipeline capacity on the AGT and that it would take no further action on the matter. On April 27, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry conclusion. The plaintiffs filed opposition to the motion to dismiss on May 25, 2018. On September 11, 2018, the District Court granted the Company’s Motion and dismissed all claims. On October 10, 2018, the plaintiffs filed a notice of appeal and on February 25, 2019, plaintiffs filed their brief on appeal. We cannot predict the outcome of this appeal.

PNE Energy Supply LLC v. Eversource Energy and Avangrid, Inc. - Class Action. On August 10, 2018, PNE Energy Supply LLC, a competitive energy supplier located in New England that purchases electricity in the day-ahead and real time wholesale electric market, filed a civil antitrust action, on behalf of itself and those similarly situated, against the Company and Eversource alleging that their respective gas subsidiaries illegally manipulated the supply of pipeline capacity in the “secondary capacity market” in order to artificially inflate New England natural gas and electricity prices. These allegations were also based on the conclusions of the whitepaper issued by EDF. The plaintiff claims to represent entities who purchased electricity directly in the wholesale electricity market that it claims was targeted by the alleged anticompetitive conduct of Eversource and the Company. On September 28, 2018, the Company filed a Motion to Dismiss all of the claims based on federal preemption and lack of any evidence of antitrust behavior, citing, among other reasons, the results of the FERC staff inquiry and the dismissal of the related case, "Breiding et al. v. Eversource and Avangrid," by the same court in September. The plaintiffs filed opposition to the motion to dismiss on October 26, 2018 and the Company filed a reply on November 15, 2018. The district court heard oral arguments on the motion to dismiss on January 18, 2019. On April 26, 2019, the Company filed a brief in support of its motion to dismiss. We cannot predict the outcome of this class action lawsuit.

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. Pursuant to the statute of limitations, the Yankee Companies file a lawsuit periodically to recover damages from the Department of Energy (DOE) for breach of the Nuclear Spent Fuel Disposal Contract to remove spent nuclear fuel and greater than class C waste as required by contract.

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From 2012 to 2016 the Yankee Companies filed three claims against the DOE (Phase I, II and III) for the years from 1995 to 2012 and received damage awards, which flow through the Yankee Companies to shareholders (including CMP and UI based percentage of ownership) to reduce retail customer charges. On May 22, 2017, the Yankee Companies filed their next case (Phase IV) in the Federal Court of Claims (Court), seeking damages for the period from January 1, 2013 through December 31, 2016 and submitted their claimed Phase IV damages to the DOE in late August 2017. The Court issued its decision on the Phase IV trial on February 21, 2019, awarding the Yankee Companies a combined $103.2 million (Connecticut Yankee $40.7 million, Maine Yankee $34.4 million and Yankee Atomic $28.1 million). The damage awards are returned to customers either through customer refunds or by reducing future costs. Refunds or reductions in costs are reflected in the Yankee Companies billings to shareholders, including CMP and UI. CMP and UI will receive their proportionate share of the awards that flow through based on percentage of ownership. On April 23, 2019, the notice of appeal period expired and the Phase IV trial award became final.

Guarantee Commitments to Third Parties

As of March 31, 2019, we had approximately $476 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of March 31, 2019, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Note 10. Environmental Liabilities

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

Waste sites

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

We have recorded an estimated liability of $5 million related to ten of the twenty-five sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $8 million related to another eleven 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. Our estimate for costs to remediate these sites ranges from $12 million to $21 million as of March 31, 2019. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination, and the allocation of the clean-up costs.

Manufactured Gas Plants

We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Eight sites are included in the New York State Registry; three sites are included in the New York State Department of Environmental Conservation Multi-Site Order on Consent; three sites are part of Maine’s Voluntary Response Action Program with two such sites 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-one of the fifty-three sites.

Our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $188 million to $423 million as of March 31, 2019. 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.

Certain of our Connecticut and Massachusetts regulated gas companies own or have previously owned properties where MGPs had historically operated. MGP operations have led to contamination of soil and groundwater with petroleum hydrocarbons, benzene and metals, among other things, at these properties, the regulation and cleanup of which is regulated by the federal Resource Conservation and Recovery Act as well as other federal and state statutes and regulations. Each of the companies has

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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 related to these sites as of March 31, 2019 and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites.

As of March 31, 2019 and December 31, 2018, the liability associated with our MGP sites in Connecticut, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates, was $98 million and $99 million, respectively.

Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $360 million and $366 million as of March 31, 2019 and December 31, 2018, 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 2055.

FirstEnergy

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

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

FirstEnergy remains liable for a substantial share of clean up expenses at nine MGP sites. Based on current projections, FirstEnergy’s share is estimated at approximately $20 million. This amount is being treated as a contingent asset and has not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG ratepayers.

Century Indemnity and OneBeacon

On August 14, 2013, NYSEG filed suit in federal court against two excess insurers, Century Indemnity and OneBeacon, who provided excess liability coverage to NYSEG. NYSEG seeks payment for clean-up costs associated with contamination at 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.

Century Indemnity and OneBeacon have answered, admitting issuance of the excess policies, but contesting coverage and providing documentation proving they received notice of the claims in the 1990s. On March 31, 2017, the District Court granted motions filed by Century Indemnity and One Beacon dismissing all of NYSEG’s claims against both defendants on the grounds of late notice. NYSEG filed a motion with the District Court on April 14, 2017 seeking reconsideration of the Court’s decision, which was denied by an order dated March 27, 2018. NYSEG filed a notice appealing the District Court’s dismissal on April 9, 2018. On April 25, 2019, the Second Circuit Court of Appeals affirmed the lower court’s dismissal of NYSEG’s claims. We cannot predict the outcome of this matter; however, any recovery will be flowed through to NYSEG ratepayers.

English Station

In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then and current owners of a former generation site on the Mill River in New Haven (the English Station site) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut against UI seeking, among other things: (i) an order directing UI to reimburse the plaintiffs for costs they have incurred and will incur for the testing, investigation and remediation of hazardous substances at the English Station site and (ii) an order directing UI to investigate and remediate the site. This proceeding had been stayed in 2014 pending resolutions of other proceedings before the Connecticut Department of Energy and Environmental Protection (DEEP) concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing

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of a motion to reopen by any party. In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit in Connecticut state court seeking among other things: (i) remediation of the English Station site; (ii) reimbursement of remediation costs; (iii) termination of UI’s easement rights; (iv) reimbursement for costs associated with securing the property; and (v) punitive damages. This lawsuit had been stayed in May 2014 pending mediation. Due to lack of activity in the case, the court terminated the stay and scheduled a status conference for July 6, 2017. On July 5, 2017, Asnat filed a pretrial memorandum claiming damages of $10 million for “environmental remediation activities” and lost use of the property. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. The complaint was further revised on July 3, 2018. We filed a Motion to Strike the counts in the complaint in August 2018 and oral arguments were held. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. As to the remaining count, the court declined to strike the claim against UI for unjust enrichment. The plaintiffs filed a motion to appeal the court's dismissal. We cannot predict the outcome of this matter.

