UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

WASHINGTON, DC 20549

FORM 10-Q

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

For the quarterly period ended September 30, 2020

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

Securities registered pursuant to Section 12(b) of the Act:

Title of each class	Trading Symbol	Name of exchange on which registered
Common Stock, par value $0.01 per share	AGR	New York Stock Exchange

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

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  ☒    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	☒	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  ☒

As of October 29, 2020, the registrant had 309,009,817 shares of common stock, par value $0.01, outstanding.

Avangrid, Inc.

REPORT ON FORM 10-Q

For the Quarter Ended September 30, 2020

INDEX

GLOSSARY OF TERMS AND ABBREVIATIONS		3
PART I. FINANCIAL INFORMATION		5
Item 1.	Financial Statements	5
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	52
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	69
Item 4.	Controls and Procedures	69
PART II. OTHER INFORMATION		71
Item 1.	Legal Proceedings	71
Item 1A.	Risk Factors	71
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	75
Item 3.	Defaults Upon Senior Securities	75
Item 4.	Mine Safety Disclosures	75
Item 5.	Other Information	75
Item 6.	Exhibits	76
SIGNATURES		77

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.

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
CFIUS	Committee on Foreign Investment in the United States
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
English Station	The former generation site on the Mill River in New Haven, Connecticut
Exchange Act	The Securities Exchange Act of 1934, as amended
FASB	Financial Accounting Standards Board
FCC	Federal Communications Commission
FERC	Federal Energy Regulatory Commission
FirstEnergy	FirstEnergy Corp.
Form 10-K	Avangrid, Inc.’s Annual Report on Form 10-K for the year ended December 31, 2019, filed with the Securities and Exchange Commission on March 2, 2020.
Gas	Enstor Gas, LLC
HLBV	Hypothetical Liquidation at Book Value
Iberdrola	Iberdrola, S.A., which owns 81.5% of the outstanding shares of Avangrid, Inc.
Iberdrola Group	The group of companies controlled by Iberdrola, S.A.
Installed capacity	The production capacity of a power plant or wind farm based either on its rated (nameplate) capacity or actual capacity.
ISO	Independent system operator
Joint Proposal	Approved by the NYPSC on June 15, 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	Klamath gas-fired cogeneration facility located in the city of Klamath, Oregon.
KW	Kilowatts
LDCs	Local distribution companies
LIBOR	The London Interbank Offered Rate
Merger	The merger of PNMR with and into Merger Sub on the terms and subject to the conditions set forth in the Merger Agreement, with PNMR continuing as the surviving corporation and as a wholly-owned subsidiary of AVANGRID.
Merger Agreement	Agreement and Plan of Merger, dated as of October 20, 2020, among AVANGRID, PNMR and Merger Sub.
Merger Sub	NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID.
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.
NMPRC	New Mexico Public Regulation Commission
Non-GAAP	Financial measures that are not prepared in accordance with U.S. GAAP, including adjusted net income and adjusted earnings per share.
NRC	Nuclear Regulatory Commission
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.
PNMR	PNM Resources, Inc.
PUCT	Public Utility Commission of Texas
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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Millions, except for number of shares and per share data)
Operating Revenues	$	1,470	$	1,487	$	4,651	$	4,729
Operating Expenses
Purchased power, natural gas and fuel used	259		279		999		1,101
Operations and maintenance	634		588		1,788		1,714
Depreciation and amortization	255		237		748		681
Taxes other than income taxes	157		144		469		446
Total Operating Expenses	1,305		1,248		4,004		3,942
Operating Income	165		239		647		787
Other Income and (Expense)
Other income	16		6		15		1
Earnings (losses) from equity method investments	1		(1)		(3)		1
Interest expense, net of capitalization	(86)		(72)		(251)		(226)
Income Before Income Tax	96		172		408		563
Income tax expense	15		33		21		103
Net Income	81		139		387		460
Net loss attributable to noncontrolling interests	6		11		28		17
Net Income Attributable to Avangrid, Inc.	$	87	$	150	$	415	$	477
Earnings Per Common Share, Basic	$	0.28	$	0.48	$	1.34	$	1.54
Earnings Per Common Share, Diluted	$	0.28	$	0.48	$	1.34	$	1.54
Weighted-average Number of Common Shares Outstanding:
Basic	309,491,082		309,491,082		309,496,234		309,491,082
Diluted	309,550,126		309,517,778		309,554,838		309,512,301

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 September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Millions)
Net Income	$	81	$	139	$	387	$	460
Other Comprehensive Income (Loss)
Loss on nonqualified pension plans	—		—		—		(1)
Unrealized (loss) gain during the period on derivatives qualifying as cash flow hedges, net of income tax of $(3) and $2 for the three months ended, respectively, and $(8) for both the nine months ended	(15)		5		(31)		(22)
Reclassification to net income of loss on cash flow hedges, net of income taxes of $0 and $1 for both the three months ended, respectively, and $1 and $2 for the nine months ended, respectively	9		5		12		8
Other Comprehensive Income (Loss)	(6)		10		(19)		(15)
Comprehensive Income	75		149		368		445
Net loss attributable to noncontrolling interests	6		11		28		17
Comprehensive Income Attributable to Avangrid, Inc.	$	81	$	160	$	396	$	462

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

5

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	September 30,		December 31,
As of	2020		2019
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	101	$	178
Accounts receivable and unbilled revenues, net	1,021		1,082
Accounts receivable from affiliates	7		10
Derivative assets	19		11
Fuel and gas in storage	100		110
Materials and supplies	157		141
Prepayments and other current assets	266		199
Regulatory assets	252		294
Total Current Assets	1,923		2,025
Total Property, Plant and Equipment ($1,657 and $787 related to VIEs, respectively)	26,432		25,218
Operating lease right-of-use assets	68		70
Equity method investments	668		645
Other investments	61		63
Regulatory assets	2,591		2,567
Other Assets
Goodwill	3,119		3,119
Intangible assets	307		314
Derivative assets	85		84
Other	386		311
Total Other Assets	3,897		3,828
Total Assets	$	35,640	$	34,416

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

6

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	September 30,		December 31,
As of	2020		2019
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	813	$	730
Notes payable	998		560
Notes payable to affiliates	4		—
Interest accrued	87		72
Accounts payable and accrued liabilities	1,481		1,361
Accounts payable to affiliates	43		64
Dividends payable	136		136
Taxes accrued	82		56
Operating lease liabilities	11		12
Derivative liabilities	19		20
Other current liabilities	296		334
Regulatory liabilities	214		242
Total Current Liabilities	4,184		3,587
Regulatory liabilities	3,342		3,281
Other Non-current Liabilities
Deferred income taxes	1,846		1,814
Deferred income	1,221		1,274
Pension and other postretirement	998		1,100
Operating lease liabilities	42		65
Derivative liabilities	81		85
Asset retirement obligations	208		190
Environmental remediation costs	333		338
Other	450		380
Total Other Non-current Liabilities	5,179		5,246
Non-current debt	7,081		6,716
Total Non-current Liabilities	15,602		15,243
Total Liabilities	19,786		18,830
Commitments and Contingencies
Equity
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 309,794,917 and 309,752,140 shares issued; 309,005,485 and 309,005,272 shares outstanding, respectively	3		3
Additional paid in capital	13,664		13,660
Treasury stock	(14)		(12)
Retained earnings	1,684		1,681
Accumulated other comprehensive loss	(114)		(95)
Total Stockholders’ Equity	15,223		15,237
Non-controlling interests	631		349
Total Equity	15,854		15,586
Total Liabilities and Equity	$	35,640	$	34,416

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)

	Nine Months Ended September 30,
	2020		2019
(Millions)
Cash Flow from Operating Activities:
Net income	$	387	$	460
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	748		681
Regulatory assets/liabilities amortization and carrying cost	63		51
Pension cost	60		68
Earnings (losses) from equity method investments	3		(1)
Distributions of earnings received from equity method investments	15		10
Unrealized gain on marked-to-market derivative contracts	(9)		(66)
Deferred taxes	11		99
Other non-cash items	(35)		(35)
Changes in operating assets and liabilities:
Current assets	7		188
Noncurrent assets	(152)		(24)
Current liabilities	24		(73)
Noncurrent liabilities	(30)		(114)
Net Cash Provided by Operating Activities	1,092		1,244
Cash Flow from Investing Activities:
Capital expenditures	(1,960)		(2,045)
Contributions in aid of construction	35		36
Proceeds from sale of assets	12		13
Proceeds from notes receivable from affiliates	2		—
Distributions received from equity method investments	3		4
Other investments and equity method investments, net	(48)		(164)
Net Cash Used in Investing Activities	(1,956)		(2,156)
Cash Flow from Financing Activities:
Non-current debt issuances	967		1,637
Repayments of non-current debt	(511)		(344)
Receipts of other short-term debt, net	441		32
Repayments of financing leases	(7)		(26)
Repurchase of common stock	(2)		—
Issuance of common stock	(1)		—
Distributions to noncontrolling interests	(5)		(47)
Contributions from noncontrolling interests	312		133
Dividends paid	(408)		(408)
Net Cash Provided by Financing Activities	786		977
Net (Decrease) Increase in Cash, Cash Equivalents and Restricted Cash	(78)		65
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	184		43
Cash, Cash Equivalents and Restricted Cash, End of Period	$	106	$	108
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	206	$	183
Cash paid for income taxes	$	4	$	4

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 June 30, 2019	309,005,272	$	3	$	13,659	$	(12)	$	1,594	$	(109)	$	15,135	$	414	$	15,549
Net income (loss)	—	—		—		—		150		—		150		(11)		139
Other comprehensive income, net of tax of $3	—	—		—		—		—		10		10		—		10
Comprehensive income																149
Dividends declared, $0.44/share	—	—		—		—		(136)		—		(136)		—		(136)
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(37)		(37)
Contributions from noncontrolling interests	—	—		—		—		(9)		—		(9)		2		(7)
As of September 30, 2019	309,005,272	$	3	$	13,659	$	(12)	$	1,599	$	(99)	$	15,150	$	368	$	15,518
As of June 30, 2020	309,005,485	$	3	$	13,664	$	(14)	$	1,733	$	(108)	$	15,278	$	638	$	15,916
Net income (loss)	—	—		—		—		87		—		87		(6)		81
Other comprehensive income, net of tax of $(3)	—	—		—		—		—		(6)		(6)		—		(6)
Comprehensive income																75
Dividends declared, $0.44/share	—	—		—		—		(136)		—		(136)		—		(136)
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(1)		(1)
As of September 30, 2020	309,005,485	$	3	$	13,664	$	(14)	$	1,684	$	(114)	$	15,223	$	631	$	15,854

9

	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, 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)	—	—		—		—		477		—		477		(17)		460
Other comprehensive loss, net of tax of $(6)	—	—		—		—		—		(15)		(15)		—		(15)
Comprehensive income																445
Dividends declared, $1.32/share	—	—		—		—		(408)		—		(408)		—		(408)
Stock-based compensation	—	—		2		—		—		—		2		—		2
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(47)		(47)
Contributions from noncontrolling interests	—	—		—		—		(9)		—		(9)		133		124
As of September 30, 2019	309,005,272	$	3	$	13,659	$	(12)	$	1,599	$	(99)	$	15,150	$	368	$	15,518
As of December 31, 2019	309,005,272	$	3	$	13,660	$	(12)	$	1,681	$	(95)	$	15,237	$	349	$	15,586
Adoption of accounting standards	—	—		—		—		(1)		—		(1)		—		(1)
Net income (loss)	—	—		—		—		415		—		415		(28)		387
Other comprehensive loss, net of tax of $(7)	—	—		—		—		—		(19)		(19)		—		(19)
Comprehensive income																368
Dividends declared, $1.32/share	—	—		—		—		(408)		—		(408)		—		(408)
Release of common stock held in trust	213	—		—		—		—		—		—		—		—
Issuance of common stock	42,777	—		(1)		—		—		—		(1)		—		(1)
Repurchase of common stock	(42,777)	—		—		(2)		—		—		(2)		—		(2)
Stock-based compensation	—	—		5		—		—		—		5		—		5
Distributions to noncontrolling interests	—	—		—		—				—		—		(5)		(5)
Contributions from noncontrolling interests	—	—		—		—		(3)		—		(3)		315		312
As of September 30, 2020	309,005,485	$	3	$	13,664	$	(14)	$	1,684	$	(114)	$	15,223	$	631	$	15,854

(*) Par value of share amounts is $0.01

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

10

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% of 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 condensed consolidated financial statements should be read in conjunction with the Form 10-K for the fiscal year ended December 31, 2019.

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.

Preparation of the accompanying unaudited financial statements requires management to make estimates and assumptions that affect the amounts reported during the periods covered by the related financial statements and accompanying disclosures. We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from the global pandemic of the novel coronavirus (COVID-19) has made such estimates and assumptions more difficult to assess and calculate. Impacted estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While there were no material impacts from COVID-19 on financial results, actual results could differ from those estimates, which could result in material impacts to our consolidated financial statements in future reporting periods.

In the opinion of management, the accompanying condensed consolidated financial statements contain all adjustments necessary to present fairly our condensed consolidated financial statements for the interim periods described herein. All such adjustments are of a normal and recurring nature, except as otherwise disclosed. The results for the three and nine months ended September 30, 2020, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2020.

Note 3. Significant Accounting Policies and New Accounting Pronouncements

The new accounting pronouncements that we have adopted as of January 1, 2020, 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 Form 10-K for the fiscal year ended December 31, 2019, except for those described below resulting from the adoption of new authoritative accounting guidance issued by Financial Accounting Standards Board (FASB).

Goodwill

Goodwill represents future economic benefits arising from other assets acquired in a business combination that are not individually identified and separately recognized. Goodwill is initially measured at cost, being the excess of the aggregate of the consideration transferred, the fair value of any noncontrolling interest and the acquisition date fair value of any previously held equity interest in the acquiree over the fair value of the net identifiable assets acquired and liabilities assumed.

Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment. In assessing goodwill for impairment, we have the option of first performing a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine that it is more likely than not that its fair value is

11

less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit.

Accounts receivable and unbilled revenue, net

We record accounts receivable at amounts billed to customers and we record unbilled revenues based on an estimate of energy delivered or services provided to customers. Certain accounts receivable and payable related to our wholesale activities associated with generation and delivery of electric energy and associated environmental attributes, origination and marketing, natural gas storage, hub services, and energy management, are subject to master netting agreements with counterparties, whereby we have the legal right to offset the balances and they are settled on a net basis. We present receivables and payables subject to such agreements on a net basis on our consolidated balance sheets.

Accounts receivable include amounts due under Deferred Payment Arrangements (DPAs). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies 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 short term.

We establish our allowance for credit losses, including for unbilled revenue, by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. Due to our adoption of Accounting Standards Codification (ASC) 326 effective January 1, 2020, we now also consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the accounts receivable. We write off amounts when we have exhausted reasonable collection efforts.

Adoption of New Accounting Pronouncements

(a) Measurement of credit losses on financial instruments, amendments and updates

The FASB issued an accounting standards update in June 2016 that requires more timely recording of credit losses on loans and other financial instruments (ASC 326). The amendments affect entities that hold financial assets and net investment in leases that are not accounted for at fair value through net income (loans, debt securities, trade receivables, net investments in leases, off-balance-sheet credit exposures, etc.). They require an entity to present a financial asset (or group of financial assets) that is measured at amortized cost basis at the net amount expected to be collected. The allowance for credit losses is a valuation account that is deducted from the amortized cost basis of the financial asset(s) to present the net carrying value at the amount expected to be collected on the financial asset. The income statement reflects the measurement of credit losses for newly recognized financial assets, as well as the expected increases or decreases of expected credit losses that have taken place during the period. The measurement of expected credit losses is based on relevant information about past events, including historical experience, current conditions and reasonable and supportable forecasts that affect the collectability of the reported amount. An entity must use judgment in determining the relevant information and estimation methods appropriate in its circumstances. The FASB subsequently issued various updates to ASC 326 to clarify transition and scope requirements, make narrow-scope codification improvements, including in March 2020, and corrections and provide targeted transition relief. We adopted the amendments effective January 1, 2020, including the narrow-scope improvements issued in March 2020, and recorded a cumulative-effect adjustment of $1 million to retained earnings at the beginning of the period of adoption, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures.

(b) Simplifying the test for goodwill impairment

In January 2017, the FASB issued amendments to simplify the test for goodwill impairment, which are required for public entities and certain other entities that have goodwill reported in their financial statements. The amendments simplify the subsequent measurement of goodwill by eliminating Step 2 from the goodwill impairment test, which requires the valuation of assets acquired and liabilities assumed using business combination accounting guidance. Under the new guidance, an entity should perform its annual, or interim, goodwill impairment test by comparing the fair value of a reporting unit with its carrying amount. An entity should recognize an impairment charge for the amount by which the carrying amount exceeds the reporting unit’s fair value; but the loss recognized should not exceed the total amount of goodwill allocated to that reporting unit. Also, an entity should consider income tax effects from any tax-deductible goodwill on the carrying amount of the reporting unit when measuring the goodwill impairment loss, if applicable. Certain requirements are eliminated for any reporting unit with a

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zero or negative carrying amount; therefore, the same impairment assessment applies to all reporting units. An entity still has the option to perform the qualitative assessment for a reporting unit to determine if the quantitative impairment test is necessary. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we will apply the amendments on a prospective basis.