On April 8, 2013, DEEP issued an administrative order addressed to UI, Evergreen Power, Asnat and others, ordering the parties to take certain actions related to investigating and remediating the English Station site. Mediation of the matter began in the fourth quarter of 2013 and concluded unsuccessfully in April 2015. This proceeding was stayed while DEEP and UI continue to work through the remediation process pursuant to the consent order described below. Status reports are periodically filed with the DEEP.

On August 4, 2016, DEEP issued a partial consent order (the consent order), that, subject to its terms and conditions, requires UI to investigate and remediate certain environmental conditions within the perimeter of the English Station site. Under the consent order, to the extent that the cost of this investigation and remediation is less than $30 million, UI will remit to the State of Connecticut the difference between such cost and $30 million to be used for a public purpose as determined in the discretion of the Governor of the State of Connecticut, the Attorney General of the State of Connecticut and the Commissioner of DEEP. UI is obligated to comply with the terms of the consent order even if the cost of such compliance exceeds $30 million. Under the terms of the consent order, the State will discuss options with UI on recovering or funding any cost above $30 million such as through public funding or recovery from third parties; however, it is not bound to agree to or support any means of recovery or funding. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order.

As of March 31, 2019 and December 31, 2018, the amount reserved for this matter was $19 million and $20 million, respectively. We cannot predict the outcome of this matter.

Note 11. Post-retirement and Similar Obligations

We made $7 million of pension contributions for the three months ended March 31, 2019. We expect to make additional contributions of $58 million for the remainder of 2019.

The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2019 and 2018, respectively, consisted of:

	Three Months Ended March 31,
	2019			2018
(Millions)
Service cost	$	10		$	11
Interest cost	33			32
Expected return on plan assets	(48		)	(50		)
Amortization of:
Actuarial loss	30			38
Net Periodic Benefit Cost	$	25		$	31

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The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2019 and 2018, respectively, consisted of: 

	Three Months Ended March 31,
	2019			2018
(Millions)
Service cost	$	1		$	1
Interest cost	4			4
Expected return on plan assets	(2		)	(2		)
Amortization of:
Prior service costs	(2		)	(2		)
Actuarial loss	—			1
Net Periodic Benefit Cost	$	1		$	2

Note 12. Equity

As of March 31, 2019, our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which are owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $3 million and additional paid in capital of $13,658 million. As of December 31, 2018, our share capital consisted of 500,000,000 shares of common stock authorized, 309,752,140 shares issued and 309,005,272 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $0.01, for a total value of common stock capital of $3 million and additional paid in capital of $13,657 million. We had 485,810 shares of common stock held in trust and no convertible preferred shares outstanding as of both March 31, 2019 and December 31, 2018. During the three months ended March 31, 2019, we issued no shares of common stock and released no shares of common stock held in trust. During the three months ended March 31, 2018, we issued 81,208 shares of common stock each having a par value of $0.01 and released no shares of common stock held in trust common stock.

We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain the relative ownership percentage by Iberdrola at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. Out of a total of 261,058 treasury shares of common stock of AVANGRID as of March 31, 2019, 115,831 shares were repurchased during 2016, 64,019 shares were repurchased during 2017 and 81,208 shares were repurchased during 2018, all in the open market. The total cost of all repurchases, including commissions, was $12 million as of March 31, 2019.

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Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss for the three months ended March 31, 2019 and 2018, respectively, consisted of:

	As of December 31,			Adoption of new accounting			Three Months Ended March 31,			As of March 31,			As of December 31,			Adoption of new accounting			Three Months Ended March 31,			As of March 31,
	2018			standard			2019			2019			2017			standard			2018			2018
(Millions)
Change in revaluation of defined benefit plans	$	(11	)	$	(2	)	$	—		$	(13	)	$	(14	)	$	—		$	—		$	(14	)
Loss for nonqualified pension plans	(6		)	—			—			(6		)	(6		)	(1		)	—			(7		)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(10.9) for 2019	9			—			(29		)	(20		)	30			—			—			30
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $0.7 for 2019 and $(7.5) for 2018(a)	(64		)	(10		)	2			(72		)	(56		)	—			(10		)	(66		)
Loss on derivatives qualifying as cash flow hedges	(55		)	(10		)	(27		)	(92		)	(26		)	—			(10		)	(36		)
Accumulated Other Comprehensive Loss	$	(72	)	$	(12	)	$	(27	)	$	(111	)	$	(46	)	$	(1	)	$	(10	)	$	(57	)

________________________

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

Note 13. 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 months ended March 31, 2019 and 2018, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculation for the three months ended March 31, 2019 and 2018.

The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2019 and 2018, respectively, consisted of:

	Three Months Ended March 31,
	2019		2018
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	217	$	244
Denominator:
Weighted average number of shares outstanding - basic	309,491,082		309,513,640
Weighted average number of shares outstanding - diluted	309,712,308		309,793,064
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	0.70	$	0.79
Earnings Per Common Share, Diluted	$	0.70	$	0.79

Note 14. Segment Information

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

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

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

The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market adjustments to reflect the effect of mark-to-market changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity, loss from held for sale measurement, accelerated depreciation derived from repowering of wind farms and adjustments for the non-core Gas business.

Products and services are sold between reportable segments and affiliate companies at cost. Segment income, expense and assets presented in the accompanying tables include all intercompany transactions that are eliminated in the condensed consolidated financial statements.

Segment information as of and for the three months ended March 31, 2019, consisted of:

Three Months Ended March 31, 2019	Networks		Renewables			Other (a)			AVANGRID Consolidated
(Millions)
Revenue - external	$	1,600	$	242		$	—		$	1,842
Revenue - intersegment	4		—			(4		)	—
Loss from assets held for sale	—		—			—			—
Depreciation and amortization	134		88			—			222
Operating income (loss)	331		13			(3		)	341
Earnings (losses) from equity method investments	3		(2		)	—			1
Interest expense, net of capitalization	68		4			6			78
Income tax expense (benefit)	64		1			(24		)	41
Adjusted net income	201		5			13			219
Capital expenditures	324		101			—			425
As of March 31, 2019
Property, plant and equipment	14,819		8,728			8			23,555
Equity method investments	140		341			—			481
Total assets	$	22,408	$	11,046		$	(846	)	$	32,608

_________________________

(a) Includes Corporate, Gas and intersegment eliminations.