(c) Changes to the disclosure requirements for fair value measurement and defined benefit plans

In August 2018, the FASB issued amendments related to disclosure requirements for both fair value measurement and defined benefit plans.

The amendments concerning fair value measurement remove, modify and add certain disclosure requirements in order to improve the overall usefulness of the disclosures and reduce unnecessary costs to companies to prepare the disclosures. We adopted the amendments effective January 1, 2020, with no material effect to our disclosures. Certain amendments are to be applied prospectively, and all others are to be applied retrospectively.

The amendments concerning disclosure requirements for defined benefit plans are narrow in scope and apply to all employers that sponsor defined benefit pension or other postretirement plans. The amendments change annual disclosures requirements, including removal of disclosures that are no longer considered cost beneficial, adding certain new relevant disclosures and clarifying specific requirements of disclosures concerning information for defined benefit pension plans. We adopted the amendments effective January 1, 2020, and they will not materially affect the disclosures for our fiscal year ending December 31, 2020. As required, our application will be on a retrospective basis.

(d) Targeted improvements to related party guidance for VIEs

In October 2018, the FASB issued amendments that affect reporting entities that are required to determine whether they should consolidate a legal entity under the consolidation guidance applicable to VIEs. The targeted improvements specifically applicable to public business entities clarify that indirect interests held through related parties in common control arrangements should be considered on a proportional basis for determining whether fees paid to decision makers and service providers are variable interests. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures.

(e) Clarifying guidance for certain collaborative arrangements with respect to revenue recognition

The FASB issued amendments in November 2018 to clarify the interaction between the guidance for certain collaborative arrangements and the guidance applicable to ASC 606. A collaborative arrangement is a contractual arrangement under which two or more parties actively participate in a joint operating activity and are exposed to significant risks and rewards that depend on the activity’s commercial success. The targeted improvements clarify that certain transactions between collaborative arrangement participants are within the scope of ASC 606 and thus subject to all of its guidance. We adopted the amendments effective January 1, 2020, with no material effect to our condensed consolidated results of operations, financial position, cash flows and disclosures. As required, we retrospectively applied the amendments to the date of our initial application of ASC 606.

Accounting Pronouncements Issued But Not Yet Adopted

The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2019, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Simplifying the accounting for income taxes

In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes, eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. The amendments are effective for public business entities for fiscal years beginning after December 15, 2020, and interim periods within those fiscal years. Early adoption is permitted, including adoption in any interim period for which financial statements have not been issued, with adoption of all amendments in the same period. Application is on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment aspect. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.

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(b) Facilitation of the effects of reference rate reform on financial reporting

In March 2020, the FASB issued amendments to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension. We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.

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 our reportable segments, refer to Note 13.

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 (RDMs), 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 ASC 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 ASC 606 revenue, which we recognize based on the amount invoiced to the customer.

Other

Other, which does not represent a segment, includes miscellaneous Corporate revenues and 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 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 prior costs incurred to cancel a PPA, which are related to the wind farm interest that is being sold as described in Note 15. Contract assets totaled $12 million at both September 30, 2020 and December 31, 2019, 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 $6 million and $10 million at September 30, 2020 and December 31, 2019, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $6 million and $16 million as revenue during the three and nine months ended September 30, 2020, respectively, and $7 million and $16 million for the three and nine months ended September 30, 2019, respectively.

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Revenues disaggregated by major source for our reportable segments for the three and nine months ended September 30, 2020 and 2019 are as follows:

	Three Months Ended September 30, 2020								Nine Months Ended September 30, 2020
	Networks		Renewables		Other (b)		Total		Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	984	$	—	$	—	$	984	$	2,701	$	—	$	—	$	2,701
Regulated operations – natural gas	166		—		—		166		910		—		—		910
Nonregulated operations – wind	—		200		—		200		—		639		—		639
Nonregulated operations – solar	—		6		—		6		—		16		—		16
Nonregulated operations – thermal	—		13		—		13		—		27		—		27
Other(a)	12		28		(4)		36		38		75		(4)		109
Revenue from contracts with customers	1,162		247		(4)		1,405		3,649		757		(4)		4,402
Leasing revenue	2		—		—		2		5		—		—		5
Derivative revenue	—		25		—		25		—		111		—		111
Alternative revenue programs	24		—		—		24		109		—		—		109
Other revenue	9		4		1		14		16		8		—		24
Total operating revenues	$	1,197	$	276	$	(3)	$	1,470	$	3,779	$	876	$	(4)	$	4,651

	Three Months Ended September 30, 2019								Nine Months Ended September 30, 2019
	Networks		Renewables		Other (b)		Total		Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	922	$	—	$	—	$	922	$	2,637	$	—	$	—	$	2,637
Regulated operations – natural gas	179		—		—		179		1,053		—		—		1,053
Nonregulated operations – wind	—		218		—		218		—		621		—		621
Nonregulated operations – solar	—		9		—		9		—		22		—		22
Nonregulated operations – thermal	—		5		—		5		—		21		—		21
Other(a)	16		23		—		39		71		40		(4)		107
Revenue from contracts with customers	1,117		255		—		1,372		3,761		704		(4)		4,461
Leasing revenue	1		—		—		1		5		—		—		5
Derivative revenue	—		84		—		84		—		173		—		173
Alternative revenue programs	13		—		—		13		48		—		—		48
Other revenue	9		8		—		17		23		19		—		42
Total operating revenues	$	1,140	$	347	$	—	$	1,487	$	3,837	$	896	$	(4)	$	4,729

(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 and intersegment eliminations.

As of September 30, 2020 and December 31, 2019, accounts receivable balances related to contracts with customers were approximately $988 million and $1,050 million, respectively, including unbilled revenues of $266 million and $345 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

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As of September 30, 2020, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of September 30, 2020	2021		2022		2023		2024		2025		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	1	$	1	$	1	$	1	$	—	$	—	$	4
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	39		23		15		12		11		75		175
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	27		18		9		4		3		5		66
Total operating revenues	$	67	$	42	$	25	$	17	$	14	$	80	$	245

As of September 30, 2020, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2020 was $24 million.

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 regulatory 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 rate base or accruing carrying costs are 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 $1,616 million.

CMP Rate Case

In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7%, based on an allowed ROE of 9.25% and a 50% equity ratio. The rate increase was effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a period of 18 consecutive months, which commenced on March 1, 2020. CMP has satisfied all four of these quality measures since the measurement period commenced.

The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine ratepayers. The management audit was commenced in July 2020 by the MPUC’s consultants and is expected to conclude in December 2020.

CMP Revenue Decoupling Mechanism Investigation

On June 9, 2020, the MPUC issued a Notice of Investigation to open an investigation into the effects of the COVID-19 pandemic on customers’ electricity-usage patterns and whether CMP’s RDM should be suspended for the annual distribution rate change that is expected to occur on July 1, 2021, for electricity delivered in calendar year 2020. On June 24, 2020, the MPUC issued a procedural order setting forth initial steps in this proceeding. On July 21, 2020, CMP filed testimony presenting electricity-usage data for its two RDM classes (residential and commercial/industrial) through June 2020, along with testimony explaining the data and the reasons why the current RDM should remain in place without alteration. We cannot predict the outcome of this matter.

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NYSEG and RG&E Rate Plans and Rate Case Filings

Current Rate Plan

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 a portion of storm costs to be recovered over ten 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.

Rate Case Filing Update

On May 20, 2019, NYSEG and RG&E filed rate cases with the NYPSC for new tariffs.

On March 23, 2020, the Public Utility Law Project (a party to the cases) submitted a letter motion requesting that the NYPSC administrative law judges assigned to preside over the rate cases require NYSEG and RG&E to pause settlement discussions and to provide new and accurate calculations based on the current and future expected economic impact of the COVID-19 pandemic. On March 31, 2020, NYSEG and RG&E, Multiple Intervenors (a party to the cases) and NYDPS staff each filed a response in opposition to the motion. On April 7, 2020, the NYPSC administrative law judges issued a Ruling Denying Public Utility Law Project’s Motion, allowing settlement negotiations to continue. On April 22, 2020, the Public Utility Law Project and AARP filed an interlocutory appeal requesting that the NYPSC review the determination of the administrative law judges. We cannot predict the outcome of this proceeding.

On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan. The effective date of new tariffs was November 1, 2020 with a make-whole provision back to April 17, 2020. We were granted a one month extension making the new effective date December 1, 2020, pending NYPSC approval of the joint proposal. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The joint proposal bases delivery revenues on an 8.80% ROE and 48% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50%. The below table provides a summary of the proposed delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass-through, for all four businesses:

	Year 1				Year 2				Year 3
	Rate Increase		Delivery Rate %		Rate Increase		Delivery Rate %		Rate Increase		Delivery Rate %
Utility	(Millions)		Increase		(Millions)		Increase		(Millions)		Increase
NYSEG Electric	$	34.7	4.6	%	$	71.51	9.1	%	$	79.4	9.1	%
NYSEG Gas	$	—	—	%	$	1.58	0.8	%	$	3.3	1.6	%
RG&E Electric	$	10.7	2.4	%	$	22.92	5.2	%	$	25.4	5.2	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2.4	1.3	%

The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. Statements in support or opposition and reply statements were filed in July 2020, and a final decision by the NYPSC is expected during the fourth quarter of 2020. We cannot predict the outcome of this proceeding.

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UI, CNG, SCG and BCG Rate Plans

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.

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 $2 million, $5 million and $5 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 an 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.

In December 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with rate increases of $10 million, $5 million and $5 million in 2019, 2020 and 2021, respectively. The new tariffs continued the RDM and DIMP mechanism. ESM and tariff increases are 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.

On January 18, 2019, the DPU approved new distribution rates for BGC providing for a $2 million distribution base rate increase effective February 1, 2019 (with a make-whole provision back to January 1, 2019), and an additional $1 million base distribution increase effective November 1, 2019, if certain investments are made by BGC. The distribution rate increase is based on a 9.70% ROE and 55% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021.

Connecticut Storm Reimbursement Legislation

On October 7, 2020, the Governor of Connecticut signed into law an energy bill that, among other things, instructs PURA to revise the rate-making structure in Connecticut to adopt performance-based rates for each electric distribution company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.

Regulatory assets and liabilities

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 September 30, 2020 and December 31, 2019, respectively, consisted of:

	September 30,		December 31,
As of	2020		2019
(Millions)
Pension and other post-retirement benefits cost deferrals	$	101	$	125
Pension and other post-retirement benefits	963		1,061
Storm costs	418		272
Rate adjustment mechanism	16		79
Revenue decoupling mechanism	56		19
Transmission revenue reconciliation mechanism	9		5
Contracts for differences	90		92
Hardship programs	26		29
Plant decommissioning	—		5
Deferred purchased gas	14		25
Deferred transmission expense	14		11
Environmental remediation costs	278		277
Debt premium	88		97
Unamortized losses on reacquired debt	27		29
Unfunded future income taxes	408		399
Federal tax depreciation normalization adjustment	149		153
Asset retirement obligation	21		17
Deferred meter replacement costs	25		27
COVID-19 cost recovery	2		—
Other	138		139
Total regulatory assets	2,843		2,861
Less: current portion	252		294
Total non-current regulatory assets	$	2,591	$	2,567

“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 September 30, 2020, deferred storm costs include $69 million and $16 million at NYSEG being recovered over ten-year and five-year periods, respectively, beginning in 2016, and $196 million and $61 million at NYSEG and RG&E, respectively, not included in the Joint Proposal. The amounts not included in the Joint Proposal will be recovered through RAM or determined as part of the current rate proceedings.

“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.

"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.

"Transmission revenue reconciliation mechanism" reflects differences in actual costs in the rate year from those used to set rates. This mechanism contains the Annual Transmission True up (ATU), which is recovered over the subsequent June to May period.

“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.

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

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

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

“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.

“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.

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

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

“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 32.5 years beginning in 2020.

“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 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.

"COVID-19 cost recovery" represents deferred COVID-19-related costs in the state of Connecticut based on the order issued by PURA on April 29, 2020, requiring utilities to track COVID-19-related expenses and lost revenue and create a regulatory asset.

“Other” includes post-term amortization deferrals and various items subject to reconciliation including hedge losses and deferred property tax.

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Regulatory liabilities as of September 30, 2020 and December 31, 2019, respectively, consisted of:

	September 30,		December 31,
As of	2020		2019
(Millions)
Energy efficiency portfolio standard	$	72	$	72
Gas supply charge and deferred natural gas cost	4		11
Pension and other post-retirement benefits cost deferrals	69		80
Carrying costs on deferred income tax bonus depreciation	32		49
Carrying costs on deferred income tax - Mixed Services 263(a)	11		15
2017 Tax Act	1,550		1,548
Revenue decoupling mechanism	10		17
Accrued removal obligations	1,181		1,173
Asset sale gain account	10		10
Economic development	27		27
Positive benefit adjustment	35		37
Theoretical reserve flow thru impact	10		14
Deferred property tax	52		17
Net plant reconciliation	23		23
Debt rate reconciliation	83		67
Rate refund – FERC ROE proceeding	33		32
Transmission congestion contracts	24		23
Merger-related rate credits	14		16
Accumulated deferred investment tax credits	26		13
Asset retirement obligation	16		14
Earning sharing provisions	26		28
Middletown/Norwalk local transmission network service collections	18		18
Low income programs	29		33
Non-firm margin sharing credits	15		16
New York 2018 winter storm settlement	11		11
Other	175		159
Total regulatory liabilities	3,556		3,523
Less: current portion	214		242
Total non-current regulatory liabilities	$	3,342	$	3,281

“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.

"Gas supply charge and deferred natural gas cost" reflects the actual costs of purchasing, transporting and storing of natural gas. Gas supply reconciliation is determined by comparing actual gas supply expenses to the monthly gas cost recoveries in rates. Prior rate year balances are collected/ returned to customers beginning the next calendar year.

“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.

“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. A portion of this balance is amortized

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through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.

"Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.

“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.

"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.

“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 net gain on the sale of certain assets that will be used for the future benefit of customers. The amortization period for the majority of the balance will be determined in future proceedings.

“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 customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.

“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.

“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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2016.

"Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for in rates.

"Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the Joint Proposal.

"Debt rate reconciliation" represents the over/under collection of costs related to debt instruments identified in the rate case. Costs would include interest, commissions and fees versus amounts included in rates.

"Rate refund - FERC ROE proceeding" represents the reserve associated with the FERC proceeding around the base return on equity (ROE) reflected in ISO New England, Inc.’s (ISO-NE) open access transmission tariff (OATT). See Note 8 for more details.

"Transmission congestion contracts" represents deferral of Nine Mile 2 Nuclear Plant transmission congestion contract at RGE.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During the three and nine months ended September 30, 2020 and 2019, respectively, $1 million and $2 million of rate credits were applied against customer bills.

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"Asset retirement obligation" 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.

"Earning sharing provisions" represents the annual earnings over the earning sharing threshold.

"Middletown/Norwalk local transmission network service collections" represents allowance for funds used during construction of the Middletown/Norwalk transmission line, which is being amortized over the useful life of the project.

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

"New York 2018 winter storm settlement" represents the settlement amount with the NYSPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms.

“Other” includes cost of removal being amortized through rates and various items subject to reconciliation including rate change levelization.

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 equity and other investments consist of Rabbi Trusts for deferred compensation plans and a supplemental retirement benefit life insurance trust. The Rabbi Trusts primarily include equity securities and money market funds. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2.

•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 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 measurements 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 products with no adjustment are included in fair value Level 1. 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 fair value Level 2. 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 fair value Level 3. 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 foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2.

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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 $6 million as of September 30, 2020 and December 31, 2019, respectively, and is included in "Other Assets" on our condensed consolidated balance sheets.