Included in revenue-external for the three months ended March 31, 2019, are: $964 million from regulated electric operations, $636 million from regulated gas operations and $0 from other operations of Networks; $242 million primarily from renewable energy generation of Renewables.

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Segment information for the three months ended March 31, 2018, consisted of:

Three Months Ended March 31, 2018	Networks		Renewables			Other (a)			AVANGRID Consolidated
(Millions)
Revenue - external	$	1,549	$	283		$	33		$	1,865
Revenue - intersegment	3		1			(4		)	—
Loss from assets held for sale	—		—			5			5
Depreciation and amortization	118		85			—			203
Operating income (loss)	344		44			15			403
Earnings (losses) from equity method investments	2		—			—			2
Interest expense, net of capitalization	60		8			6			74
Income tax expense (benefit)	64		(8		)	16			72
Adjusted net income	201		47			(5		)	243
Capital expenditures	282		116			1			399
As of December 31, 2018
Property, plant and equipment	14,754		8,697			8			23,459
Equity method investments	142		224			—			366
Total assets	$	22,239	$	10,703		$	(775	)	$	32,167

_________________________

(a) Includes Corporate, Gas and intersegment eliminations.

Included in revenue-external for the three months ended March 31, 2018, are: $955 million from regulated electric operations, $600 million from regulated gas operations and $(6) million from other operations of Networks; $283 million primarily from renewable energy generation of Renewables.

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2019 and 2018, respectively, is as follows:

	Three Months Ended March 31,
	2019			2018
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	219		$	243
Adjustments:
Loss from assets held for sale (1)	—			(5		)
Mark-to-market adjustments - Renewables (2)	3			4
Restructuring charges (3)	—			(1		)
Accelerated depreciation from repowering (4)	(5		)	—
Income tax impact of adjustments	—			(10		)
Gas Storage, net of tax (5)	—			13
Net Income Attributable to Avangrid, Inc.	$	217		$	244

(1) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses.

(2) Mark-to-market adjustments relate to changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity and gas.

(3) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment.

(4) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables.

(5) Removal of the impact from Gas activity in the reconciliation to the AVANGRID Net Income.

Note 15. Related Party Transactions

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

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Related party transactions for the three months ended March 31, 2019 and 2018, respectively, consisted of:

Three Months Ended March 31,	2019					2018
(Millions)	Sales To		Purchases From			Sales To		Purchases From
Iberdrola Canada Energy Services, Ltd	$	—	$	—		$	—	$	(4	)
Iberdrola Renovables Energía, S.L.	$	—	$	(4	)	$	—	$	(3	)
Iberdrola, S.A.	$	—	$	(10	)	$	—	$	(14	)
Iberdrola Energia Monterrey, S.A. de C.V.	$	—	$	—		$	3	$	—
Other	$	—	$	(1	)	$	1	$	(1	)

In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola has an 8.1% ownership. The amounts capitalized for these transactions were $2 million and $6 million for the periods ended March 31, 2019 and December 31, 2018, respectively.

Related party balances as of March 31, 2019 and December 31, 2018, respectively, consisted of:

As of	March 31, 2019					December 31, 2018
(Millions)	Owed By		Owed To			Owed By		Owed To
Siemens-Gamesa	$	—	$	(16	)	$	—	$	(14	)
Iberdrola, S.A.	$	1	$	(10	)	$	1	$	(40	)
Iberdrola Renovables Energía, S.L.	$	4	$	(7	)	$	4	$	—
Other	$	2	$	(2	)	$	1	$	(4	)

Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable.

Transactions with Iberdrola Canada Energy Services (ICES) predominantly relate to the purchase of gas for ARHI’s gas-fired cogeneration facility in Klamath, Oregon. There are no notes payable amounts owed to ICES of as of March 31, 2019 and December 31, 2018.

Transactions with Iberdrola Energia Monterrey predominantly relate to the sale of gas by Enstor Gas for the power generation plant in Monterrey, Mexico.

There have been no guarantees provided or received for any related party receivables or payables. These balances are unsecured and are typically settled in cash. Interest is not charged on regular business transactions but is charged on outstanding loan balances. There have been no impairments or provisions made against any affiliated balances.

Networks holds an approximate 20% ownership interest in the regulated New York TransCo, LLC (New York TransCo). Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. As of both March 31, 2019 and December 31, 2018, the amount receivable from New York TransCo was $1 million.

We hold a 50% ownership in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners. Vineyard Wind acquired an easement from the U.S. Bureau of Ocean Energy Management containing rights to develop offshore wind generation in a 260 square mile area located southeast of Martha’s Vineyard. The area subject to easement has the capacity for siting up to approximately 3,000 MW. In May 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. Under the provisions of the LLC agreement, Renewables has committed $92 million in total contributions, of which $70 million has been funded to date. We expect to provide additional capital contributions. The amount receivable from Vineyard was $0.9 million and $0 as of March 31, 2019 and December 31, 2018, respectively.

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Renewables, through its joint venture in Vineyard Wind, was awarded a second Massachusetts offshore easement. In February 2019, a contribution was made to a new offshore development project of $100 million to enter into the easement contract.

AVANGRID manages its overall liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both March 31, 2019 and December 31, 2018, was zero.

AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of March 31, 2019 and December 31, 2018, there was no outstanding amount under this credit facility.

Note 16. Other Financial Statement Items

Loss from assets held for sale

In connection with the sale of our gas trading and storage businesses, we recorded a loss from held for sale measurement of $5.3 million, which is included in “Loss from assets held for sale” in our condensed consolidated statements of income for the three months ended March 31, 2018.

Accounts receivable

Accounts receivable include amounts due under deferred payment arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period of time, which generally exceeds one year, by negotiating mutually acceptable payment terms and not bearing interest. The utility company generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and are classified as current.

We establish provisions for uncollectible accounts for DPAs by using both historical average loss percentages to project future losses and by establishing specific provisions for known credit issues. Amounts are written off when reasonable collection efforts have been exhausted. DPA receivable balances were $67 million and $62 million at March 31, 2019 and December 31, 2018, respectively. The allowance for doubtful accounts for DPAs at March 31, 2019 and December 31, 2018, was $33 million and $32 million, respectively. Furthermore, the provision for bad debts associated with the DPAs for both the three months ended March 31, 2019 and 2018 was $1 million.