The financial instruments measured at fair value as of September 30, 2020 and December 31, 2019, respectively, consisted of:

As of September 30, 2020	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	41	$	12	$	—	$	—	$	53
Derivative assets
Derivative financial instruments - power	$	8	$	19	$	118	$	(67)	$	78
Derivative financial instruments - gas	4		26		29		(37)		22
Contracts for differences	—		—		2		—		2
Derivative financial instruments – other	—		2		—		—		2
Total	$	12	$	47	$	149	$	(104)	$	104
Derivative liabilities
Derivative financial instruments - power	$	(17)	$	(31)	$	(34)	$	77	$	(5)
Derivative financial instruments - gas	—		(5)		(4)		8		(1)
Contracts for differences	—		—		(92)		—		(92)
Derivative financial instruments – other	—		—		(2)		—		(2)
Total	$	(17)	$	(36)	$	(132)	$	85	$	(100)

As of December 31, 2019	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	38	$	13	$	—	$	—	$	51
Derivative assets
Derivative financial instruments - power	$	4	$	23	$	120	$	(54)	$	93
Derivative financial instruments - gas	—		40		31		(71)		—
Contracts for differences	—		—		2		—		2
Total	$	4	$	63	$	153	$	(125)	$	95
Derivative liabilities
Derivative financial instruments - power	$	(28)	$	(43)	$	(29)	$	92	$	(8)
Derivative financial instruments - gas	(4)		(26)		(5)		33		(2)
Contracts for differences	—		—		(94)		—		(94)
Derivative financial instruments - other	—		(1)		—		—		(1)
Total	$	(32)	$	(70)	$	(128)	$	125	$	(105)

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The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three and nine months ended September 30, 2020 and 2019, respectively, is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions)	2020		2019		2020		2019
Fair Value Beginning of Period,	$	16	$	(32)	$	25	$	(15)
Gains recognized in operating revenues	2		38		10		42
(Losses) recognized in operating revenues	—		(22)		(4)		(5)
Total gains recognized in operating revenues	2		16		6		37
Gains recognized in OCI	—		12		2		—
(Losses) recognized in OCI	(1)		—		(7)		(2)
Total gains (losses) recognized in OCI	(1)		12		(5)		(2)
Net change recognized in regulatory assets and liabilities	3		1		2		2
Purchases	(1)		—		—		(23)
Settlements	(1)		10		(9)		8
Transfers out of Level 3 (a)	(1)		—		(2)		—
Fair Value as of September 30,	$	17	$	7	$	17	$	7
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	$	2	$	16	$	6	$	37

(a) Transfers out of Level 3 were the result of increased observability of market data.

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

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Level 3 Fair Value Measurement

The table below illustrates 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.

As of September 30, 2020
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)	$	2.51	$	3.45	$	1.48
				AECO ($/MMBtu)	$	1.43	$	3.23	$	(0.17)
				Ameren ($/MWh)	$	26.03	$	40.53	$	14.73
				COB ($/MWh)	$	33.12	$	95.00	$	8.20
				ComEd ($/MWh)	$	24.01	$	39.26	$	12.65
				ERCOT N hub ($/MWh)	$	32.30	$	196.95	$	11.25
				ERCOT S hub ($/MWh)	$	32.66	$	203.37	$	11.41
				Indiana hub ($/MWh)	$	28.16	$	43.58	$	16.36
				Mid C ($/MWh)	$	29.58	$	95.00	$	4.00
				Minn hub ($/MWh)	$	22.75	$	37.78	$	11.52
				NoIL hub ($/MWh)	$	23.92	$	39.01	$	12.70
				PJM W hub ($/MWh)	$	28.41	$	59.53	$	14.28

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 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

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using credit default swap rates. Certain management assumptions were required, including development of pricing that extends 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	September 30, 2020
Risk of non-performance	0.59% - 0.64%
Discount rate	0.29% - 0.49%
Forward pricing ($ per KW-month)	$2.00 - $5.30

Fair Value of Debt

As of September 30, 2020 and December 31, 2019, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt amounted to $9,216 million and $8,168 million as of September 30, 2020 and December 31, 2019, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rates used to make these calculations take into account the credit ratings of the borrowers in each case. All debt is considered Level 2 within the fair value hierarchy.

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 September 30, 2020 and December 31, 2019, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:

As of September 30, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	11	$	3	$	7	$	1
Derivative liabilities	(7)		(1)		(26)		(83)
	4		2		(19)		(82)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		—
	—		—		(1)		—
Total derivatives before offset of cash collateral	4		2		(20)		(82)
Cash collateral receivable	—		—		6		3
Total derivatives as presented in the balance sheet	$	4	$	2	$	(14)	$	(79)

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As of December 31, 2019	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	1	$	4	$	1	$	2
Derivative liabilities	(1)		(2)		(39)		(86)
	—		2		(38)		(84)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		(1)
	—		—		(1)		(1)
Total derivatives before offset of cash collateral	—		2		(39)		(85)
Cash collateral receivable	—		—		27		1
Total derivatives as presented in the balance sheet	$	—	$	2	$	(12)	$	(84)

The net notional volumes of the outstanding derivative instruments associated with Networks activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:

	September 30,	December 31,
As of	2020	2019
(Millions)
Wholesale electricity purchase contracts (MWh)	5.1	5.1
Natural gas purchase contracts (Dth)	8.8	8.5
Fleet fuel purchase contracts (Gallons)	2.4	2.2

Derivatives not designated as hedging instruments

NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We 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 us 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.

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The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of September 30, 2020 and December 31, 2019 and amounts reclassified from regulatory assets and liabilities into income for the three and nine months ended September 30, 2020 and 2019 are as follows:

(Millions)	Loss or Gain Recognized in Regulatory Assets/Liabilities				Location of Loss Reclassified from Regulatory Assets/Liabilities into Income	Loss Reclassified from Regulatory Assets/Liabilities into Income
As of						Three Months Ended September 30,				Nine Months Ended September 30,
September 30, 2020	Electricity		Natural Gas		2020	Electricity		Natural Gas		Electricity		Natural Gas
Regulatory assets	$	9	$	—	Purchased power, natural gas and fuel used	$	8	$	—	$	41	$	5
Regulatory liabilities	$	—	$	(4)
December 31, 2019					2019
Regulatory assets	$	24	$	4	Purchased power, natural gas and fuel used	$	6	$	—	$	16	$	—

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 September 30, 2020, UI has recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $90 million, a gross derivative liability of $92 million ($89 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, 2019, UI had recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $92 million, a gross derivative liability of $94 million ($92 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 and nine months ended September 30, 2020 and 2019, respectively, were as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Millions)
Derivative assets	$	—	$	—	$	—	$	(3)
Derivative liabilities	$	3	$	2	$	2	$	5

Certain foreign currency exchange contracts are not designated as hedging instruments. For both the three and nine months ended September 30, 2020, we recorded a gain of $3 million related to our foreign currency contracts not designated as hedging instruments, included in "Other income" in our condensed consolidated statements of income. No amounts were recorded for both the three and nine months ended September 30, 2019.

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Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:

Three Months Ended September 30,	(Loss) Recognized in OCI on Derivatives (a)		Location of Loss (Gain) Reclassified from Accumulated OCI into Income	Loss (Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2020
Interest rate contracts	$	—	Interest expense	$	1	$	86
Commodity contracts	(1)		Purchased power, natural gas and fuel used	—		259
Foreign currency exchange contracts	—			—
Total	$	(1)		$	1
2019
Interest rate contracts	$	—	Interest expense	$	1	$	72
Commodity contracts	—		Purchased power, natural gas and fuel used	(1)		279
Foreign currency exchange contracts	(5)			—
Total	$	(5)		$	—

Nine Months Ended September 30,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss (Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2020
Interest rate contracts	$	—	Interest expense	$	3	$	251
Commodity contracts	(2)		Purchased power, natural gas and fuel used	1		999
Foreign currency exchange contracts	(2)			—
Total	$	(4)		$	4
2019
Interest rate contracts	$	—	Interest expense	$	5	$	226
Commodity contracts	—		Purchased power, natural gas and fuel used	(1)		1,101
Foreign currency exchange contracts	(4)			—
Total	$	(4)		$	4

(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 $52 million and $55 million as of September 30, 2020 and December 31, 2019, respectively. We recorded $1 million and $3 million in net derivative losses related to discontinued cash flow hedges for the three and nine months ended September 30, 2020, respectively and $1 million and $5 million for the three and nine months ended September 30, 2019, respectively. We will amortize approximately $1 million of discontinued cash flow hedges for the remainder of 2020.

Unrealized losses of $1 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable as of September 30, 2020. We expect that $1 million of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is 12 months.

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(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.

The net notional volumes of outstanding derivative instruments associated with Renewables activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:

	September 30,	December 31,
As of	2020	2019
(MWh/Dth in millions)
Wholesale electricity purchase contracts	3	4
Wholesale electricity sales contracts	8	9
Natural gas and other fuel purchase contracts	29	29
Financial power contracts	12	10
Basis swaps – purchases	40	42
Basis swaps – sales	—	1

The fair values of derivative contracts associated with Renewables activities as of September 30, 2020 and December 31, 2019, respectively, consisted of:

	September 30,		December 31,
As of	2020		2019
(Millions)
Wholesale electricity purchase contracts	$	8	$	10
Wholesale electricity sales contracts	1		4
Natural gas and other fuel purchase contracts	6		(2)
Financial power contracts	62		73
Basis swaps – purchases	12		—
Total	$	89	$	85

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The tables below present Renewables' derivative positions as of September 30, 2020 and December 31, 2019, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:

As of September 30, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	49	$	111	$	1	$	2
Derivative liabilities	(26)		(13)		(3)		(2)
	23		98		(2)		—
Designated as hedging instruments
Derivative assets	5		20		2		1
Derivative liabilities	(7)		(15)		(5)		(3)
	(2)		5		(3)		(2)
Total derivatives before offset of cash collateral	21		103		(5)		(2)
Cash collateral payable	(8)		(20)		—		—
Total derivatives as presented in the balance sheet	$	13	$	83	$	(5)	$	(2)

As of December 31, 2019	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	23	$	110	$	42	$	13
Derivative liabilities	(1)		(7)		(48)		(18)
	22		103		(6)		(5)
Designated as hedging instruments
Derivative assets	—		18		5		4
Derivative liabilities	—		(9)		(13)		(6)
	—		9		(8)		(2)
Total derivatives before offset of cash collateral	22		112		(14)		(7)
Cash collateral (payable) receivable	(11)		(30)		7		6
Total derivatives as presented in the balance sheet	$	11	$	82	$	(7)	$	(1)

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Derivatives not designated as hedging instruments

The effects of trading and non-trading derivatives associated with Renewables activities for the three and nine months ended September 30, 2020, consisted of:

	Three Months Ended						Nine Months Ended
	September 30, 2020						September 30, 2020
	Trading		Non-trading		Total amount per income statement		Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	3	$	—			$	1	$	—
Wholesale electricity sales contracts	(7)		(11)				(1)		4
Financial power contracts	4		(12)				1		2
Financial and natural gas contracts	—		(8)				—		(13)
Total (loss) gain included in operating revenues	$	—	$	(31)	$	1,470	$	1	$	(7)	$	4,651
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	9			$	—	$	(2)
Wholesale electricity sales contracts	—		1				—		—
Financial and natural gas contracts	—		16				—		19
Total gain included in purchased power, natural gas and fuel used	$	—	$	26	$	259	$	—	$	17	$	999
Total (Loss) Gain	$	—	$	(5)			$	1	$	10

The effects of trading and non-trading derivatives associated with Renewables activities for the three and nine months ended September 30, 2019, consisted of:

	Three Months Ended						Nine Months Ended
	September 30, 2019						September 30, 2019
	Trading		Non-trading		Total amount per income statement		Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	—			$	(2)	$	—
Wholesale electricity sales contracts	—		42				2		37
Financial power contracts	—		13				—		22
Financial and natural gas contracts	—		1				(1)		1
Total (loss) gain included in operating revenues	$	(1)	$	56	$	1,487	$	(1)	$	60	$	4,729
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(19)			$	—	$	(2)
Financial power contracts	—		—				—		(2)
Financial and natural gas contracts	—		6				—		10
Total (loss) gain included in purchased power, natural gas and fuel used	$	—	$	(13)	$	279	$	—	$	6	$	1,101
Total (Loss) Gain	$	(1)	$	43			$	(1)	$	66

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During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the three and nine months ended September 30, 2019.

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:

Three Months Ended September 30,	(Loss) 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)
2020
Commodity contracts	$	(17)	Operating revenues	$	5	$	1,470
2019
Commodity contracts	$	13	Operating revenues	$	3	$	1,487

Nine Months Ended September 30,	(Loss) 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)
2020
Commodity contracts	$	(9)	Operating revenues	$	4	$	4,651
2019
Commodity contracts	$	(2)	Operating revenues	$	3	$	4,729

(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 $4 million of losses included in accumulated OCI at September 30, 2020, are expected to be reclassified into earnings within the next twelve months. We did not record any net derivative losses related to discontinued cash flow hedges for both the three and nine months ended September 30, 2020 and 2019.

(c) Interest rate contracts

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.

On January 31, 2020, AVANGRID entered into two treasury locks, with a total notional amount of $600 million, to hedge the issuance of forecasted fixed rate debt. The treasury locks were designated and qualified as cash flow hedges and were settled upon the second quarter debt issuance described in Note 15. The $27 million loss on the treasury locks is reported as a component of accumulated OCI and is being reclassified into earnings during the periods in which the related interest expense of the forecasted debt is incurred.

The net loss in accumulated OCI related to previously settled interest rate contracts is $59 million and $38 million as of September 30, 2020 and December 31, 2019, respectively. We amortized into income $2 million and $5 million of the loss related to the settled interest rate contracts for the three and nine months ended September 30, 2020, respectively, and $1 million for the three and nine months ended September 30, 2019. We will amortize approximately $2 million of the net loss on the interest rate contracts for the remainder of 2020.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:

Three Months Ended September 30,	Gain (Loss) 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)
2020
Interest rate contracts	$	—	Interest expense	$	2	$	86
2019
Interest rate contracts	$	—	Interest expense	$	1	$	72

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Nine Months Ended September 30,	(Loss) 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)
2020
Interest rate contracts	$	(27)	Interest expense	$	5	$	251
2019
Interest rate contracts	$	(24)	Interest expense	$	1	$	226

(a) Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods.

(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 September 30, 2020, UI would have had to post an aggregate of approximately $13 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 $23 million and $21 million as of September 30, 2020 and December 31, 2019, 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 September 30, 2020 is $9 million, for which we have posted collateral.

Note 8. Contingencies

We are party to various legal disputes arising as part of our normal business activities. We 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,

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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 $26 million and $7 million, respectively, as of September 30, 2020, which has not changed since December 31, 2019, 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 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). Pursuant to the October 2018 Order, the NETOs filed initial briefs on the proposed methodology in all four Complaints on January 11, 2019 and replied to the initial briefs on March 8, 2019.

On November 21, 2019, the FERC issued rulings on two complaints challenging the base return on equity for Midcontinent Independent System Operator, or MISO transmission owners. These rulings established a new zone of reasonableness based on equal weighting of the DCF and capital-asset pricing model for establishing the base return on equity. This resulted in a base return on equity of 9.88% as the midpoint of the zone of reasonableness. Various parties have requested rehearing on this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. We cannot predict the outcome of these proceedings, including the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for our pending four Complaints.

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 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 no 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 Action Regarding LDC Gas Transportation Service on Algonquin Gas Transmission

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

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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, and on June 7, 2019, the district court granted the Company’s Motion to Dismiss and dismissed all claims. On July 3, 2019, the plaintiffs filed notice of appeal in the U.S. Court of Appeals for the First Circuit and, on October 18, 2019, filed a brief in support of appeal. On January 2, 2020, the Company and Eversource filed a joint motion in opposition and on January 23, 2020, the plaintiffs filed a reply brief. On April 9, 2020, the U.S. Court of Appeals for the First Circuit canceled oral arguments of the appeal and ordered the case to be decided on the briefs without oral argument. On September 9, 2020, the First Circuit denied the appeal and affirmed the District Court’s dismissal of PNE’s complaint.

Gas Storage Indemnification Claims

On May 1, 2018, ARHI closed a transaction to sell our gas storage business to Amphora Gas Storage USA, LLC. On October 30, 2019, ARHI received notice of a claim for indemnification from Amphora Gas Storage USA, LLC under the purchase agreement with respect to such sale in the amount of approximately $20 million related to, among other things, certain alleged violations of occupational, health and safety requirements, the condition and sufficiency of assets and a third party intellectual property infringement claim. Pursuant to the terms of the purchase agreement, the aggregate amount for which ARHI may be responsible to indemnify Amphora Gas Storage USA, LLC for all claims arising under the purchase agreement, other than those related to certain fundamental representations, tax matters and claims involving fraud, shall not exceed 15% of the purchase price, or approximately $10 million. ARHI has disputed this claim for indemnification. We cannot predict the outcome of this matter.

Guarantee Commitments to Third Parties

As of September 30, 2020, we had approximately $449 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 September 30, 2020, neither we nor our subsidiaries have any liabilities recorded for these instruments.

PILOT Program Commitment

In June 2020, Renewables entered into a Payment In Lieu of Taxes (PILOT) agreement related to two of its projects with Torrance County, New Mexico. The agreement requires PILOT payments to Torrance County through 2049. No payments are due until 2021.

Note 9. Environmental Liabilities

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

Waste sites

The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-six waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-six sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; five sites are included in Maine’s Uncontrolled Sites Program; one site is included in the Brownfield Cleanup 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, six of the twenty-six 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 $6 million related to twelve of the twenty-six sites. We have paid remediation costs related to the remaining fourteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation

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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 $13 million to $23 million as of September 30, 2020. 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). Six 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 and one site is pending application into the Brownfield Cleanup 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 $181 million to $378 million as of September 30, 2020. 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 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 September 30, 2020 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 September 30, 2020 and December 31, 2019, the liability associated with our MGP sites in Connecticut was $96 million and $97 million, respectively, 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.

Our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $344 million and $349 million as of September 30, 2020 and December 31, 2019, 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 2058.

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 customers.

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English Station

In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was 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 of a motion to reopen by any party.

In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. 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. 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. The plaintiffs have appealed the court's decision to strike. 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. 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 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 September 30, 2020 and December 31, 2019, the amount reserved for this matter was $17 million and $16 million, respectively. We cannot predict the outcome of this matter.