Prepayments and other current assets

Included in prepayments and other current assets are $144 million and $137 million of prepaid other taxes as of March 31, 2019 and December 31, 2018, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of March 31, 2019 and December 31, 2018, respectively, were as follows:

	March 31,		December 31,
As of	2019		2018
(Millions)
Property, plant and equipment
Accumulated depreciation	$	8,518	$	8,359
Intangible assets
Accumulated amortization	$	294	$	291

Note 17. Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2019, was 16.0% which is lower than the 21% statutory federal income tax rate, predominantly due to the recognition of production tax credits associated with wind production, partially offset by discrete tax adjustments recorded during the period. The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2018, was 23.2% which was higher than the 21% statutory federal income tax rate, predominantly due to discrete tax adjustments recorded during the period, partially offset by the recognition of production tax credits associated with wind production.

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Note 18. Stock-Based Compensation Expense

Pursuant to the 2016 Avangrid, Inc. Omnibus Incentive Plan, 1,358 additional performance stock units (PSUs) were granted to certain officers and employees of AVANGRID in March 2019. The PSUs will vest upon achievement of certain performance- and market-based metrics related to the 2016 through 2019 plan and will be payable in three equal installments in 2020, 2021 and 2022. The fair value on the grant date was determined based on $31.80 per share.

The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2019 and 2018 was $0.8 million and $(0.1) million, respectively.

Note 19. Variable Interest Entities

We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). These arrangements consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights.

The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our condensed consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs.

The assets and liabilities of the VIEs totaled approximately $862 million and $52 million, respectively, at March 31, 2019. As of December 31, 2018, the assets and liabilities of VIEs totaled approximately $876 million and $50 million, respectively. At March 31, 2019 and December 31, 2018, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment and equity method investments. At March 31, 2019 and December 31, 2018, equity method investments of VIEs were approximately $100 million and $101 million, respectively.

At March 31, 2019 and December 31, 2018, we consider Aeolus Wind Power II LLC and El Cabo to be VIEs.

Wind power generation is subject to certain favorable tax treatments in the U.S. In order to monetize the tax benefits, we have entered into these structured institutional partnership investment transactions related to certain wind farms. Under these structures, we contribute certain wind assets, relating both to existing wind farms and wind farms that are being placed into operation at the time of the relevant transaction, and other parties invest in the share equity of the limited liability holding company. As consideration for their investment, the third parties make either an upfront cash payment or a combination of upfront cash and payments over time. We retain a class of membership interest and day-to-day operational and management control, subject to investor approval of certain major decisions. The third-party investors do not receive a lien on any assets and have no recourse against us for their upfront cash payments.

The partnerships generally involve disproportionate allocations of profit or loss, cash distributions and tax benefits resulting from the wind farm energy generation between the investor and sponsor until the investor recovers its investment and achieves a cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met.

Our Aeolus and El Cabo interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests.

Note 20. Restructuring and Severance Related Expenses

In 2017, we announced initial targeted voluntary workforce reductions predominantly within the Networks segment. Those actions primarily include: reducing our workforce through voluntary programs in various areas to better align our people resources with business demands and priorities; reorganizing our human resources function to substantially consolidate in Connecticut, as well as related costs to vacate a lease and relocate employees; and reducing our information technology (IT) workforce to make increasing use of external services for operations, support, and development of systems. Those decisions and transactions resulted in restructuring charges of $0.2 million and $1.2 million recorded in the three months ended March 31, 2019 and 2018, respectively, for severance expenses, which are included in "Operations and maintenance" in our condensed consolidated statements of income. The remaining costs for severance agreements are being accrued ratably over the remaining service periods, which span intermittent periods through December 2019. Our severance and lease restructuring charges reserves, which are recorded in other current liabilities and other liabilities on our condensed consolidated balance sheets, was $4 million as of both March 31, 2019 and December 31, 2018 with immaterial activity for the three months ended March 31, 2019.

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Note 21. Subsequent Event

On April 11, 2019, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on July 1, 2019 to shareholders of record at the close of business on June 7, 2019.

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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 consolidated financial statements as of December 31, 2018 and 2017, and for the three years ended December 31, 2018, included in our Annual Report on Form 10-K for the year ended December 31, 2018, filed with the Securities and Exchange Commission, or the SEC, on March 1, 2019, 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

AVANGRID is a leading sustainable energy company with approximately $33 billion in assets and operations in 24 states. AVANGRID has two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving approximately 3.2 million customers in New York and New England. Avangrid Renewables owns and operates 7.2 gigawatts of electricity capacity, primarily through wind power, with a presence in 22 states across the United States. AVANGRID supports the achievement of the Sustainable Development Goals approved by the member states of the United Nations, and earned the Compliance Leader Verification certification from the Ethisphere Institute, a third party verification of its ethics and compliance program. AVANGRID employs approximately 6,500 people. Iberdrola S.A., a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.5% of outstanding shares of AVANGRID common stock. AVANGRID's primary business is ownership of its operating businesses, which are described below.

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. Networks owns and operates our regulated utility businesses through its subsidiaries, including electric transmission and distribution and natural gas distribution, transportation and sales. Renewables operates a portfolio of renewable energy generation facilities primarily using onshore wind power and also solar, biomass and thermal power. 

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 1.0 million natural gas public utility customers as of March 31, 2019.

Networks, a Maine 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 the eight regulated utilities it owns directly:

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

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

• The United Illuminating Company, or UI, which serves electric customers in southwestern Connecticut;

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

• The Southern Connecticut Gas Company, or SCG, which serves natural gas customers in southern Connecticut;

• Connecticut Natural Gas Corporation, or CNG, which serves natural gas customers in Connecticut;

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

• Maine Natural Gas Corporation, or MNG, which 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 7,225 megawatts, or MW, as of March 31, 2019, including Renewables’ share of joint projects, of which 6,473 MW was installed wind capacity. Approximately 69% of the capacity was contracted as of March 31, 2019, for an average period of 9.4 years. Being among the top three largest wind operators in the United States based on installed capacity as of March 31, 2019, Renewables strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables currently operates 57 wind farms in 21 states across the United States.

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Summary of Results of Operations

Our operating revenues decreased by 1%, from $1,865 million for the three months ended March 31, 2018 to $1,842 million for the three months ended March 31, 2019.

Networks business revenues increased due to the impact of higher customer rates and an increase in heating degree days from colder weather. Renewables had a decrease in revenues mainly due to a decline in wind generation along with lower average prices in the period.

Net income attributable to AVANGRID decreased by 11% from $244 million for the three months ended March 31, 2018 to $217 million for the three months ended March 31, 2019, primarily due to a lower net income at Renewables business as a result of a decline in wind generation and lower average prices in the period.

Adjusted net income (a non-GAAP financial measure) decreased by 9% from $243 million for the three months ended March 31, 2018 to $219 million for the three months ended March 31, 2019. The decrease is primarily due to a $42 million decrease in Renewables as a result of a decline in wind generation and lower average prices in the period.