On April 24, 2020, ACV Environmental Services Company (ACV) filed a lawsuit in Connecticut Superior Court against UI arising out of a contract dispute for services rendered by ACV in the demolition of the Station B at the English Station site. The complaint seeks damages in the amount of $5 million on claims of breach of contract, breach of the covenant of good faith and fair dealing, quantum merit, and unjust enrichment. The claims arise from the alleged non-payment of certain change order requests. We cannot predict the outcome of this matter.

Note 10. Post-retirement and Similar Obligations

We made $34 million and $59 million of pension contributions for the three and nine months ended September 30, 2020, respectively. We expect to make additional contributions of $25 million for the remainder of 2020.

The components of net periodic benefit cost for pension benefits for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Millions)
Service cost	$	12	$	10	$	35	$	30
Interest cost	27		33		81		98
Expected return on plan assets	(50)		(48)		(150)		(144)
Amortization of:
Prior service costs	—		—		—		(1)
Actuarial loss	31		28		94		85
Net Periodic Benefit Cost	$	20	$	23	$	60	$	68

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The components of net periodic benefit cost for postretirement benefits for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of: 

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Millions)
Service cost	$	1	$	1	$	2	$	2
Interest cost	4		4		10		12
Expected return on plan assets	(2)		(1)		(6)		(5)
Amortization of:
Prior service costs	(3)		(3)		(7)		(7)
Actuarial loss	—		—		1		(1)
Net Periodic Benefit Cost	$	—	$	1	$	—	$	1

Note 11. Equity

As of September 30, 2020 and December 31, 2019, we had 485,597 and 485,810 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three and nine months ended September 30, 2020 we released 0 and 213 shares of common stock held in trust, respectively. During both the three and nine months ended September 30, 2019, we released no shares of common stock held in trust. In October 2020, we released 4,332 shares of common stock held in trust.

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 Iberdrola's relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In May 2020, 42,777 shares were repurchased pursuant to the stock repurchase program. As of September 30, 2020, a total of 303,835 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. The total cost of all repurchases, including commissions, was $14 million as of September 30, 2020.

Accumulated Other Comprehensive Loss 

Accumulated Other Comprehensive Loss for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:

	As of June 30,		Three Months Ended September 30,		As of September 30,		As of June 30,		Three Months Ended September 30,		As of September 30,
	2020		2020		2020		2019		2019		2019
(Millions)
Change in revaluation of defined benefit plans	$	(12)	$	—	$	(12)	$	(13)	$	—	$	(13)
Loss on nonqualified pension plans	(7)		—		(7)		(7)		—		(7)
Unrealized (loss) gain during period on derivatives qualifying as cash flow hedges, net of income tax expense of $(3) for 2020 and $2 for 2019	(29)		(15)		(44)		(18)		5		(13)
Reclassification to net income of losses on cash flow hedges, net of income tax expense of $0 for 2020 and $1 for 2019(a)	(60)		9		(51)		(71)		5		(66)
(Loss) Gain on derivatives qualifying as cash flow hedges	(89)		(6)		(95)		(89)		10		(79)
Accumulated Other Comprehensive (Loss) Income	$	(108)	$	(6)	$	(114)	$	(109)	$	10	$	(99)

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	As of December 31,		Nine Months Ended September 30,		As of September 30,		As of December 31,		Adoption of new accounting		Nine Months Ended September 30,		As of September 30,
	2019		2020		2020		2018		standard		2019		2019
(Millions)
Change in revaluation of defined benefit plans	$	(12)	$	—	$	(12)	$	(11)	$	(2)	$	—	$	(13)
Loss on nonqualified pension plans	(7)		—		(7)		(6)		—		(1)		(7)
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(8) for both 2020 and 2019	(13)		(31)		(44)		9		—		(22)		(13)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense of $1 for 2020 and $2 for 2019(a)	(63)		12		(51)		(64)		(10)		8		(66)
Loss on derivatives qualifying as cash flow hedges	(76)		(19)		(95)		(55)		(10)		(14)		(79)
Accumulated Other Comprehensive Loss	$	(95)	$	(19)	$	(114)	$	(72)	$	(12)	$	(15)	$	(99)

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

Note 12. Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three and nine months ended September 30, 2020 and 2019, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations.

The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three and nine months ended September 30, 2020 and 2019, respectively, consisted of:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	87	$	150	$	415	$	477
Denominator:
Weighted average number of shares outstanding - basic	309,491,082		309,491,082		309,496,234		309,491,082
Weighted average number of shares outstanding - diluted	309,550,126		309,517,778		309,554,838		309,512,301
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	0.28	$	0.48	$	1.34	$	1.54
Earnings Per Common Share, Diluted	$	0.28	$	0.48	$	1.34	$	1.54

Note 13. Segment Information

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

•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.

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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 earnings from changes in the fair value of derivative instruments, accelerated depreciation derived from repowering of wind farms and costs incurred in connection with the COVID-19 pandemic.

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 our condensed consolidated financial statements. Refer to Note 4 - Revenue for more detailed information on revenue by segment.

Segment information as of and for the three and nine months ended September 30, 2020, consisted of:

Three Months Ended September 30, 2020	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,194	$	275	$	1	$	1,470
Revenue - intersegment	3		1		(4)		—
Depreciation and amortization	151		104		—		255
Operating income (loss)	160		7		(2)		165
Earnings (losses) from equity method investments	3		(2)		—		1
Interest expense, net of capitalization	63		(1)		24		86
Income tax expense (benefit)	20		(7)		2		15
Adjusted net income	$	99	$	32	$	(31)	$	100

Nine Months Ended September 30, 2020	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	3,775	$	875	$	1	$	4,651
Revenue - intersegment	4		1		(5)		—
Depreciation and amortization	446		301		1		748
Operating income	617		24		6		647
Earnings (losses) from equity method investments	8		(11)		—		(3)
Interest expense, net of capitalization	199		(1)		53		251
Income tax expense (benefit)	75		(53)		(1)		21
Adjusted net income	379		108		(53)		434
Capital expenditures	1,312		648		—		1,960
As of September 30, 2020
Property, plant and equipment	16,640		9,782		10		26,432
Equity method investments	138		530		—		668
Total assets	$	24,178	$	12,694	$	(1,232)	$	35,640

(a) Includes Corporate and intersegment eliminations.

Segment information for the three and nine months ended September 30, 2019 and as of December 31, 2019, consisted of:

Three Months Ended September 30, 2019	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,139	$	347	$	1	$	1,487
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	138		98		1		237
Operating income	182		53		4		239
Earnings (losses) from equity method investments	3		(4)		—		(1)
Interest expense, net of capitalization	66		(1)		7		72
Income tax expense	28		2		3		33
Adjusted net income	$	89	$	46	$	(12)	$	123

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Nine Months Ended September 30, 2019	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	3,831	$	896	$	2	$	4,729
Revenue - intersegment	6		—		(6)		—
Depreciation and amortization	407		273		1		681
Operating income	668		115		4		787
Earnings (losses) from equity method investments	8		(7)		—		1
Interest expense, net of capitalization	201		6		19		226
Income tax expense (benefit)	117		(15)		1		103
Adjusted net income	355		115		(28)		442
Capital expenditures	1,086		959		—		2,045
As of December 31, 2019
Property, plant and equipment	15,840		9,368		10		25,218
Equity method investments	139		506		—		645
Total assets	$	23,250	$	13,163	$	(1,997)	$	34,416

(a) Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three and nine months ended September 30, 2020 and 2019, respectively, is as follows:

	Three Months Ended September 30,				Nine Months Ended September 30,
	2020		2019		2020		2019
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	100	$	123	$	434	$	442
Adjustments:
Mark-to-market earnings - Renewables (1)	(7)		42		9		66
Restructuring charges (2)	(1)		(2)		(5)		(4)
Accelerated depreciation from repowering (3)	(3)		(5)		(9)		(15)
Impact of COVID-19 (4)	(8)		—		(21)		—
Income tax impact of adjustments	5		(9)		7		(12)
Net Income Attributable to Avangrid, Inc.	$	87	$	150	$	415	$	477

(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(2)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.

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

(4)Represents costs incurred in connection with the COVID-19 pandemic.

Note 14. 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 and nine months ended September 30, 2020 and 2019, respectively, consisted of:

Three Months Ended September 30,	2020				2019
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(1)
Iberdrola Financiación, S.A.	$	—	$	(3)	$	—	$	(1)
Iberdrola, S.A.	$	—	$	(10)	$	—	$	(8)
Vineyard Wind	$	3	$	—	$	4	$	—
Iberdrola Solutions	$	2	$	—	$	—	$	—
Other	$	—	$	(1)	$	—	$	(1)

Nine Months Ended September 30,	2020				2019
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola Renovables Energía, S.L.	$	—	$	(6)	$	—	$	(10)
Iberdrola Financiación, S.A.	$	—	$	(5)	$	—	$	(2)
Iberdrola, S.A.	$	—	$	(31)	$	—	$	(28)
Vineyard Wind	$	7	$	—	$	11	$	—
Iberdrola Solutions	$	2	$	—	$	—	$	—
Other	$	—	$	(2)	$	1	$	(2)

In addition to the statements of income items above, we made purchases of turbines for wind farms from Siemens-Gamesa, in which Iberdrola had an 8.1% ownership interest until Iberdrola sold its interest in February 2020. After the sale, the turbine purchases are no longer considered related party transactions. The amounts capitalized for transactions while Siemens-Gamesa was considered a related party were $11 million and $18 million for the periods ended September 30, 2020 and December 31, 2019, respectively.

Related party balances as of September 30, 2020 and December 31, 2019, respectively, consisted of:

As of	September 30, 2020				December 31, 2019
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	1	$	(32)	$	1	$	(42)
Iberdrola Renovables Energía, S.L.	$	—	$	(6)	$	—	$	—
Iberdrola Financiación, S.A.	$	—	$	(4)	$	—	$	—
Vineyard Wind	$	3	$	—	$	5	$	—
Iberdrola Solutions	$	2	$	(4)	$	—	$	—
Siemens-Gamesa (a)	$	—	$	—	$	—	$	(18)
Other	$	1	$	(1)	$	4	$	(4)

(a) After Iberdrola's sale of its interest of Siemens-Gamesa in February 2020, transactions with Siemens-Gamesa are no longer considered related party.

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.

See Note 19 - Equity Method Investments for more information on Vineyard Wind, LLC (Vineyard Wind).

We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had a notes payable balance of $4 million and $0, respectively, as of September 30, 2020 and December 31, 2019.

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.

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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 September 30, 2020 and December 31, 2019, was zero and $150 million, respectively.

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 September 30, 2020 and December 31, 2019, there was no outstanding amount under this credit facility.

Iberdrola made additional financial commitments to AVANGRID related to an announced merger, both of which are discussed in Note 21 - Subsequent Event.

Note 15. Other Financial Statement Items

Accounts receivable and unbilled revenue, net

Accounts receivable and unbilled revenues, net as of September 30, 2020 and December 31, 2019 consisted of:

As of	September 30, 2020		December 31, 2019
(Millions)
Trade receivables and unbilled revenues	$	1,115	$	1,151
Allowance for credit losses	(94)		(69)
Accounts receivable and unbilled revenues, net	$	1,021	$	1,082

The change in the allowance for credit losses for the three and nine months ended September 30, 2020 and 2019 consisted of:

	Three Months Ended September 30,				Nine Months Ended September 30,
(Millions)	2020		2019		2020		2019
As of Beginning of Period,	$	85	$	73	$	69	$	62
Current period provision	19		24		60		71
Write-off as uncollectible	(10)		(24)		(35)		(60)
As of September 30,	$	94	$	73	$	94	$	73

The Deferred Payment Arrangements (DPA) receivable balance was $77 million and $65 million at September 30, 2020 and December 31, 2019, respectively. The allowance for credit losses for DPAs at September 30, 2020 and December 31, 2019 was $37 million and $33 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three and nine months ended September 30, 2020, was $3 million and $4 million, respectively, and for the three and nine months ended September 30, 2019, $1 million and $3 million, respectively.

Prepayments and other current assets

Included in prepayments and other current assets are $179 million and $123 million of prepaid other taxes as of September 30, 2020 and December 31, 2019, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of September 30, 2020 and December 31, 2019, respectively, were as follows:

	September 30,		December 31,
As of	2020		2019
(Millions)
Property, plant and equipment
Accumulated depreciation	$	9,713	$	9,059
Intangible assets
Accumulated amortization	$	315	$	305

Debt

As of September 30, 2020 and December 31, 2019, "Notes Payable" consisted of $999 million and $562 million, respectively, of commercial paper outstanding, presented net of discounts on our condensed consolidated balance sheets.

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On April 9, 2020, AGR issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%.

On May 1, 2020, NYSEG remarketed $200 million aggregate Pollution Control bonds with maturity dates ranging from 2026 to 2029 at fixed interest rates of 1.40% to 1.61%. The remarketing was a non-cash transaction to reset the interest rates.

On June 29, 2020, we entered into a revolving credit agreement with several lenders (the 2020 Credit Facility), that provides maximum borrowings up to $500 million. We will pay an annual facility fee, which ranges from 15 to 30 basis points, dependent on AVANGRID’s credit rating. As of September 30, 2020, the facility fee is 20 basis points. The 2020 Credit Facility matures on June 28, 2021. We have the right to extend, and the banks are obligated to extend, the commitments and loans outstanding under the facility for one year at a cost of 75 basis points. We may also request an extension of the facility for one year, which the banks may grant at their discretion for a fee that will be determined at the time of the request. As of September 30, 2020, there were no borrowings outstanding under this credit facility.

On September 1, 2020, BGC issued $25 million aggregate principal amount of unsecured notes maturing in 2050 at a fixed interest rate of 3.68%.

On September 25, 2020, NYSEG issued $200 million aggregate principal amount of unsecured notes maturing in 2030 at a fixed interest rate of 1.95%.

Disposition

On July 24, 2020, Renewables reached an agreement to transfer 85% ownership in one South Dakota wind farm for a purchase price of $236 million, subject to closing adjustments as applicable. The transaction, which is subject to the satisfaction of customary closing conditions, including FERC approval, is expected to be completed during the fourth quarter of 2020. As of September 30, 2020, the carrying value of the wind farm primarily consisted of $196 million of assets held for sale included in "property, plant and equipment" on our condensed consolidated balance sheet.

Note 16. Income Tax Expense

The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2020, were 15.6% and 5.1%, respectively. The effective tax rates for the three and nine months ended September 30, 2020 are below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act.

The effective tax rates, inclusive of federal and state income tax, for the three and nine months ended September 30, 2019, were 19.2% and 18.3%, respectively. The effective tax rate for the three months ended September 30, 2019 is below than the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, offset by unfavorable discrete tax adjustments. The effective tax rate for the nine months ended September 30, 2019 is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and favorable discrete tax adjustments.

Note 17. Stock-Based Compensation Expense

The Avangrid, Inc. Amended and Restated Omnibus Incentive Plan (the Plan) provides for, among other things, the issuance of performance stock units (PSUs), restricted stock units (RSUs) and phantom share units (Phantom Shares).

In June and October 2018, 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vest in full in one installment in June and December 2020, respectively, for each award, provided that the grantee remains continuously employed with AVANGRID through the applicable date. The fair value on the grant date was determined based on a price of $50.40 per share for the June 2018 awards and $47.59 per share for the October 2018 awards. In June 2020, 60,000 RSU's, plus dividend equivalents accrued through the vesting period, were settled for $3 million in cash.

In August 2020, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in three equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting dates. The fair value on the grant date was determined based on a price of $48.99 per share.

In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes, in 2020, 2021 and 2022. The remaining unvested PSUs were forfeited. In May 2020, 42,777 shares of common stock were issued to settle the first installment payment and 2,605 PSUs were forfeited from the originally approved total number of PSUs.

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On March 18, 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards will vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of AVANGRID’s common stock at each reporting date until the date of settlement. In June 2020, $2 million was paid to settle the first installment under this plan. As of September 30, 2020, the total liability is $2 million, which is included in other current and non-current liabilities.

Total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three and nine months ended September 30, 2020 was $1 million and $12 million, respectively, and for the three and nine months ended September 30, 2019 was $0 and $2 million, respectively.

Note 18. Variable Interest Entities

We participate in certain partnership arrangements that qualify as variable interest entities (VIEs). Consolidated VIE's 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.

On March 2, 2020, we closed on two TEF agreements, receiving $237 million from two tax equity investors related to two wind farms that reached commercial operation. On May 8, 2020, we closed on a TEF agreement, receiving $70 million from the same tax equity investors related to a wind farm that reached commercial operation. The three wind farms are part of a portfolio of companies called Aeolus Wind Power VII, LLC (Aeolus VII). One more wind farm undergoing a repowering will become a part of Aeolus VII once the project is complete and the TEF agreement is finalized. The four wind farms expected to be part of Aeolus VII will total 681 MW of wind power.

The assets and liabilities of the VIEs totaled approximately $1,720 million and $104 million, respectively, at September 30, 2020. As of December 31, 2019, the assets and liabilities of VIEs totaled approximately $806 million and $29 million, respectively. At September 30, 2020 and December 31, 2019, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.