For additional information and reconciliation of the non-GAAP adjusted net income to net income attributable to AVANGRID, 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, 2018.

CMP rate case

On January 14, 2019, the Maine Public Utility Commission, or the MPUC, issued an Order and Notice of Investigation initiating an investigation of CMP’s metering and billing practices and initiating a separate investigation of the audit of CMP’s customer service and communication practices and incorporating such investigation into the general rate case. On February 22, 2019, the MPUC issued the MPUC staff Bench Analysis, or BA on all revenue requirement issues in this case, including customer service issues. The BA includes, among other things, a proposal to reduce CMP’s existing distribution rates by $2.0 - $3.6 million, inclusive of one-time items from July 2018, and implement a management efficiency adjustment as part of the rate setting process to reduce CMP’s allowed ROE of 9.35% by 75 to 100 basis points. We cannot predict the outcome of this matter.

Transmission - ROE Complaint

Following various intermediate hearings, orders and appellate decisions, on October 16, 2018, the Federal Energy Regulatory Commission, or FERC, issued an order directing briefs and proposing a new methodology to calculate the NETOs' ROE that is contained in NETOs’ transmission formula rate on file at the FERC, or the October 2018 Order. The FERC proposes to use this new methodology to resolve Complaints I, II, III and IV filed by the New England state consumer advocates. Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019, and replies to the initial briefs on March 8, 2019. We cannot predict the outcome of this proceeding.

New York State Department of Public Service Investigation of the Preparation for and Response to the March 2017 Windstorm

On May 18, 2018, NYSEG and RG&E filed a settlement joint proposal and investment joint proposal before the NYPSC to settle potential penalties and avoid litigation related to the March 2017 windstorm, pursuant to which, among other things, NYSEG and RG&E have agreed to make $3.9 million in investments designed to increase resiliency and improve emergency response in the areas impacted by the storm. The investments will not be reflected in rate base or operating expenses in establishing future delivery rates. On April 18, 2019, the NYPSC approved the joint proposals.

New York State Department of Public Service Investigation of the Preparation for and Response to the March 2018 Winter Storms

In March 2018, following two severe winter storms that impacted more than one million electric utility customers in New York, including 520,000 NYSEG and RG&E customers, the NYPSC initiated a comprehensive investigation of all the New York

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electric utilities’ preparation and response to those events. The investigation was expanded to include other 2018 New York spring storm events.

On April 18, 2019 the Department Staff issued a report (the 2018 Staff Report) of the findings from their investigation. The 2018 Staff Report identifies 94 recommendations for corrective actions to be implemented in the utilities Emergency Response Plans (ERP). The report also identified potential violations by several of the utilities, including NYSEG and RG&E.

Also on April 18, 2019, the NYPSC issued an Order Instituting Proceeding and to Show Cause directed to all major electric utilities in New York, including NYSEG and RG&E. The order directs the utilities, including NYSEG and RG&E, to show cause why the NYPSC should not pursue civil penalties, and / or administrative penalties for the apparent failure to follow their respective ERPs as approved and mandated by the NYPSC. The NYPSC also directs the utilities, within 30 days, to address whether the NYPSC should mandate, reject or modify in whole or in part, the 94 recommendations contained in the 2018 Staff Report. We cannot predict the final outcome of this matter. 

NYPSC directs Counsel to commence Judicial Enforcement Proceeding against NYSEG

On April 18, 2019, the NYPSC issued an Order Directing Counsel to the Commission to commence a special proceeding or an action in New York State Supreme Court to stop and prevent ongoing future violations by NYSEG of NYPSC regulations and orders. As of the date hereof, a special proceeding or an action has not been commenced. Therefore, NYSEG cannot respond to or assess the merits of claims which may be brought and we cannot predict the final outcome of this matter.

Power Tax Audits

In 2015, we implemented power tax software to track and measure deferred tax amounts for CMP, NYSEG and RG&E. In connection with this change, we identified historical updates needed with deferred taxes recognized by CMP, NYSEG and RG&E. We increased our deferred tax liabilities in 2015, with a corresponding increase to regulatory assets, to reflect the updated amounts calculated by the power tax software. Since 2015, the NYPSC and MPUC accepted certain adjustments to deferred taxes and associated regulatory assets for this item in recent distribution rate cases, resulting in regulatory asset balances of approximately $156 million and $157 million, respectively, for this item at March 31, 2019 and December 31, 2018.

In 2017, audits of the power tax regulatory assets were commenced by the NYPSC and MPUC. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax accounting. The audit report is expected to be completed during 2019. In January 2018, the MPUC published the power tax audit report with respect to CMP, which indicated that the auditor was unable to verify the “acquisition value” of the power tax regulatory assets. The audit report requires that CMP must provide support for the beginning balance of the regulatory assets or will be unable to recover the value of the assets, which is approximately $10 million. CMP responded to the audit report in its rate case filing and noted that it could reconcile 99% of the tax values and therefore requested full recovery of the power tax regulatory asset. In its BA, the MPUC staff indicated that it was hiring an outside auditor to review CMP's calculations. We cannot predict the outcome of this 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, or the Yankee Companies, three New England single-unit decommissioned nuclear reactor sites, and UI has an ownership interest in Connecticut Yankee Atomic Power Company. Pursuant to the statute of limitations, the Yankee Companies file a lawsuit periodically to recover damages from the Department of Energy, or DOE, for breach of the Nuclear Spent Fuel Disposal Contract to remove spent nuclear fuel and greater than class C waste as required by contract.

From 2012 to 2016 the Yankee Companies filed three claims against the DOE (Phase I, II and III) for the years from 1995 to 2012 and received damage awards, which flow through the Yankee Companies to shareholders (including CMP and UI based percentage of ownership) to reduce retail customer charges. On May 22, 2017, the Yankee Companies filed their next case (Phase IV) in the Federal Court of Claims, or Court, seeking damages for the period from January 1, 2013 through December 31, 2016 and submitted their claimed Phase IV damages to the DOE in late August 2017. The Court issued its decision on the Phase IV trial on February 21, 2019, awarding the Yankee Companies a combined $103.2 million (Connecticut Yankee $40.7 million, Maine Yankee $34.4 million and Yankee Atomic $28.1 million). The damage awards are returned to customers either through customer refunds or by reducing future costs. Refunds or reductions in costs are reflected in the Yankee Companies billings to shareholders, including CMP and UI. CMP and UI will receive their proportionate share of the awards that flow through based on percentage of ownership. On April 23, 2019, the notice of appeal period expired and the Phase IV trial award became final.

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Results of Operations

The following table sets forth financial information by segment for each of the periods indicated.

	Three Months Ended												Three Months Ended
	March 31, 2019												March 31, 2018
	Total			Networks			Renewables			Other(1)			Total			Networks			Renewables			Other(1)
	(in millions)
Operating Revenues	$	1,842		$	1,604		$	242		$	(4	)	$	1,865		$	1,552		$	284		$	29
Operating Expenses
Purchased power, natural gas and fuel used	563			526			37			—			576			518			56			2
Loss from assets held for sale	—			—			—			—			5			—			—			5
Operations and maintenance	553			468			87			(2		)	527			436			86			5
Depreciation and amortization	222			134			88			—			203			118			85			—
Taxes other than income taxes	163			145			17			1			151			136			13			2
Total Operating Expenses	1,501			1,273			229			(1		)	1,462			1,208			240			14
Operating income (loss)	341			331			13			(3		)	403			344			44			15
Other Income (Expense)
Other income (expense)	(7		)	(1		)	(3		)	(3		)	(21		)	(22		)	—			1
Earnings (losses) from equity method investments	1			3			(2		)	—			2			2			—			—
Interest expense, net of capitalization	(78		)	(68		)	(4		)	(5		)	(74		)	(60		)	(8		)	(6		)
Income (Loss) Before Income Tax	257			265			4			(11		)	310			264			36			10
Income tax expense (benefit)	41			64			1			(24		)	72			64			(8		)	16
Net Income (Loss)	216			201			3			13			238			200			44			(6		)
Less: Net loss attributable to noncontrolling interests	(1		)	—			(1		)	—			(6		)	—			(6		)	—
Net Income (Loss) Attributable to Avangrid, Inc.	$	217		$	201		$	4		$	13		$	244		$	200		$	50		$	(6	)

__________________________

(1) Other amounts represent Corporate, Gas and intersegment eliminations.

Comparison of Period to Period Results of Operations

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

Operating Revenues

Our operating revenues decreased by $23 million, or 1%, from $1,865 million for the three months ended March 31, 2018 to $1,842 million for the three months ended March 31, 2019, as detailed by segment below:

Networks

Operating revenues increased by $52 million, or 3%, from $1,552 million for the three months ended March 31, 2018 to $1,604 million for the three months ended March 31, 2019. Electricity and gas revenues increased by $32 million, primarily due to the impact of increased electric customer rates in the three months period ended March 31, 2019 compared to the same period of 2018. Electricity and gas revenues for the three months ended March 31, 2019 compared to the same period in 2018, increased by $8 million due to increased purchased power and purchased gas. Revenues in the current period compared to the same period of 2018 increased by $8 million and $4 million, respectively, due to a change in intercompany billing, which is offset in operating expenses, and pass-through components.

Renewables

Operating revenues decreased by $42 million, or 15%, from $284 million for the three months ended March 31, 2018 to $242 million for the three months ended March 31, 2019. The decrease in operating revenues was primarily due to a decrease of $31 million with wind generation output decreasing 624 GWh, a decrease of $18 million from lower overall average prices in the period, unfavorable mark to market, or MtM, changes of $27 million on energy derivative transactions entered into for economic hedging purposes, offset by an increase in thermal revenue of $36 million driven by higher average prices in the period.

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Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used decreased by $13 million, or 2%, from $576 million for the three months ended March 31, 2018 to $563 million for the three months ended March 31, 2019, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used increased by $8 million, or 2%, from $518 million for the three months ended March 31, 2018 to $526 million for the three months ended March 31, 2019. The increase is primarily driven by a $34 million increase in average commodity prices and an overall increase in the units of gas procured due to an increase in heating degree days from colder weather, offset by a decrease of $24 million in overall electricity units procured in the period combined with a $3 million decrease in other power supply purchases.

Renewables

Purchased power, natural gas and fuel used decreased by $19 million, or 34%, from $56 million for the three months ended March 31, 2018 to $37 million for the three months ended March 31, 2019. The decrease is primarily driven by a decrease of $8 million in power purchases and favorable MtM changes on derivatives of $25 million due to market price changes in the current period, offset by increases of $3 million in transmission costs and $12 million in additional gas purchases in the period.

Operations and Maintenance

Our operations and maintenance increased by $26 million, or 5%, from $527 million for the three months ended March 31, 2018 to $553 million for the three months ended March 31, 2019, as detailed by segment below:

Networks

Operations and maintenance increased by $32 million, or 7% from $436 million for the three months ended March 31, 2018 to $468 million for the three months ended March 31, 2019. The increase is primarily due to $8 million increase driven by a change in intercompany billing (offset in revenues), $11 million increase in storm and regulatory adjustment mechanism amortizations (offset in rate increases), $4 million increase in pass through components and $7 million increase in personnel costs.

Renewables

Operations and maintenance expenses increased by $1 million, or 1%, from $86 million for the three months ended March 31, 2018 to $87 million for the three months ended March 31, 2019. The increase is primarily due to $4 million of increased costs resulting from headcount increases and higher maintenance costs, offset by a $3 million decrease driven by an insurance recovery in the current period.

Depreciation and Amortization and Loss From Assets Held for Sale

Depreciation and amortization and loss from assets held for sale for the three months ended March 31, 2019 was $222 million compared to $208 million for the three months ended March 31, 2018, representing an increase of $14 million. The increase is primarily due to increases of $11 million and $4 million in depreciation expense as a result of plant additions in Networks and accelerated depreciation from re-powering in Renewables, respectively, in the period.

Other Income (Expense) and Earnings (Losses) from Equity Method Investments

Other income (expense) and equity earnings (losses) decreased by $13 million from $(19) million for the three months ended March 31, 2018 to $(6) million for the three months ended March 31, 2019. The decrease is primarily due to a decrease of $14 million of pension and other post-retirement expense in the period in Networks.

Interest Expense, Net of Capitalization

Interest expense for the three months ended March 31, 2019 and 2018 was $78 million and $74 million, respectively. Networks had $4 million increase in interest expense due to a higher average outstanding balance of debt in the period and $4 million increase from carrying costs on regulatory deferrals. This is offset by interest expense decrease in Renewables of $3 million due to lower average debt balances in the current period.