At September 30, 2020, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot) and Aeolus VII are our consolidated 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 El Cabo, Patriot and Aeolus VII 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.

See Note 19 - Equity Method Investments for information on our VIE we do not consolidate.

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Note 19. Equity Method Investments

Renewables holds a 50% voting interest in Vineyard Wind, a joint venture with Copenhagen Infrastructure Partners (CIP). 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.

In 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project. Pursuant to a joint bidding agreement between Renewables and CIP, CIP held a right to sell all or a portion of its 50% ownership interest to Renewables, subject to certain conditions, however this right expired on September 30, 2020. In October 2020, Vineyard Wind submitted an offshore wind solicitation to NYSERDA to provide 1,200 to 1,300 MW of offshore wind through the development of its Liberty Wind Project. In October 2020, Renewables and CIP entered into an agreement pursuant to which, subject to the satisfaction of certain conditions, CIP may exercise an option to effectuate a series of transactions that include the sale of its ownership interest in the Liberty Wind and Park City Wind Projects to Renewables and the purchase of Renewables’ residual ownership interest in certain lease areas that have not been awarded an offtake agreement as of the date of the exercise of such option by CIP.

Under the provisions of the LLC agreement, Renewables has contributed $157 million to Vineyard Wind. Contributions of $110 million have also been made to enter into a second offshore easement contract and for development costs for the area, which includes the site of the proposed Liberty Wind Project. We expect to provide additional capital contributions.

Vineyard Wind cannot finance its activities without additional support from its owners or third parties so Vineyard Wind is considered a VIE. We are not the primary beneficiary since we do not have a controlling interest in Vineyard Wind, and therefore we do not consolidate Vineyard Wind. Renewables' investment in Vineyard Wind was $261 million and $227 million as of September 30, 2020 and December 31, 2019, respectively.

Networks holds an approximate 20% ownership interest in New York TransCo, LLC (New York TransCo). Through New York TransCo, Networks has formed a partnership with affiliates of 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. In 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The total project cost is $600 million, plus interconnection costs. Networks’ contribution as 20% co-owner is $120 million. As of both September 30, 2020 and December 31, 2019, there was no amount receivable from New York TransCo.

Note 20. Restructuring and Severance Related Expenses

In 2019, we announced changes across the Company aimed to mitigate costs and deliver sustainable growth, including among others, outsourcing and insourcing of certain areas of the Company and technology initiatives that help improve efficiency and reduce costs. Those decisions and transactions resulted in restructuring charges of $0 and $2 million recorded for the three and nine months ended September 30, 2020, respectively, and $1 million and $3 million for the three and nine months ended September 30, 2019, respectively, which are included in "Operations and maintenance" in our condensed consolidated statements of income. "Depreciation and amortization" in our condensed consolidated statements of income includes $1 million and $3 million for the three and nine months ended September 30, 2020, respectively, and $1 for both the three and nine months ended September 30, 2019 for restructuring activities.

As of September 30, 2020, our severance and lease restructuring charges reserves, which are recorded in "Other current liabilities" and "Other liabilities" on our condensed consolidated balance sheets, consisted of:

	Nine Months Ended September 30, 2020
	(Millions)
Beginning Balance	$	5
Restructuring and severance related expenses	2
Payments	(3)
Ending Balance	$	4

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Note 21. Subsequent Event

On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation (PNMR) and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID (Merger Sub), entered into an Agreement and Plan of Merger (Merger Agreement), pursuant to which Merger Sub will merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID (Merger). Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (PNMR common stock) (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash (Merger Consideration).

Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the FERC, the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. The Merger is currently expected to close in the fourth quarter of 2021.

The Merger Agreement also contains representations, warranties and covenants of PNMR, AVANGRID and Merger Sub, which are customary for transactions of this type. In addition, among other things, the Merger Agreement contains a covenant requiring PNMR to, prior to the Closing, enter into agreements (Four Corners Divestiture Agreements) providing for, and to make filings required to, exit from all ownership interests in the Four Corners Power Plant, all with the objective of having the closing date for such exit be no later than December 31, 2024.

In connection with the Merger, Iberdrola, S.A. has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. To the extent AVANGRID wishes to effect a funding transaction under the Iberdrola Funding Commitment Letter in order to pay the Merger Consideration, the specific terms of any such transaction will be negotiated between Iberdrola and AVANGRID on an arm’s length basis and must be approved by both (i) a majority of the members of the unaffiliated committee of the board of directors of AVANGRID, and (ii) a majority of the board of directors of AVANGRID. Under the terms of such commitment letter, Iberdrola S.A. has agreed to negotiate with AVANGRID the specific terms of any transaction effecting such funding commitment promptly and in good faith, with the objective that such terms shall be commercially reasonable and approved by AVANGRID. AVANGRID’s and Merger Sub’s obligations under the Merger Agreement are not conditioned upon AVANGRID obtaining financing.

The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before January 20, 2022 (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii) AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee).

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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, 2019 and 2018, and for the three years ended December 31, 2019, included in our Annual Report on Form 10-K for the year ended December 31, 2019, filed with the Securities and Exchange Commission, or the SEC, on March 2, 2020, 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 $36 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 3.3 million customers in New York and New England. Avangrid Renewables owns and operates 8.3 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 was named among the World’s Most Ethical companies in 2019 and 2020 by the Ethisphere Institute and listed by Forbes and Just Capital as one of the 2021 Just 100, an annual ranking of the most just U.S. public companies. AVANGRID employs approximately 6,600 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 2.3 million electric utility customers and delivering natural gas to approximately 1.0 million natural gas public utility customers as of September 30, 2020.

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 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 8,280 megawatts, or MW, as of September 30, 2020, including Renewables’ share of joint projects, of which 7,516 MW was installed wind capacity. As of September 30, 2020, approximately 67% of the capacity was contracted for an average period of 9.2 years, and 13% of installed capacity was hedged. Being among the top three largest wind operators in the United States based on installed capacity as of September 30, 2020, Renewables strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables currently operates 65 wind farms and four solar facilities in 21 states across the United States.

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Proposed Merger with PNMR

On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation, or PNMR, and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID, or Merger Sub, entered into an Agreement and Plan of Merger, or Merger Agreement, pursuant to which Merger Sub will merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID, or Merger. Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the merger is consummated, into the right to receive $50.30 in cash, or Merger Consideration, or approximately $4.3 billion in aggregate consideration. In connection with the Merger, Iberdrola, S.A. has provided the Iberdrola Funding Commitment Letter, pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to Avangrid of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. The Merger is expected to be consummated in the fourth quarter of 2021 and is subject to certain conditions including regulatory and PNMR shareholder approval and entry into agreements providing for, and to making filings required to, exit from all ownership interests in the Four Corners Power Plant and certain other customary closing conditions. For additional information, see Note 21 – Subsequent Event.

COVID-19

The continued spread of the novel Coronavirus, or COVID-19, has led to global economic disruption and volatility in financial markets and the United States economy. AVANGRID is one of the many companies providing essential services during this national emergency and we communicate regularly with federal and state authorities and industry resources to ensure a coordinated response. We have implemented business continuity and emergency response plans to continue to provide service to our customers and support our operational needs. We continue to monitor developments affecting both our workforce and our customers and will take precautions that we determine are necessary or appropriate. We regularly communicate with our customers regarding the tools and resources available and to help our customers stay informed during this public health crisis. In addition to measures to protect our workforce and critical operations, we have established a cross-functional task force to plan for a safe and effective return to office. AVANGRID is actively monitoring potential supply chain and transportation disruptions that could impact the Company’s operations and will implement plans to address any such impacts on our business.

This is a rapidly evolving situation that could lead to extended disruption of economic activity in our markets, which could adversely affect our business. We have not yet experienced a materially adverse impact to our business, results of operations or financial condition, however, given the uncertain scope and duration of the COVID-19 outbreak and its potential effects on our business, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition in the future.

For more information, see the risk factor under the heading “The outbreak of COVID-19 and its impact on business and economic conditions could negatively affect our business, results of operations or financial condition.” in Item 1A. Risk Factors in this Form 10-Q.

Summary of Results of Operations

Our operating revenues decreased by 1%, from $1,487 million for the three months ended September 30, 2019 to $1,470 million for the three months ended September 30, 2020.

Networks business revenues increased mainly due to increased customer rates and increased flow-through amortizations in the period. Renewables had a decrease in revenues mainly due to unfavorable mark to market, or MtM, changes on energy derivative transactions entered into for economic hedging purposes along with a decrease in wind generation output in the period.

Net income attributable to AVANGRID decreased by 42% from $150 million for the three months ended September 30, 2019 to $87 million for the three months ended September 30, 2020, primarily due to decreased revenue from Renewables and Other in the period.

Adjusted net income (a non-GAAP financial measure) decreased by 18% from $123 million for the three months ended September 30, 2019 to $100 million for the three months ended September 30, 2020. The decrease is primarily due to a $14 million decrease in Renewables driven by decrease in existing production, unfavorable results from decreased pricing and higher depreciation, a $15 million decrease in Corporate mainly driven by higher interest expenses, offset by a $10 million

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increase in Networks driven primarily by customer rate increases in the period and favorable tax benefits, which were offset by unfavorable outage restoration costs..

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, 2019.

Customer Disconnections

Due to the COVID-19 pandemic, all of our regulated utilities suspended customer disconnections during March 2020. In New York, we had voluntarily suspended disconnections for non-payment. In June 2020, the New York state legislature passed a bill stating moratoriums on residential customer disconnections shall remain in place until 180 days after the COVID-19 state of emergency in New York is lifted, or until no later than March 31, 2021, whichever comes first.

In Connecticut and Maine, regulatory orders for COVID-19 disconnection moratoriums cease on November 1, 2020, however, disconnections will not resume until the winter disconnection period has ended.

NYSEG and RG&E Rate Cases

On May 20, 2019, NYSEG and RG&E filed rate cases with the New York State Public Service Commission, or NYPSC, for new tariffs.

On March 23, 2020, the Public Utility Law Project (a party to the cases) submitted a letter motion requesting that the NYPSC administrative law judges assigned to preside over the rate cases require NYSEG and RG&E to pause settlement discussions and to provide new and accurate calculations based on the current and future expected economic impact of the COVID-19 pandemic. On March 31, 2020, NYSEG and RG&E, Multiple Intervenors (a party to the cases), and NYDPS staff each filed a response in opposition to the motion. On April 7, 2020, the NYPSC administrative law judges issued a Ruling Denying Public Utility Law Project’s Motion, allowing settlement negotiations to continue. On April 22, 2020, the Public Utility Law Project and AARP filed an interlocutory appeal requesting that the NYPSC review the determination of the administrative law judges. We cannot predict the outcome of this proceeding.

On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan. The effective date of new tariffs was November 1, 2020 with a make-whole provision back to April 17, 2020. We were granted a one month extension making the new effective date December 1, 2020, pending NYPSC approval of the joint proposal. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The joint proposal bases delivery revenues on an 8.80% ROE and 48% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50%. The below table provides a summary of the proposed delivery rate increases and delivery rate percentages, including rate levelization and excluding energy efficiency, which is a pass through, for all four businesses:

	Year 1				Year 2				Year 3
	Rate Increase		Delivery Rate %		Rate Increase		Delivery Rate %		Rate Increase		Delivery Rate %
Utility	(Millions)		Increase		(Millions)		Increase		(Millions)		Increase
NYSEG Electric	$	34.7	4.6	%	$	71.51	9.1	%	$	79.4	9.1	%
NYSEG Gas	$	—	—	%	$	1.58	0.8	%	$	3.3	1.6	%
RG&E Electric	$	10.7	2.4	%	$	22.92	5.2	%	$	25.4	5.2	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2.4	1.3	%

The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue the existing revenue decoupling mechanisms, or RDMs, for each business. Statements in

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support or opposition and reply statements were filed in July 2020, and a final decision by the NYPSC is expected during the fourth quarter of 2020. 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 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 NYDPS commenced a comprehensive investigation of the preparation and response to those events by New York's major electric utility companies. The investigation was expanded in the spring of 2018 to include other 2018 New York spring storm events.

On April 18, 2019, the NYDPS 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. On May 20, 2019, NYSEG and RG&E responded to the portion of the Order to Show Cause with respect to the recommendations contained in the 2018 Staff Report. The Commission granted the companies a series of extensions to respond to the portion of the Order to Show Cause with respect to why the Commission should not pursue a penalty action. A petition requesting Commission approval of a joint settlement agreement was filed with the Commission on December 17, 2019. On February 6, 2020, the Commission approved the joint settlement agreement, which allows the companies to avoid litigation and provides for payment by the companies of a $10.5 million penalty ($9.0 million by NYSEG and $1.5 million by RG&E). The proposed joint settlement provides for payment of these penalties as rate modifiers by the establishment of regulatory liabilities that will be amortized over the three-year term of the proposed rate plans for NYSEG Electric and RG&E Electric, respectively. The company cannot predict the outcome of the rate cases and the provisions for payment of these penalties.

CMP Rate Case

In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7%, based on an allowed ROE of 9.25% and a 50% equity ratio. The rate increase was effective March 1, 2020. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a period of 18 consecutive months, which commenced on March 1, 2020. CMP has satisfied all four of these quality measures since the measurement period commenced.

The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine ratepayers. The management audit was commenced in July 2020 by the MPUC’s consultants and is expected to conclude in December 2020.

CMP Metering and Billing Investigation

On February 19, 2020, the MPUC issued an order in CMP’s distribution rate case proceeding discussed above and on February 24, 2020 issued an order in the metering and billing investigation. Each order reflected the MPUC’s conclusion that CMP’s Metering and Billing system is accurately reporting data, there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. However, the MPUC orders imposed a reduction of 100 basis points in ROE, as a management efficiency adjustment, to address the MPUC Commissioners’ concerns with CMP’s customer service implementation and performance following the launch of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a period of 18 consecutive months with measurement commencing on March 1, 2020. On April 27, 2020, the MPUC issued an order requiring that CMP pay for the costs of the metering, billing and customer service practices audit, which were less than $1 million. CMP has satisfied all four of these quality measures since the measurement period commenced.

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CMP Disconnection Notices Investigation

On January 22, 2020, the MPUC initiated an investigation into certain customer notices of CMP that reference service disconnection. The purpose of this investigation is (1) to determine whether CMP provided customers notices that violated Commission rules or that contained incorrect or misleading information and, (2) if it did, to order CMP to show cause why it should not be subject to administrative penalties for those violations. CMP has responded to data requests and party testimony was filed on March 2, 2020. Hearings were suspended to allow for settlement discussions that began in March 2020. On April 27, 2020, CMP filed a proposed stipulation to resolve all issues in this proceeding and requested that the Hearing Examiner convene a settlement conference to discuss the proposed Stipulation. A settlement conference was held on April 30, 2020 and May 5, 2020. A revised Stipulation was filed with the MPUC on May 8, 2020, and was deliberated and rejected by the MPUC on June 2, 2020, due to the Office of the Public Advocate’s lack of authority to perform the tasks required by the revised Stipulation. A written order rejecting the Stipulation was issued on June 8, 2020. Following submission of an offer of proof by the customer-intervenors, comments by CMP and the Office of the Public Advocate and recommendations by the MPUC staff, the MPUC issued an Order on August 5, 2020, accepting CMP’s consent to a finding that CMP violated a MPUC rule and payment of an administrative penalty less than $1 million.

CMP Revenue Decoupling Mechanism (RDM) Investigation

On June 9, 2020, the MPUC issued a Notice of Investigation to open an investigation into the effects of the COVID-19 pandemic on customers’ electricity-usage patterns and whether CMP’s RDM should be suspended for the annual distribution rate change that is expected to occur on July 1, 2021, for electricity delivered in calendar year 2020. On June 24, 2020, the MPUC issued a procedural order setting forth initial steps in this proceeding. On July 21, 2020, CMP filed testimony presenting electricity-usage data for its two RDM classes (residential and commercial/industrial) through June 2020, along with testimony explaining the data and the reasons why the current RDM should remain in place without alteration. On August 11, 2020, a technical conference was held and CMP filed electricity-usage data on August 20, 2020. We cannot predict the outcome of this matter.

CMP Annual Compliance Filing

On March 31, 2020, CMP submitted its annual compliance filing in accordance with the Commission’s February 19, 2020 decision in Public Utilities Commission, Investigation into Rates and Revenue Requirements of Central Maine Power Company. In its filing, CMP proposed an overall increase in its distribution delivery revenues of $14.5 million, or 5.56% over current rates, effective July 1, 2020. This increase is due primarily to storm costs, RDM, which are by offset excess deferred income taxes. As a result of the COVID-19 pandemic, CMP’s filing proposed cost recovery provisions designed to minimize the rate impacts on customers including, without limitation, an extended period for recovery of storm costs incurred in 2019. On June 18, 2020, the MPUC approved a partial stipulation, which adopted CMP’s proposal to recover 2019 major storm costs over a three-year period commencing on July 1, 2020, but denied CMP’s proposed recovery of costs related to its legacy billing system, which are less than $1 million. On June 18, 2020, CMP made a compliance filing with revised tariffs, which was approved by the MPUC on June 23, 2020, and the new rates took effect on July 1, 2020.