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2019, was 16.0%, which is lower than the 21% statutory federal income tax rate, predominantly due to the recognition of production tax credits associated with wind production, partially offset by discrete tax adjustments recorded during the period. The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2018 was 23.2%, which is higher than the 21%

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statutory federal income tax rate, predominately due to discrete tax adjustments recorded during the period, partially offset by 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 adjusted net income and adjusted earnings per share as non-GAAP financial measures that are not prepared in accordance with U.S. GAAP. 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. 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. We believe that presenting such non-GAAP financial measures is useful because such measures can be used to analyze and compare profitability between companies and industries by eliminating the impact of certain non-cash charges. 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 net income as net income adjusted to exclude restructuring charges, mark-to-market adjustments to reflect the effect of mark-to-market changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity, loss from held for sale measurement, accelerated depreciation derived from repowering of wind farms and adjustments for the non-core Gas storage business. We believe adjusted net income is more useful in understanding and evaluating actual and projected financial performance and contribution of AVANGRID core lines of business and to more fully compare and explain our results. The most directly comparable U.S. GAAP measure to adjusted net income is net income. We also define adjusted earnings per share, or 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, and 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.

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.

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The following tables provide a reconciliation between Net Income attributable to AVANGRID and Adjusted Net Income (non-GAAP) by segment for the three months ended March 31, 2019 and 2018, respectively:

	Three Months Ended March 31, 2019
	Total			Networks		Renewables			Corporate*
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	217		$	201	$	4		$	13
Adjustments:
Mark-to-market adjustments - Renewables	(3		)	—		(3		)	—
Restructuring charges	—			—		—			—
Accelerated depreciation from repowering	5			—		5			—
Income tax impact of adjustments (1)	—			—		—			—
Adjusted Net Income (2)	$	219		$	201	$	5		$	13

	Three Months Ended March 31, 2018
	Total			Networks		Renewables			Corporate*			Gas Storage
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	244		$	200	$	50		$	(5	)	$	(1	)
Adjustments:
Mark-to-market adjustments - Renewables	(4		)	—		(4		)	—			—
Restructuring charges	1			1		—			—			—
Loss from held for sale measurement	5			—		—			—			5
Income tax impact of adjustments (1)	10			—		1			—			9
Gas Storage, net of tax	(13		)	—		—			—			(13		)
Adjusted Net Income (2)	$	243		$	201	$	47		$	(5	)	$	—

(1) Income tax impact of adjustments: 2019 - $0.9 million from MtM adjustment, $(0.1) million from restructuring charges, $(1.3) million from accelerated depreciation for the three months ended March 31, 2019; 2018 - $1 million from MtM adjustment, $(0.3) million from restructuring charges, $11 million from gain from held for sale measurement for the three months ended March 31, 2018.

(2) Adjusted Net Income is a non-GAAP financial measure and is presented after excluding restructuring charges, loss from held for sale measurement, accelerated depreciation derived from repowering of wind farms, the impact from mark-to-market activities in Renewables and Gas storage business.

* Includes corporate and other non-regulated entities as well as intersegment eliminations.

Three Months Ended March 31, 2019 Compared to Three Months Ended March 31, 2018

Adjusted net income

Our adjusted net income decreased by $24 million, or 9%, from $243 million for the three months ended March 31, 2018 to $219 million for the three months ended March 31, 2019. The decrease is primarily due to a $42 million decrease in Renewables as a result of a decline in wind generation and lower average prices in the period.

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The following tables reconcile Net Income attributable to AVANGRID to Adjusted Net Income (non-GAAP), and EPS attributable to AVANGRID to adjusted EPS (non-GAAP) for the three months ended March 31, 2019 and 2018, respectively:

	Three Months Ended
	March 31,
(in millions)	2019			2018
Networks	$	201		$	200
Renewables	4			50
Corporate (1)	13			(5		)
Gas Storage	—			(1		)
Net Income	$	217		$	244
Adjustments:
Loss from held for sale measurement (2)	—			5
Mark-to-market adjustments - Renewables (3)	(3		)	(4		)
Restructuring charges (4)	—			1
Accelerated depreciation from repowering (5)	5			—
Income tax impact of adjustments	—			10
Gas Storage, net of tax	—			(13		)
Adjusted Net Income (6)	$	219		$	243

	Three Months Ended
	March 31,
	2019			2018
Networks	$	0.65		$	0.65
Renewables	0.01			0.16
Corporate (1)	0.04			(0.02		)
Gas Storage	—			—
Net Income	$	0.70		$	0.79
Adjustments:
Loss from held for sale measurement (2)	—			0.02
Mark-to-market adjustments - Renewables (3)	(0.01		)	(0.01		)
Restructuring charges (4)	—			—
Accelerated depreciation from repowering (5)	0.02			—
Income tax impact of adjustments	—			0.03
Gas Storage, net of tax	—			(0.04		)
Adjusted Earnings Per Share (6)	$	0.71		$	0.78

(1) Includes corporate and other non-regulated entities as well as intersegment eliminations.

(2) Represents loss from measurement of assets and liabilities held for sale in connection with the committed plan to sell the gas trading and storage businesses.

(3) Mark-to-market adjustments relate to changes in the fair value of derivative instruments used by AVANGRID to economically hedge market price fluctuations in related underlying physical transactions for the purchase and sale of electricity and gas.

(4) Restructuring and severance related charges relate to costs resulted from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment.

(5) Represents the amount of accelerated depreciation derived from repowering of wind farms in Renewables.

(6) Adjusted net income and adjusted earnings per share are non-GAAP financial measures and are presented after excluding restructuring charges, loss from held for sale measurement, accelerated depreciation derived from repowering of a wind farm, the impact from mark-to-market activities in Renewables and Gas storage business.

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 program as our primary sources of liquidity. Our long-term capital requirements have been met primarily through retention of earnings 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.

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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 March 31, 2019.

Liquidity Position

At March 31, 2019 and December 31, 2018, available liquidity was approximately $2,233 million and $2,447 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 liquidity agreement with Bank of America, N.A. along with certain members of the Iberdrola Group. The liquidity 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 the financial institution, provided that the net balance of funds deposited or borrowed by all pool participants in the aggregate is not less than zero. The balance at March 31, 2019 was zero. Any deposit amounts would be reflected in our condensed consolidated balance sheets under cash and cash equivalents because our deposited surplus funds under the cash pooling agreement are highly-liquid short-term investments. We also have a bi-lateral demand note agreement with a Canadian affiliate of the Iberdrola Group under which we had notes payable balance outstanding of $0 at March 31, 2019.

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. We have the capacity to borrow up to $2.5 billion from the lenders committed to the AVANGRID Credit Facility and $0.5 billion from an Iberdrola Group Credit Facility, both of which are described below.

The following table provides the components of our liquidity position as of March 31, 2019 and December 31, 2018, respectively:

	As of March 31,			As of December 31,
	2019			2018
	(in millions)
Cash and cash equivalents	$	33		$	36
AVANGRID Credit Facility	2,500			2,500
Iberdrola Group Credit Facility	500			500
Less: borrowings	(800		)	(589		)
Total	$	2,233		$	2,447

AVANGRID Commercial Paper Program

AVANGRID has a commercial paper program with a limit of $2 billion that is backstopped by the AVANGRID Credit Facility (described below). As of March 31, 2019 and May 1, 2019, there was $800 million and $872 million of commercial paper outstanding, respectively.