CMP Standard Offer Uncollectible Adder Investigation

On August 19, 2020, the MPUC issued a Notice of Investigation to open an investigation into the whether the uncollectible adder to CMP’s standard offer retainage account for the residential and small non-residential standard offer customer class should be increased for standard offer electricity-supply rates that will go into effect January 1, 2022. The investigation will also include a review of CMP’s credit and collection practices. A technical conference was held on October 8, 2020. We cannot predict the outcome of this matter.

Power Tax Audits

Previously, CMP, NYSEG and RG&E implemented Power Tax software to track and measure their respective deferred tax amounts. In connection with this change, we identified historical updates needed with deferred taxes recognized by CMP, NYSEG and RG&E and increased our deferred tax liabilities, 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 $149 million and $153 million, respectively, for this item at September 30, 2020 and December 31, 2019.

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 NYPSC audit report is expected to be completed during 2020. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which indicated the auditor was unable to verify the asset “acquisition value” used to calculate the Power Tax regulatory asset. The audit report requires that CMP must provide support for the beginning balance of the regulatory assets or it will be unable to recover the value of the assets, which is approximately $11 million, excluding

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carrying costs. CMP responded to the audit report in its rate case filing by providing additional acquisition value support and, therefore, requested full recovery of the Power Tax regulatory asset. MPUC staff expressed concerns about the value CMP has attributed to this issue. The MPUC also had an outside firm conduct an audit of CMP's filing and acquisition values, and the auditor found CMP's information was reasonable. In September 2019, CMP filed a report in response to the audit report and addressed MPUC staff concerns. On December 17, 2019, CMP filed a stipulation with the MPUC providing for recovery of the Power Tax regulatory asset and adjusting the carrying costs values for the period of July 1, 2017 through June 30, 2019. The MPUC approved the stipulation on January 21, 2020 and CMP will begin collecting the Power Tax Regulatory asset beginning in July 2020 over 32.5 years.

New England Clean Energy Connect

The New England Clean Energy Connect, or NECEC, transmission project includes a 145-mile transmission line linking the electrical grids in Québec, Canada and New England. The project, which has an estimated cost of approximately $950 million, would add 1,200 MW of transmission capacity to supply New England with power from reliable hydroelectric generation. On March 13, 2020, the Federal Energy Regulatory Commission, or FERC, approved the transfer of jurisdictional facilities from CMP to NECEC Transmission LLC and the regulatory approval from the MPUC to effectuate the transfer was granted on October 20, 2020. On May 11, 2020, the Maine Department of Environmental Protection issued its final approval of the project. That approval has been appealed by certain intervenors. The appeals are currently before the Board of Environmental Protection. On July 9, 2020, ISO-NE issued its final approval. On October 27, 2020, three environmental groups filed a lawsuit against the Army Corps of Engineers in the U.S. District Court of Maine alleging that the Army Corp’s decision to prepare an environmental assessment of the NECEC transmission project instead of an environmental impact statement violates federal laws and asking the court set aside the Army Corps’ environmental assessment and prepare an environmental impact statement before issuing the permit. We cannot predict the outcome of this proceeding and its impact on the timing of the Army Corps of Engineers permit, which is expected to be issued in the fourth quarter of 2020.

In 2019, certain opponents of the NECEC began an effort to have a referendum ballot question to enact legislation (i.e., a Maine Citizens Initiative) entitled “Resolve, To Reject the New England Clean Energy Transmission Project,” which, if passed by Maine voters, would have required the MPUC to amend its May 3, 2019 "Order Granting Certificate of Public Convenience and Necessity and Approving Stipulation” and deny the certificate of public convenience and necessity for the NECEC transmission project, or the NECEC Referendum. On August 13, 2020, the Maine Supreme Judicial Court vacated the Superior Court decision, held that the NECEC Referendum is unconstitutional, and remanded the case to the Superior Court to enter a declaratory judgment. On August 21, 2020, the Superior Court issued a declaratory judgment that the NECEC Referendum fails to meet the constitutional requirements for inclusion on the ballot.

On September 16, 2020, a group of Maine voters submitted an application for a citizen referendum to enact legislation that, if enacted into law and found to be constitutional, would, among other things, require a two-thirds affirmative vote of each of the Maine state house of representatives and Maine state senate to approve high-impact transmission line construction and the lease by the Bureau of Parks and Lands of public reserved lands for transmission lines and similar linear projects. Proponents of the citizen initiative will need to gather the constitutionally required number of signatures before the initiative can be considered for placement on the ballot. We cannot predict the outcome of this citizen initiative.

We will start construction following the issuance of the Army Corps of Engineers permit and the transfer of the project from CMP to NECEC Transmission LLC, which is expected in the fourth quarter of 2020.

Maine Government-Run Power Referendum

On September 18, 2020, a request was submitted to the Maine Secretary of State to initiate the process of placing a government-run power referendum on the November 2021 ballot. We cannot predict the outcome of this request or any potential referendum.

PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation

On August 6, 2020, the PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. We cannot predict the outcome of this investigation. Public statement hearings were held on October 21 – 23, 2020.

On October 7, 2020, the Governor of Connecticut signed into law an energy bill that, among other things, instructs PURA to revise the rate-making structure in Connecticut to adopt performance-based rates for each electric distribution company, increases the maximum civil penalties assessable for failures in emergency preparedness, and provides certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.

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NYDPS Investigation of the Preparation for and Response to the Tropical Storm Isaias

In August 2020, following Tropical Storm Isaias, the NYDPS commenced a comprehensive investigation of the preparation and response this event by New York's major electric utility companies. In addition, on August 20, 2020, the New York State Senate and Assembly held a joint hearing to examine the response of various utility companies during the aftermath of Tropical Storm Isaias. We cannot predict the outcome of this investigation or any potential legislative action.

Results of Operations

The following tables set forth financial information by segment for each of the periods indicated:

	Three Months Ended								Three Months Ended
	September 30, 2020								September 30, 2019
	Total		Networks		Renewables		Other(1)		Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	1,470	$	1,197	$	276	$	(3)	$	1,487	$	1,140	$	347	$	—
Operating Expenses
Purchased power, natural gas and fuel used	259		218		41		—		279		209		70		—
Operations and maintenance	634		527		107		—		588		482		111		(5)
Depreciation and amortization	255		151		104		—		237		138		98		1
Taxes other than income taxes	157		141		17		(1)		144		129		15		—
Total Operating Expenses	1,305		1,037		269		(1)		1,248		958		294		(4)
Operating Income	165		160		7		(2)		239		182		53		4
Other Income (Expense)
Other income (expense)	16		14		5		(3)		6		(3)		15		(6)
Earnings (losses) from equity method investments	1		3		(2)		—		(1)		3		(4)		—
Interest expense, net of capitalization	(86)		(63)		1		(24)		(72)		(66)		1		(7)
Income (Loss) Before Income Tax	96		114		11		(29)		172		116		65		(9)
Income tax (benefit) expense	15		20		(7)		2		33		28		2		3
Net Income (Loss)	81		94		18		(31)		139		88		63		(12)
Net loss (income) attributable to noncontrolling interests	6		(1)		7		—		11		—		11		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	87	$	93	$	25	$	(31)	$	150	$	88	$	74	$	(12)

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	Nine Months Ended								Nine Months Ended
	September 30, 2020								September 30, 2019
	Total		Networks		Renewables		Other(1)		Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	4,651	$	3,779	$	876	$	(4)	$	4,729	$	3,837	$	896	$	(4)
Operating Expenses
Purchased power, natural gas and fuel used	999		819		180		—		1,101		932		169		—
Operations and maintenance	1,788		1,479		318		(9)		1,714		1,428		295		(9)
Depreciation and amortization	748		446		301		1		681		407		273		1
Taxes other than income taxes	469		418		53		(2)		446		402		44		—
Total Operating Expenses	4,004		3,162		852		(10)		3,942		3,169		781		(8)
Operating Income	647		617		24		6		787		668		115		4
Other Income (Expense)
Other (expense) income	15		14		10		(9)		1		(3)		17		(13)
(Losses) earnings from equity method investments	(3)		8		(11)		—		1		8		(7)		—
Interest expense, net of capitalization	(251)		(199)		1		(53)		(226)		(201)		(6)		(19)
Income (Loss) Before Income Tax	408		440		24		(56)		563		472		119		(28)
Income tax expense (benefit)	21		75		(53)		(1)		103		117		(15)		1
Net Income (Loss)	387		365		77		(55)		460		355		134		(29)
Net loss (income) attributable to noncontrolling interests	28		(2)		30		—		17		(1)		18		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	415	$	363	$	107	$	(55)	$	477	$	354	$	152	$	(29)

(1)"Other" represents Corporate and intersegment eliminations.

Comparison of Period to Period Results of Operations

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

Operating Revenues

Our operating revenues decreased by $17 million, or 1%, from $1,487 million for the three months ended September 30, 2019 to $1,470 million for the three months ended September 30, 2020, as detailed by segment below:

Networks

Operating revenues increased by $57 million, or 5%, from $1,140 million for the three months ended September 30, 2019 to $1,197 million for the three months ended September 30, 2020. Electricity and gas revenues increased by $8 million, primarily due to the impact of increased customer rates in the three months ended September 30, 2020 compared to the same period of 2019, increased by $9 million from unfavorable earnings sharing and other regulatory deferrals recorded in the third quarter of 2019. These were offset by unfavorable $4 million recorded in the third quarter of 2020 due to an electric reliability revenue adjustment and $5 million of unfavorable other. Electricity and gas revenues changed due to the following items that have offsets within the income statement: an increase of $9 million in purchased power and purchased gas (offset in purchased power) and an increase of $40 million in flow through amortizations ($33 million of which are offset in operating expenses and $7 million in taxes other than income taxes).

Renewables

Operating revenues decreased by $71 million, or 20%, from $347 million for the three months ended September 30, 2019 to $276 million for the three months ended September 30, 2020. The decrease in operating revenues was primarily due to unfavorable mark to market, or MtM, changes of $88 million on energy derivative transactions entered for economic hedging purposes and a decrease of $3 million driven by lower wind generation output of 49 GWh in the current period, and a $4 million decrease in other revenues, offset by an $18 million increase due to a combination of higher market prices, RECs and curtailment revenues and a $6 million increase in thermal revenue driven by higher average prices in the period.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used decreased by $20 million, or 7%, from $279 million for the three months ended September 30, 2019 to $259 million for the three months ended September 30, 2020, as detailed by segment below:

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Networks

Purchased power, natural gas and fuel used increased by $9 million, or 4%, from $209 million for the three months ended September 30, 2019 to $218 million for the three months ended September 30, 2020. The increase is primarily driven by an $8 million increase in average commodity prices and an overall increase in electricity units procured due to an increase in degree days along with a $1 million increase in other power supply purchases driven primarily by new purchase agreements in the period.

Renewables

Purchased power, natural gas and fuel used decreased by $29 million, or 41%, from $70 million for the three months ended September 30, 2019 to $41 million for the three months ended September 30, 2020. The decrease is primarily driven by favorable MtM changes on derivatives of $39 million due to market price changes in the period and a decrease of $5 million in thermal purchases driven by the decrease in volume and unit cost in the period, offset by an increase of $15 million in power purchases in the current period.

Operations and Maintenance

Operations and maintenance expenses increased by $46 million, or 8%, from $588 million for the three months ended September 30, 2019 to $634 million for the three months ended September 30, 2020, as detailed by segment below:

Networks

Operations and maintenance expenses increased by $45 million, or 9%, from $482 million for the three months ended September 30, 2019 to $527 million for the three months ended September 30, 2020. The increase is driven by $11 million in outage restoration costs, a $1 million increase in uncollectible expenses, a $2 million increase due to additional cleaning and personal protective equipment resulting from COVID-19, and an increase of $38 million in flow through amortizations (which are offset in operating revenue). These were offset by $5 million of favorable overhead and $2 million of favorable other.

Renewables

Operations and maintenance expenses decreased by $4 million, or 4%, from $111 million for the three months ended September 30, 2019 to $107 million for the three months ended September 30, 2020. The decrease is primarily due to $12 million of lower maintenance costs driven by reduced production and curtailments, offset by an $8 million increase driven by higher personnel costs primarily attributable to new capacity.

Depreciation and Amortization

Depreciation and amortization for the three months ended September 30, 2020 was $255 million compared to $237 million for the three months ended September 30, 2019, representing an increase of $18 million. The increase is primarily due to an increase of $21 million in depreciation expense from plant additions in Networks and Renewables in the period, offset by a $2 million decrease of accelerated depreciation from the repowering of wind farms in Renewables and $1 million of other.

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

Other income (expense) and equity earnings (losses) increased by $12 million from $5 million for the three months ended September 30, 2019 to $17 million for the three months ended September 30, 2020. The increase is primarily due to $9 million favorable change in allowance for funds used during construction, $2 million favorable equity earnings and a $5 million increase due to a settlement gain, offset by a $5 million gain for the sale of assets recorded in the same period of 2019.

Interest Expense, Net of Capitalization

Interest expense for the three months ended September 30, 2020 and 2019 was $86 million and $72 million, respectively. The increase was due to an increase of $13 million of interest expense primarily from new debt issued in 2020 and 2019 within Other.

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended September 30, 2020, was 15.6%, which is lower than the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act. The effective tax rate, inclusive of federal and state income tax, for the three months ended September 30, 2019 was 19.2%, which is higher than the federal statutory tax rate of 21% primarily due to unfavorable discrete income tax adjustments recorded in the period, partially offset by production tax credits associated with wind production.

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Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Operating Revenues

Our operating revenues decreased by $78 million, or 2%, from $4,729 million for the nine months ended September 30, 2019 to $4,651 million for the nine months ended September 30, 2020, as detailed by segment below:

Networks

Operating revenues decreased by $58 million, or 2%, from $3,837 million for the nine months ended September 30, 2019 to $3,779 million for the nine months ended September 30, 2020. Electricity and gas revenues increased by $19 million, primarily due to the impact of increased customer rates in the nine months ended September 30, 2020 compared to the same period of 2019, and increased by $16 million from unfavorable earnings sharing, net plant reconciliation and other regulatory deferrals incurred in 2019, which were not incurred in 2020. These were offset by a decrease of $10 million from a pension deferral write-off, $7 million decrease due to an electric reliability revenue adjustment, $8 million decrease from the inability to charge late payment fees due to regulatory orders, and a decrease of $1 million due to other. Electricity and gas revenues changed due to the following items that have offsets within the income statement: a decrease of $113 million in purchased power and purchased gas (offset in purchased power) offset by an increase of $46 million in flow through amortizations ($39 million of which are offset in operating expenses and $7 million in taxes other than income taxes).

Renewables

Operating revenues decreased by $20 million, or 2%, from $896 million for the nine months ended September 30, 2019, to $876 million for the nine months ended September 30, 2020. The decrease in operating revenues was primarily due to unfavorable MtM changes of $66 million on energy derivative transactions entered for economic hedging purposes, a decrease of $5 million in merchant pricing, a $30 million decrease in thermal revenue driven by lower volumes and average prices in the period, and a $11 million decrease in other revenues (offset in operating expenses). These were offset by an increase of $92 million driven by wind generation output increase of 1,722 GWh from existing and new capacity in the current period.

Purchased Power, Natural Gas and Fuel Used

Our purchased power, natural gas and fuel used decreased by $102 million, or 9%, from $1,101 million for the nine months ended September 30, 2019 to $999 million for the nine months ended September 30, 2020, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used decreased by $113 million, or 12%, from $932 million for the nine months ended September 30, 2019 to $819 million for the nine months ended September 30, 2020. The decrease is primarily driven by a $109 million decrease in average commodity prices and an overall decrease in electricity and gas units procured due to a decline in degree days along with a $4 million increase in other power supply purchases in the period.

Renewables

Purchased power, natural gas and fuel used increased by $11 million, or 7%, from $169 million for the nine months ended September 30, 2019 to $180 million for the nine months ended September 30, 2020. The increase is primarily driven by an increase of $37 million in power purchases, $5 million in RECs, offset by unfavorable MtM changes on derivatives of $10 million due to market price changes in the period and a decrease of $21 million in thermal purchases driven by the decrease in volume and unit cost in the period.

Operations and Maintenance

Our operations and maintenance expenses increased by $74 million, or 4%, from $1,714 million for the nine months ended September 30, 2019 to $1,788 million for the nine months ended September 30, 2020, as detailed by segment below:

Networks

Operations and maintenance expenses increased by $51 million, or 4%, from $1,428 million for the nine months ended September 30, 2019 to $1,479 million for the nine months ended September 30, 2020. The increase is driven by $12 million in outage restoration costs, a $6 million increase in uncollectible expenses, a $5 million increase due to additional cleaning and personal protective equipment resulting from COVID-19, an increase of $41 million in flow through amortizations (which is offset in revenue) and a $3 million increase in other. These were offset by a decrease of $5 million in unfavorable write-off of deferred storm costs in the nine months ended September 30, 2019, which did not recur in 2020, $6 million decrease in medical expenses, and $5 million of favorable overhead.

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Renewables

Operations and maintenance expenses increased by $23 million, or 8%, from $295 million for the nine months ended September 30, 2019 to $318 million for the nine months ended September 30, 2020. The increase is primarily due to $27 million of increased costs resulting from higher personnel and maintenance costs, which are primarily attributed to operations of new capacity. Additionally, operations and maintenance expense increased by $10 million driven by an asset retirement obligation adjustment in the same period of 2019, offset by $3 million decrease due to a favorable provision release in the nine months ended September 30, 2020, and $11 million in other expenses (offset in operating revenues).

Depreciation and Amortization

Depreciation and amortization for the nine months ended September 30, 2020 was $748 million compared to $681 million for the nine months ended September 30, 2019, an increase of $67 million. The increase is driven by $63 million from plant additions in Networks and Renewables in the period, an increase of lease amortizations of $3 million, $4 million increase due to an asset retirement obligation true up for the period ended September 30, 2019, which did not recur in 2020, and $2 million of other, offset by a $5 million decrease of accelerated depreciation from the repowering of wind farms in Renewables.

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

Other income (expense) and equity earnings (losses) increased by $10 million from $2 million for the nine months ended September 30, 2019 to $12 million for the nine months ended September 30, 2020. The change is primarily due to $17 million favorable change in allowance for funds used during construction in Networks and a $5 million increase due to a settlement gain, offset by $5 million gain for the sale of assets recorded in the same period of 2019, and $4 million of unfavorable equity earnings in the period.

Interest Expense, Net of Capitalization

Interest expense for the nine months ended September 30, 2020 and 2019 was $251 million and $226 million, respectively. The increase was due to an increase of $26 million of interest expense primarily from new debt issued in 2020 and 2019 within Other.

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the nine months ended September 30, 2020 was 5.1%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act. The effective tax rate, inclusive of federal and state income tax, for the nine months ended September 30, 2019 was 18.3%, which is below the federal statutory tax rate of 21% primarily due to the recognition of production tax credits associated with wind production.

Non-GAAP Financial Measures

To supplement our consolidated financial statements presented in accordance with U.S. GAAP, we consider 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 earnings from 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, accelerated depreciation derived from repowering of wind farms and costs incurred in connection with the COVID-19 pandemic. 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

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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.

The following tables provide a reconciliation between Net Income attributable to AVANGRID and Adjusted Net Income (non-GAAP) by segment for the three and nine months ended September 30, 2020 and 2019, respectively:

	Three Months Ended September 30, 2020								Nine Months Ended September 30, 2020
	Total		Networks		Renewables		Corporate*		Total		Networks		Renewables		Corporate*
	(in millions)								(in millions)
Net Income Attributable to Avangrid, Inc.	$	87	$	94	$	25	$	(31)	$	415	$	363	$	107	$	(55)
Adjustments:
Mark-to-market earnings - Renewables	7		—		7		—		(9)		—		(9)		—
Restructuring charges	1		1		—		—		5		3		1		—
Accelerated depreciation from repowering	3		—		3		—		9		—		9		—
Impact of COVID-19	8		7		1		—		21		18		1		2
Income tax impact of adjustments (1)	(5)		(2)		(3)		—		(7)		(6)		—		(1)
Adjusted Net Income (2)	$	100	$	99	$	32	$	(31)	$	434	$	379	$	108	$	(53)

	Three Months Ended September 30, 2019								Nine Months Ended September 30, 2019
	Total		Networks		Renewables		Corporate*		Total		Networks		Renewables		Corporate*
	(in millions)								(in millions)
Net Income Attributable to Avangrid, Inc.	$	150	$	88	$	74	$	(12)	$	477	$	354	$	152	$	(29)
Adjustments:
Mark-to-market earnings - Renewables	(42)		—		(42)		—		(66)		—		(66)		—
Restructuring charges	2		2		—		—		4		2		—		2
Accelerated depreciation from repowering	5		—		5		—		15		—		15		—
Income tax impact of adjustments (1)	9		—		10		—		12		(1)		13		—
Adjusted Net Income (2)	$	123	$	89	$	46	$	(12)	$	442	$	355	$	115	$	(28)

(1)Income tax impact of adjustments: 2020 - $(2) million and $2 million from MtM earnings, $0 and $(1) million from restructuring charges, and $(1) million and $(3) million from accelerated depreciation from repowering, $(2) million and $(5) million from impact of COVID-19 for the three and nine months ended September 30, 2020, respectively; 2019 - $11 million and $17 million from MtM earnings, $0 and $(1) from restructuring charges and $(2) million and $(4) million from accelerated depreciation from repowering for the three and nine months ended September 30, 2019, respectively.

(2)Adjusted Net Income is a non-GAAP financial measure and is presented after excluding restructuring charges, accelerated depreciation derived from repowering of wind farms, costs incurred in connection with the COVID-19 pandemic and the impact from mark-to-market activities in Renewables.

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

Three Months Ended September 30, 2020 Compared to Three Months Ended September 30, 2019

Adjusted net income

Our adjusted net income decreased by $23 million, or 18%, from $123 million for the three months ended September 30, 2019 to $100 million for the three months ended September 30, 2020. The decrease is primarily due to a $14 million decrease in Renewables driven by decrease in existing production, unfavorable results from decreased pricing and higher depreciation, a $15 million decrease in Corporate mainly driven by higher interest expenses, offset by a $10 million increase in Networks driven primarily by customer rate increases in the period and favorable tax benefits.

Nine Months Ended September 30, 2020 Compared to Nine Months Ended September 30, 2019

Adjusted net income

Our adjusted net income decreased by $8 million, or 2%, from $442 million for the nine months ended September 30, 2019 to $434 million for the nine months ended September 30, 2020. The decrease is primarily due to $7 million decrease in Renewables as a result of unfavorable results from decreased pricing, higher personnel and maintenance costs in the period driven by new capacity, $25 million decrease in Corporate mainly driven by higher interest expenses in the period, offset by $24 million increase in Networks driven primarily by customer rate increases 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 and nine months ended September 30, 2020 and 2019, respectively:

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
(in millions)	2020		2019		2020		2019
Networks	$	94	$	88	$	363	$	354
Renewables	25		74		107		152
Corporate (1)	(31)		(12)		(55)		(29)
Net Income	$	87	$	150	$	415	$	477
Adjustments:
Mark-to-market earnings - Renewables (2)	7		(42)		(9)		(66)
Restructuring charges (3)	1		2		5		4
Accelerated depreciation from repowering (4)	3		5		9		15
Impact of COVID-19 (5)	8		—		21		—
Income tax impact of adjustments	(5)		9		(7)		12
Adjusted Net Income (6)	$	100	$	123	$	434	$	442

	Three Months Ended				Nine Months Ended
	September 30,				September 30,
	2020		2019		2020		2019
Networks	$	0.30	$	0.28	$	1.17	$	1.14
Renewables	0.08		0.24		0.35		0.49
Corporate (1)	(0.10)		(0.04)		(0.18)		(0.09)
Net Income	$	0.28	$	0.48	$	1.34	$	1.54
Adjustments:
Mark-to-market earnings - Renewables (2)	0.02		(0.14)		(0.03)		(0.21)
Restructuring charges (3)	—		0.01		0.02		0.01
Accelerated depreciation from repowering (4)	0.01		0.02		0.03		0.05
Impact of COVID-19 (5)	0.02		—		0.07		—
Income tax impact of adjustments	(0.02)		0.03		(0.02)		0.04
Adjusted Earnings Per Share (6)	$	0.32	$	0.40	$	1.40	$	1.43

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

(2)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.

(3)Restructuring and severance related charges relate to costs to implement an initiative to mitigate costs and achieve sustainable growth.

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

(5)Represents costs incurred in connection with the COVID-19 pandemic.

(6)Adjusted net income and adjusted earnings per share are non-GAAP financial measures and are presented after excluding restructuring charges, accelerated depreciation derived from repowering of wind farms, costs incurred in connection with the COVID-19 pandemic and the impact from mark-to-market activities in Renewables.

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.

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 September 30, 2020.

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Liquidity Position

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 was $0 and $150 million as of September 30, 2020 and December 31, 2019, respectively. Any deposit amounts are reflected on 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 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, $500 million from the lenders committed to the 2020 Credit Facility and $500 million from an Iberdrola Group Credit Facility, each of which are described below.

The following table provides the components of our liquidity position as of September 30, 2020 and December 31, 2019, respectively:

	As of September 30,		As of December 31,
	2020		2019
	(in millions)
Cash and cash equivalents	$	101	$	178
AVANGRID Credit Facility	2,500		2,500
2020 Credit Facility	500		—
Iberdrola Group Credit Facility	500		500
Less: borrowings	(999)		(562)
Total	$	2,602	$	2,616

AVANGRID Commercial Paper Program

AVANGRID has a commercial paper program with a limit of $2 billion that is backstopped by the AVANGRID Credit Facility and the 2020 Credit Facility (described below). As of September 30, 2020 and October 29, 2020, there was $999 million and $1,758 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. On June 29, 2020, we entered into an amendment to the AVANGRID Credit Facility, which reduced AVANGRID's maximum sublimit from $2.0 billion to $1.5 billion and added minimum sublimits for each joint borrower other than AVANGRID. Under the AVANGRID Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. As of September 30, 2020, the facility fees ranged from 10.0 to 17.5 basis points. The AVANGRID Credit Facility matures on June 29, 2024. As of both September 30, 2020 and October 29, 2020, we had no borrowings outstanding under this credit facility.

2020 Credit Facility

On June 29, 2020, we entered into a revolving credit agreement with several lenders, or the 2020 Credit Facility, that provides maximum borrowings up to $500 million. We will pay an annual facility fee, which ranges from 15 to 30 basis points, dependent on AVANGRID’s credit rating. As of September 30, 2020, the facility fee is 20 basis points. The 2020 Credit Facility matures on June 28, 2021. We have the right to extend, and the banks are obligated to extend, the commitments and loans outstanding under the facility for one year at a cost of 75 basis points. We may also request an extension of the facility for

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one year, which the banks may grant at their discretion for a fee that will be determined at the time of the request. As of both September 30, 2020 and October 29, 2020, we had no borrowings outstanding under this credit facility.

Since our credit facilities are also a backstop to the AVANGRID commercial paper program, the total amounts available under the facilities as of September 30, 2020 and October 29, 2020, were $2,001 million and $1,242 million, respectively.

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. As of both September 30, 2020 and October 29, 2020, we had no borrowings outstanding under this credit facility.

Capital Resources

On April 9, 2020, AGR issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%.

On May 1, 2020, NYSEG remarketed $200 million aggregate Pollution Control bonds with maturity dates ranging from 2026 to 2029 at fixed interest rates of 1.40% to 1.61%. The remarketing was a non-cash transaction to reset the interest rates.

On September 1, 2020, BGC issued $25 million aggregate principal amount of unsecured notes maturing in 2050 at a fixed interest rate of 3.68%.

On September 25, 2020, NYSEG issued $200 million aggregate principal amount of unsecured notes maturing in 2030 at a fixed interest rate of 1.95%.

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 revolving credit facilities, as described above, to fund short-term liquidity needs and we believe that we will continue to have access to the capital markets as long-term growth capital is needed. To date, the Company has not experienced limitations in our ability to access these sources of liquidity in connection with the economic recession triggered by the COVID-19 pandemic. While taking into consideration the current economic environment, management expects that we will continue to have sufficient liquidity and financial flexibility to meet our business requirements.

We expect to incur approximately $717 million in capital expenditures through the remainder of 2020.

Cash Flows

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

The following is a summary of the cash flows by activity for the nine months ended September 30, 2020 and 2019, respectively:

	Nine Months Ended
	September 30,
	2020		2019
	(in millions)
Net cash provided by operating activities	$	1,092	$	1,244
Net cash used in investing activities	(1,956)		(2,156)
Net cash provided by financing activities	786		977
Net (decrease) increase in cash, cash equivalents and restricted cash	$	(78)	$	65

Operating Activities

The cash from operating activities for the nine months ended September 30, 2020 compared to the nine months ended September 30, 2019 decreased by $152 million, primarily attributable to higher operations and maintenance expenses in the period.

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Investing Activities

For the nine months ended September 30, 2020, net cash used in investing activities was $1,956 million, which was comprised of $1,960 million of capital expenditures and $48 million of other investments and equity method investments, partially offset by $35 million of contributions in aid of construction and $12 million of proceeds from the sale of assets.

For the nine months ended September 30, 2019, net cash used in investing activities was $2,156 million, which was comprised of $2,045 million of capital expenditures and $164 million of other investments and equity method investments, partially offset by $36 million of contributions in aid of construction and $13 million of proceeds from the sale of assets.

Financing Activities

For the nine months ended September 30, 2020, financing activities provided $786 million in cash reflecting primarily a contribution from non-controlling interests of $312 million and a net increase in non-current debt and current notes payable of $897 million, offset by distributions to non-controlling interests of $5 million, payments on finance leases of $7 million and dividends of $408 million.

For the nine months ended September 30, 2019, financing activities provided $977 million in cash reflecting primarily an issuance of notes/bonds with net proceeds of $1,637 million, contributions from non-controlling interests of $133 million and a net decrease in non-current debt and current notes payable of $312 million, offset by distributions to non-controlling interests of $47 million, payments on finance leases of $26 million and dividends of $408 million.

Off-Balance Sheet Arrangements

There have been no material changes in our off-balance sheet arrangements during the nine months ended September 30, 2020 as compared to those reported for the fiscal year ended December 31, 2019 in our Form 10-K.

Contractual Obligations

There have been no material changes in contractual and contingent obligations during the nine months ended September 30, 2020 as compared to those reported for the fiscal year ended December 31, 2019 in our Form 10-K.

In 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project. Pursuant to a joint bidding agreement between Renewables and CIP, CIP held a right to sell all or a portion of its 50% ownership interest to Renewables, subject to certain conditions, however this right expired on September 30, 2020. In October 2020, Vineyard Wind submitted an offshore wind solicitation to NYSERDA to provide 1,200 to 1,300 MW of offshore wind through the development of its Liberty Wind Project. In October 2020, Renewables and CIP entered into an agreement pursuant to which, subject to the satisfaction of certain conditions, CIP may exercise an option to effectuate a series of transactions that include the sale of its ownership interest in the Liberty Wind and Park City Wind Projects to Renewables and the purchase of Renewables’ residual ownership interest in certain lease areas that have not been awarded an offtake agreement as of the date of the exercise of such option by CIP.

Critical Accounting Policies and Estimates

The accompanying condensed consolidated financial statements provided herein have been prepared in accordance with U.S. GAAP. In preparing the accompanying condensed consolidated 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. 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 September 30, 2020, we continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from COVID-19 has made such estimates and assumptions more difficult to assess and calculate. Impacted estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While there were no material impacts from COVID-19 on financial results, actual results could differ from those estimates, which could result in material impacts to our consolidated financial statements in future reporting periods. The other notable changes to the significant accounting policies described in our Form 10-K for the fiscal year ending December 31, 2019, are with respect to our adoption of the new accounting pronouncements described in the Note 3 of our condensed consolidated financial statements for the nine months ended September 30, 2020 .

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. The new accounting pronouncements that we have adopted as of January 1, 2020, and reflected in our condensed consolidated financial statements are described in Note 3 of our condensed consolidated financial statements for the nine months ended September 30, 2020. There have been no other material changes to the significant accounting policies

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described in our Form 10-K for the fiscal year ended December 31, 2019, except for those described in Note 3 resulting from the adoption of new authoritative accounting guidance issued by FASB.

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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, civil or social unrest, natural disasters or pandemic health events or other similar occurrences;

•the impact of any change to applicable laws and regulations affecting operations, including those relating to the environment 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 nine months ended September 30, 2020, as compared to those reported for the fiscal year ended December 31, 2019 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

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objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints and that management is required to apply judgment in evaluating the benefits of possible controls and procedures relative to their costs.

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PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please read “Note 8—Contingencies” and “Note 9—Environmental 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, 2019, as updated in our Quarterly Report on Form 10-Q for the quarterly period ended June 30, 2020, filed with the SEC on July 31, 2020. The only significant changes to our risk factors relate to the Merger.

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

Completion of the proposed Merger is subject to the satisfaction or waiver of a number of conditions as set forth in the Merger Agreement, including regulatory and PNMR shareholder approvals and other customary closing conditions. There can be no assurance that the conditions to completion of the proposed Merger will be satisfied or waived or that other events will not intervene to delay or result in the failure to close the proposed Merger. In addition, each of AVANGRID and PNMR may unilaterally terminate the Merger Agreement under certain circumstances set forth in the Merger Agreement, and AVANGRID and PNMR may agree at any time to terminate the Merger Agreement, even if PMNR shareholders have already approved the Merger Agreement and thereby approved the proposed Merger and the other transactions contemplated by the Merger Agreement.

AVANGRID and PMNR may be unable to obtain the regulatory approvals required to complete the proposed Merger.