AVANGRID Credit Facility

AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC have a revolving credit facility with a syndicate of banks, or the AVANGRID Credit Facility, that provides for maximum borrowings of up to $2.5 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 contained in the agreement. AVANGRID’s maximum sublimit is $2 billion, NYSEG, RG&E, CMP and UI have maximum sublimits of $400 million, CNG and SCG have maximum sublimits of $150 million and BGC has a maximum sublimit of $40 million. Under the AVANGRID Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. The initial facility fees will range from 12.5 to 17.5 basis points. The maturity date for the AVANGRID Credit Facility is June 29, 2023.

Since the facility is a backstop to the AVANGRID commercial paper program, the amounts available under the facility as of March 31, 2019 and May 1, 2019, were $1,700 million and $1,628 million, respectively.

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Iberdrola Group Credit Facility

AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both March 31, 2019 and May 1, 2019, there was no outstanding amount under this credit facility.

Capital Resources

On January 15, 2019, UI, CNG, SCG and BGC issued $195 million in aggregate amount of notes/bonds with maturity dates ranging from 2029 to 2049 and interest rates ranging from 4.07% to 4.52%.

On April 1, 2019, NYSEG issued $12 million of Indiana County Industrial Development Authority Pollution Control Revenue Bonds in a private placement with a 2.65% interest rate and maturing in 2024.

Capital Requirements

We expect to fund our capital requirements, including, without limitation, any quarterly shareholder dividends and capital investments primarily from the cash provided by operations of our businesses and through the access to the capital markets 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 $2.3 billion in capital expenditures through the remainder of 2019.

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 three months ended March 31, 2019 and 2018, respectively:

	Three Months Ended
	March 31,
	2019			2018
	(in millions)
Net cash provided by operating activities	$	315		$	597
Net cash used in investing activities	(526		)	(323		)
Net cash provided by (used in) financing activities	206			(275		)
Net decrease in cash, cash equivalents and restricted cash	$	(5	)	$	(1	)

Operating Activities

The cash from operating activities for the three months ended March 31, 2019 compared to the three months ended March 31, 2018 decreased by $282 million, primarily attributable to a net decrease of $64 million from current assets and liabilities driven by timing of cash collections and cash disbursements during the period, and a decrease of $167 million in non-current liabilities primarily due to a decrease in other long-term liabilities and changes in long-term regulatory assets/liabilities.

Investing Activities

For the three months ended March 31, 2019, net cash used in investing activities was $526 million, which was comprised of $425 million of capital expenditures and other investments and equity method investments of $116 million, partially offset by $10 million of contributions in aid of construction and $2 million of cash distributions from equity method investments.

For the three months ended March 31, 2018, net cash used in investing activities was $323 million, which was comprised of $399 million of capital expenditures, partially offset by $7 million of contributions in aid of construction, $2 million of cash distributions from equity method investments and proceeds from sale of assets of $67 million.

Financing Activities

For the three months ended March 31, 2019, financing activities provided $206 million in cash reflecting primarily an issuance of notes/bonds with net proceeds of $194 million, contributions from non-controlling interests of $3 million and a net increase in non-current debt and current notes payable of $168 million, offset by distributions to non-controlling interests of $3 million, payments on capital leases of $21 million and dividends of $135 million.

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For the three months ended March 31, 2018, financing activities used $275 million in cash reflecting primarily a net decrease in non-current debt and current notes payable of $126 million, distributions to non-controlling interests of $11 million, payments on capital lease of $8 million and dividends of $134 million.

Off-Balance Sheet Arrangements

There have been no material changes in the off-balance sheet arrangements during the three months ended March 31, 2019 as compared to those reported for the fiscal year ended December 31, 2018 in our Form 10-K.

Contractual Obligations

Upon adoption of ASC 842, certain land easements that we previously classified as a lease do not meet the definition of a lease. As a result, our operating lease obligations as of December 31, 2018 will be categorically separated between operating leases and land easements. The new lease accounting standard is discussed further in Notes 3 and 8 to our condensed consolidated financial statements. These changes do not result in material changes to the quantitative amounts of our contractual and contingent obligations during the three months ended March 31, 2019 as compared to those reported for the fiscal year ended December 31, 2018 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, stockholders’ 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 March 31, 2019, the only notable changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2018 and 2017, and for the three years ended December 31, 2018, are with respect to our adoption of the new accounting pronouncements described in the Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2019.

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. As of March 31, 2019, the new accounting pronouncements that we have adopted as of January 1, 2019, and reflected in our condensed consolidated financial statements are described in Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2019. There have been no other material changes to the significant accounting policies described in our consolidated financial statements as of December 31, 2018 and 2017, and for the three years ended December 31, 2018.

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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,” “would,” “could,” “can,” “expect(s),” “believe(s),” “anticipate(s),” “intend(s),” “plan(s),” “estimate(s),” “project(s),” “assume(s),” “guide(s),” “target(s),” “forecast(s),” “ are (is) confident that” and “seek(s)” 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 reasonable beliefs, expectations, and assumptions of our management and are subject to significant risks and uncertainties that could cause actual outcomes and results to differ materially. Important factors are discussed and should be reviewed in our Form 10-K and other subsequent filings with the SEC. Specifically, forward-looking statements include, without limitation:

• the future financial performance, anticipated liquidity and capital expenditures;

• actions or inactions of local, state or federal regulatory agencies;

• success in retaining or recruiting our officers, key employees or directors;

• changes in levels or timing of capital expenditures;

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

• fluctuations in weather patterns;

• technological developments;

• the impact of any cyber breaches or other incidents, grid disturbances, acts of war or terrorism or natural disasters;

• 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;

• the implementation of changes in accounting standards; and

• other presently unknown unforeseen factors.

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. Other risk factors are detailed from time to time in our reports filed with the SEC, and we encourage you to consult such disclosures.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in our market risk during the three months ended March 31, 2019, as compared to those reported for the fiscal year ended December 31, 2018 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 has been no change 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

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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 9—Contingencies” and “Note 10—Environmental Liabilities” to the accompanying unaudited condensed consolidated financial statements under Part I, Item 1 of this report for a discussion of 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, 2018. 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
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.

†Compensatory plan or agreement.

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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: May 2, 2019	By:	/s/ James P. Torgerson
		James P. Torgerson
		Director and Chief Executive Officer

Date: May 2, 2019	By:	/s/ Douglas K. Stuver
		Douglas K. Stuver
		Senior Vice President - Chief Financial Officer

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