In addition to other conditions set forth in the Merger Agreement, completion of the proposed Merger is conditioned upon the receipt of various state and U.S. federal regulatory approvals including, but not limited to, approval by the Public Utility Commission of Texas, or PUCT, the New Mexico Public Regulation Commission, or NMPRC, the FERC, the Federal Communications Commission, or FCC, the Committee on Foreign Investment in the United States, or CFIUS, the Nuclear Regulatory Commission, or NRC, and under the Hart-Scott-Rodino Antitrust Improvements Act of 1976. AVANGRID and PMNR will make various filings and submissions and are pursuing all required consents, orders and approvals in accordance with the Merger Agreement. These consents, orders and approvals may impose conditions on or require divestitures relating to the divisions, operations or assets of AVANGRID and PNMR or may impose requirements, limitations or costs or place restrictions on the conduct of the combined company’s business, and if such consents, orders and approvals require an extended period of time to be obtained, such extended period of time could increase the chance that an event occurs that constitutes a material adverse effect with respect to PMNR and thereby may allow AVANGRID an opportunity not to consummate the proposed Merger. Such extended period of time also may increase the chance that other adverse effects with respect to AVANGRID or PMNR could occur, such as the loss of key personnel.

The Merger Agreement requires AVANGRID and PNMR, among other things, to accept conditions, divestitures, requirements, limitations, costs or restrictions that may be imposed by regulatory entities, subject to the burdensome effect provisions in the Merger Agreement. Such conditions, divestitures, requirements, limitations, costs or restrictions may jeopardize or delay consummation of the proposed Merger, may reduce the benefits that may be achieved from the proposed Merger or may result in the abandonment of the proposed Merger. Further, no assurance can be given that the required consents, orders and approvals will be obtained or that the required conditions to closing will be satisfied, and, even if all such consents, orders and approvals are obtained and such conditions are satisfied, no assurance can be given as to the terms, conditions and timing of such consents, orders and approvals.

The announcement and pendency of the proposed Merger could have an adverse effect on AVANGRID’s businesses, results of operations, financial condition, cash flows or the market value of AVANGRID’s common stock and debt securities.

The announcement and pendency of the proposed Merger could disrupt AVANGRID’s businesses, and uncertainty about the effect of the proposed Merger may have an adverse effect on AVANGRID or the combined company following the proposed Merger. AVANGRID’s employees may experience uncertainty regarding their roles after the proposed Merger, for example, employees may depart either before or after the completion of the proposed Merger because of such uncertainty and issues relating to the difficulty of coordination or a desire not to remain following the proposed Merger; and the pendency of the proposed Merger may adversely affect AVANGRID’s ability to retain, recruit and motivate key personnel. Additionally, the attention of AVANGRID’s management may be directed towards the completion of the proposed Merger including obtaining regulatory approvals and other transaction-related considerations and may be diverted from the day-to-day business operations

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of AVANGRID and matters related to the proposed Merger may require commitments of time and resources that could otherwise have been devoted to other opportunities that might have been beneficial to AVANGRID. Additionally, the Merger Agreement requires AVANGRID to obtain PNMR’s consent prior to taking certain specified actions while the proposed Merger is pending. These restrictions may prevent AVANGRID and PNMR from pursuing otherwise attractive business opportunities and executing certain of its business strategies prior to the consummation of the proposed Merger. Further, the proposed Merger may give rise to potential liabilities, including as a result of pending and future shareholder lawsuits relating to the proposed Merger. Any of these matters could adversely affect the businesses of, or harm the results of operations, financial condition or cash flows of AVANGRID and the market value of AVANGRID common stock and debt securities.

AVANGRID will incur substantial transaction fees and costs in connection with the proposed Merger.

AVANGRID has incurred and expects to incur additional material non-recurring expenses in connection with the proposed Merger and consummation of the transactions contemplated by the Merger Agreement. Additional unanticipated costs may be incurred in the course of coordinating the businesses of AVANGRID and PNMR after consummation of the proposed Merger. Further, even if the proposed Merger is not consummated, AVANGRID may need to pay certain pre-tax costs relating to the proposed Merger incurred prior to the date the proposed Merger was abandoned, such as legal, accounting, financial advisory and filing fees. Additionally, if the proposed Merger is not consummated within the expected timeframe, such delay may materially adversely affect the benefits that AVANGRID may achieve as a result of the proposed Merger and could result in additional pre-tax transaction costs, loss of revenue or other effects associated with uncertainty about the proposed Merger. Satisfying the conditions to, and consummation of, the proposed Merger may take longer than, and could cost more than, AVANGRID expects.

AVANGRID may be unable to integrate PNMR successfully, and AVANGRID may not experience the growth being sought from the proposed Merger.

AVANGRID and PNMR have operated and, until the consummation of the proposed Merger will continue to operate, independently. Coordinating certain aspects of the operations and personnel of PNMR with AVANGRID after the consummation of the proposed Merger will involve complex operational, technological and personnel-related challenges. This process will be time-consuming and expensive, may disrupt the businesses of either or both of the companies and may reduce the growth opportunities sought from the Merger. The potential difficulties, and resulting costs and delays, include examples such as:

•managing a larger combined company;

•coordinating corporate and administrative infrastructures;

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

•difficulty addressing possible differences in corporate cultures and management philosophies;

•unforeseen and unexpected liabilities related to the proposed Merger or PNMR’s business; and

•a deterioration of credit ratings.

Further, while AVANGRID can refuse to consummate the proposed Merger if there is a material adverse effect (as defined in the Merger Agreement) affecting PNMR prior to the consummation of the proposed Merger, certain types of changes do not permit AVANGRID to refuse to consummate the proposed Merger, even if such changes would have a material adverse effect on PNMR. If adverse changes occur but AVANGRID must still consummate the proposed Merger, the market price of AVANGRID common stock may suffer. There can be no assurance that, if the proposed Merger is not consummated, these risks will not materialize and will not materially adversely affect the business and financial results of AVANGRID.

AVANGRID may be materially adversely affected by negative publicity related to the proposed Merger and in connection with other matters.

From time to time, political and public sentiment in connection with the proposed Merger and in connection with other matters may result in a significant amount of adverse press coverage and other adverse public statements affecting AVANGRID. Adverse press coverage and other adverse statements, whether or not driven by political or public sentiment, may also result in investigations by regulators, legislators and law enforcement officials or in legal claims. Responding to these investigations and lawsuits, regardless of the ultimate outcome of the proceeding, can divert the time and effort of senior management from the management of AVANGRID’s businesses. Addressing any adverse publicity, governmental scrutiny or enforcement or other legal proceedings is time consuming and expensive and, regardless of the factual basis for the assertions being made, can have a negative impact on the reputation of AVANGRID, on the morale and performance of its employees and on its relationship with regulators. It may also have a negative impact on AVANGRID’s ability to take timely advantage of various business and market opportunities. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on AVANGRID’s business, financial condition, results of operations and cash flows and the market value of AVANGRID common stock and debt securities.

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Failure by PNMR to successfully execute its business strategy and objectives may materially adversely affect the future results of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

The success of the Merger will depend, in part, on the ability of PNMR to successfully execute its business strategy, including delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to maintain its system, serve its growing customer base with a modernized grid and support energy production. These objectives are capital intensive. If PNMR is not able to achieve these objectives, is not able to achieve these objectives on a timely basis, or otherwise fails to perform in accordance with AVANGRID’s expectations, the anticipated benefits of the Merger may not be realized fully or at all, and the Merger may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID common stock and debt securities.

The market value of AVANGRID common stock could decline if its existing shareholders sell large amounts of its common stock in anticipation of or following the Merger, and the market prices of AVANGRID common stock and debt securities may be affected by factors following the Merger that are different from those affecting the market prices for AVANGRID’s common stock and debt securities prior to the Merger.

Current shareholders of AVANGRID may not wish to continue to invest in the combined company, or may wish to reduce their investment in the combined company, for a number of reasons, which may include loss of confidence in the ability of the combined company to execute its business strategies, to comply with institutional investing guidelines or to increase diversification. If, before or following the Merger, large amounts of AVANGRID common stock are sold, the market price of its common stock could decline. If the Merger is consummated, the risks associated with the combined company may affect the results of operations of the combined company and the market prices of AVANGRID common stock and debt securities following the Merger differently than they affected such results of operations and market prices prior to the Merger. Additionally, the results of operations of the combined company may be affected by additional or different risks than those that currently affect the results of operations of AVANGRID. Any of the foregoing matters could materially adversely affect the market prices of AVANGRID common stock and debt securities following the Merger.

The Merger may not positively affect AVANGRID’s results of operations and/or may cause a decrease in its earnings per share, which may negatively affect the market price of AVANGRID common stock and debt securities.

AVANGRID anticipates that the Merger, if consummated on the terms, will have a positive impact on its consolidated results of operations. This expectation is based on current market conditions and is subject to a number of assumptions, estimates, projections and other uncertainties, including assumptions regarding the results of operations of the combined company after the Merger, and the financing necessary to fund the Merger Consideration. This expectation also assumes that PNMR will perform in accordance with AVANGRID’s expectations, and there can be no assurance that this will occur. In addition, AVANGRID may encounter additional transaction costs and costs to manage its investment in PNMR, may fail to realize some or any of the benefits anticipated in the Merger, may be subject to currently unknown liabilities as a result of the Merger, or may be subject to other factors that affect preliminary estimates. As a result, there can be no assurance that the Merger will positively impact AVANGRID’s results of operations, and it is possible that the Merger may have an adverse effect, which could be material, on AVANGRID’s results of operations, financial condition and prospects and/or may cause its earnings per share to decrease, any of which may materially adversely affect the market price of AVANGRID common stock and debt securities.

AVANGRID may incur additional indebtedness in connection with the Merger. As a result, it may be more difficult for AVANGRID to pay or refinance its debts or take other actions, and AVANGRID may need to divert cash to fund debt service payments.

AVANGRID may incur significant additional indebtedness to finance the Merger Consideration and related transaction costs. AVANGRID expects to fund all or a portion of the Merger Consideration through sales of its common stock and, possibly, other equity securities, and to the extent it is unable to do so the amount of indebtedness it may incur to finance the Merger and associated transaction costs will likely increase, perhaps substantially. If AVANGRID is required to obtain more debt financing than anticipated to finance the Merger Consideration and associated transaction costs, whether through the issuance of debt securities or borrowings under the committed financing or otherwise, the required regulatory approvals to complete the Merger may be more difficult to obtain and the combined company’s credit ratings and ability to service its debt could be materially adversely affected. The increase in AVANGRID’s debt service obligations resulting from this additional indebtedness could have a material adverse effect on the results of operations, financial condition and prospects of AVANGRID.

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AVANGRID’s increased indebtedness could:

•make it more difficult and/or costly for AVANGRID to pay or refinance its debts as they become due, particularly during adverse economic and industry conditions, because a decrease in revenues or increase in costs could cause cash flow from operations to be insufficient to make scheduled debt service payments;

•limit AVANGRID’s flexibility to pursue other strategic opportunities or react to changes in its business and the industry sectors in which it operates and, consequently, put AVANGRID at a competitive disadvantage to its competitors that have less debt;

•require a substantial portion of AVANGRID’s available cash to be used for debt service payments, thereby reducing the availability of its cash to fund working capital, capital expenditures, development projects, acquisitions, dividend payments and other general corporate purposes, which could harm AVANGRID’s prospects for growth and the market price of its common stock and debt securities, among other things;

•result in a downgrade in the credit ratings on AVANGRID’s indebtedness, which could limit AVANGRID’s ability to borrow additional funds, increase the interest rates under its credit facilities and under any new indebtedness it may incur, and reduce the trading prices of its outstanding debt securities and common stock;

•make it more difficult for AVANGRID to raise capital to fund working capital, make capital expenditures, pay dividends, pursue strategic initiatives or for other purposes;

•result in higher interest expense in the event of increases in interest rates on AVANGRID’s current or future borrowings subject to variable rates of interest; and

•require that additional materially adverse terms, conditions or covenants be placed on AVANGRID under its debt instruments.

Based on the current and expected results of operations and financial condition of AVANGRID and its subsidiaries, AVANGRID believes that its cash flow from operations, together with the proceeds from borrowings, issuances of debt securities in the capital markets, distributions from its equity method investments, project financing and equity sales (including tax equity and partnering in joint ventures) will generate sufficient cash on a consolidated basis to make all of the principal and interest payments when such payments are due under AVANGRID’s and its current subsidiaries’ existing credit facilities, indentures and other instruments governing its outstanding indebtedness and under the indebtedness incurred to fund the Merger Consideration. However, AVANGRID’s expectation is subject to numerous estimates, assumptions and uncertainties, and there can be no assurance that AVANGRID will be able to repay or refinance such borrowings and obligations when due. PNMR and its subsidiaries will not guarantee any indebtedness of AVANGRID, nor will any of them have any obligation to provide funds, whether in the form of dividends, loans or otherwise, to enable AVANGRID and its other subsidiaries to make required debt service payments. As a result, the Merger may substantially increase AVANGRID’s debt service obligations without any assurance that AVANGRID will receive any cash from PNMR or any of its subsidiaries to assist AVANGRID in servicing its indebtedness or other cash needs.

The impact of wildfires could negatively affect PNMR.

PNMR has large networks of electric transmission and distribution facilities. Weather conditions in the U.S. Southwest region and Texas vary and could contribute to wildfires in or near PNMR’s service territories. PNMR take proactive steps to mitigate wildfire risk. However, wildfire risk is always present and PNMR could be held liable for damages incurred as a result of wildfires caused, or allegedly caused, by their transmission and distribution systems. In addition, wildfires could cause damage to PNMR’s assets that could result in loss of service to customers or make it difficult to supply power in sufficient quantities to meet customer needs. These events could adversely affect PNMR and may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

Costs of decommissioning, remediation, and restoration of nuclear and fossil-fueled power plants, as well as reclamation of related coal mines, could exceed the estimates of PNMR as well as the amounts PNMR recovers from its ratepayers, which could negatively impact PNMR.

PNMR has interests in a nuclear power plant, two coal-fired power plants, and several natural gas-fired power plants and is obligated to pay its share of the costs to decommission these facilities. PNMR is also obligated to pay for its share of the costs of reclamation of the mines that supply coal to the coal-fired power plants. Likewise, other owners or participants are responsible for their shares of the decommissioning and reclamation obligations and it is important to PNMR that those parties fulfill their obligations. Rates charged by PNMR to its customers, as approved by the NMPRC, include a provision for recovery of certain costs of decommissioning, remediation, reclamation, and restoration. The NMPRC has established a cap on the amount of costs for the final reclamation of the surface coal mines that may be recovered from customers. PNMR records estimated liabilities for its share of the legal obligations for decommissioning and reclamation in accordance with GAAP. These estimates include many assumptions about future events and are inherently imprecise. In the event the costs to decommission those facilities or to reclaim the mines serving the plants exceed current estimates, or if amounts are not approved for recovery

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by the NMPRC, they could materially and adversely affect PNMR and may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

The costs of decommissioning any nuclear or fossil power plant are substantial. PNMR is responsible for all decommissioning obligations related to its entire proportionate interest in Palo Verde Nuclear Generating Station, or PVNGS, San Juan Generating Station, or SJGS, and Four Corners Power Plant, or FCPP, including portions under lease both during and after termination of the leases. PNMR maintains trust funds and escrow accounts designed to provide adequate financial resources for decommissioning PVNGS, SJGS and FCPP and for reclamation of the coal mines serving SJGS and FCPP at the end of their expected lives. However, because the funds and accounts grow over time to meet decommissioning and reclamation responsibilities, if the PVNGS, SJGS or FCPP units are decommissioned before their planned dates or the coal mines are shut down sooner than expected, these funds may prove to be insufficient, which may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

There are inherent risks in the ownership and operation of nuclear facilities.

While PNMR does not operate PVNGS, PNMR has an indirect 10.2% undivided interest in PVNGS, including interests in Units 1 and 2 held under leases. PVNGS is subject to environmental, health, and financial risks, including, but not limited to, the ability to obtain adequate supplies of nuclear fuel and water, the ability to dispose of spent nuclear fuel, decommissioning of the plant, securing the facilities against possible terrorist attacks, and unscheduled outages due to equipment failures.

The NRC has broad authority under federal law to impose licensing and safety-related requirements for the operation of nuclear generation facilities. Events at nuclear facilities of other operators or which impact the industry generally may lead the NRC to impose additional requirements and regulations on all nuclear generation facilities, including PVNGS. A major incident at a nuclear facility anywhere in the world could cause the NRC to limit or prohibit the operation or licensing of any domestic nuclear unit and to promulgate new regulations that could require significant capital expenditures and/or increase operating costs.

In the event of noncompliance with its requirements, the NRC has the authority to impose a progressively increasing inspection regime that could ultimately result in the shutdown of a unit, civil penalties or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. Increased costs resulting from penalties, a heightened level of scrutiny, and/or implementation of plans to achieve compliance with NRC requirements could adversely affect the financial condition, results of operations, and cash flows of PNMR. Although PNMR has no reason to anticipate a serious nuclear incident at PVNGS, if an incident did occur, it could materially and adversely affect PNMR and may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

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.

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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: October 30, 2020	By:	/s/ Dennis V. Arriola
		Dennis V. Arriola
		Director and Chief Executive Officer

Date: October 30, 2020	By:	/s/ Douglas K. Stuver
		Douglas K. Stuver
		Senior Vice President - Chief Financial Officer

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