10-Q

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 March 31, 2022

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) 629-1190

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 April 28, 2022, the registrant had 386,624,231 shares of common stock, par value $0.01, outstanding.

Avangrid, Inc.

REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2022

INDEX

GLOSSARY OF TERMS AND ABBREVIATIONS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	49
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	65
Item 4.	Controls and Procedures	65
PART II. OTHER INFORMATION		67
Item 1.	Legal Proceedings	67
Item 1A.	Risk Factors	67
Item 2.	Unregistered Sales of Equity Securities and Use of Proceeds	67
Item 3.	Defaults Upon Senior Securities	67
Item 4.	Mine Safety Disclosures	67
Item 5.	Other Information	67
Item 6.	Exhibits	68
SIGNATURES		69

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.

2020 Joint Proposal	Joint proposal of NYSEG and RG&E and certain other signatory parties approved by the NYPSC on November 19, 2020, for a three-year rate plan for electric and gas service commencing December 1, 2020.
AOCI	Accumulated other comprehensive income
ARHI	Avangrid Renewables Holdings, Inc.
ARP	Alternative Revenue Programs
ASC	Accounting Standards Codification
AVANGRID	Avangrid, Inc.
BGC	The Berkshire Gas Company
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
DOC	Department of Commerce
DPA	Deferred Payment Arrangements
DPU	Massachusetts Department of Public Utilities
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, 2021, filed with the Securities and Exchange Commission on March 1, 2022.
HLBV	Hypothetical Liquidation at Book Value
Iberdrola	Iberdrola, S.A.
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
Klamath Plant	Klamath gas-fired cogeneration facility located in the city of Klamath, Oregon.
KW	Kilowatts
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 and as amended and modified as of January 3, 2022 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.
NMPRC	New Mexico Public Regulation Commission
Non-GAAP	Financial measures that are not prepared in accordance with U.S. GAAP, including adjusted net income, adjusted earnings per share, adjusted EBITDA and adjusted EBITDA with tax credits.
NRC	Nuclear Regulatory Commission
NYPSC	New York State Public Service Commission
NYSE	New York Stock Exchange
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
SCG	The Southern Connecticut Gas Company
SEC	United States Securities and Exchange Commission
Side Letter	A side letter agreement dated as of April 15, 2021 between AVANGRID and Iberdrola concerning items
Tax Act	Tax Cuts and Jobs Act of 2017 enacted by the U.S. federal government on December 22, 2017
TEF	Tax equity financing arrangements
UI	The United Illuminating Company
UIL	UIL Holdings Corporation
U.S. GAAP	Generally accepted accounting principles for financial reporting in the United States.
VIEs	Variable interest entities

3

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(unaudited)

	Three Months Ended March 31,
	2022		2021
(Millions, except for number of shares and per share data)
Operating Revenues	$	2,133	$	1,966
Operating Expenses
Purchased power, natural gas and fuel used	741		501
Operations and maintenance	651		642
Depreciation and amortization	261		247
Taxes other than income taxes	178		170
Total Operating Expenses	1,831		1,560
Operating Income	302		406
Other Income and (Expense)
Other income (expense)	11		1
Earnings from equity method investments	253		1
Interest expense, net of capitalization	(71)		(73)
Income Before Income Tax	495		335
Income tax expense	68		14
Net Income	427		321
Net loss attributable to noncontrolling interests	18		13
Net Income Attributable to Avangrid, Inc.	$	445	$	334
Earnings Per Common Share, Basic	$	1.15	$	1.08
Earnings Per Common Share, Diluted	$	1.15	$	1.08
Weighted-average Number of Common Shares Outstanding:
Basic	386,698,132		309,495,250
Diluted	387,114,285		309,736,266

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

4

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(unaudited)

	Three Months Ended March 31,
	2022		2021
(Millions)
Net Income	$	427	$	321
Other Comprehensive Income (Loss)
Gain on nonqualified pension plans, net of income taxes of $3 and $0, respectively	9		—
Unrealized gain from equity method investment, net of income taxes of $5 and $0, respectively	15		—
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(15) and $(5), respectively	(39)		(27)
Reclassification to net income of loss on cash flow hedges, net of income taxes $4 and $(1), respectively	11		1
Other Comprehensive Income (Loss)	(4)		(26)
Comprehensive Income	423		295
Net loss attributable to noncontrolling interests	18		13
Comprehensive Income Attributable to Avangrid, Inc.	$	441	$	308

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

5

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	March 31,		December 31,
As of	2022		2021
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	648	$	1,474
Accounts receivable and unbilled revenues, net	1,476		1,269
Accounts receivable from affiliates	4		11
Derivative assets	135		35
Fuel and gas in storage	91		139
Materials and supplies	217		204
Prepayments and other current assets	281		245
Regulatory assets	377		400
Total Current Assets	3,229		3,777
Total Property, Plant and Equipment ($1,941 and $1,959 related to VIEs, respectively)	29,719		28,866
Operating lease right-of-use assets	156		148
Equity method investments	434		560
Other investments	58		61
Regulatory assets	2,087		2,247
Other Assets
Goodwill	3,119		3,119
Intangible assets	289		293
Derivative assets	47		59
Other	403		374
Total Other Assets	3,858		3,845
Total Assets	$	39,541	$	39,504

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

6

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)

	March 31,		December 31,
As of	2022		2021
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	281	$	372
Notes payable	33		159
Notes payable to affiliates	2		2
Interest accrued	86		69
Accounts payable and accrued liabilities	1,343		1,586
Accounts payable to affiliates	15		61
Dividends payable	340		170
Taxes accrued	76		43
Operating lease liabilities	10		12
Derivative liabilities	115		64
Other current liabilities	500		484
Regulatory liabilities	499		307
Total Current Liabilities	3,300		3,329
Regulatory liabilities	3,011		3,022
Other Non-current Liabilities
Deferred income taxes	2,125		2,016
Deferred income	1,113		1,130
Pension and other postretirement	473		684
Operating lease liabilities	143		149
Derivative liabilities	154		160
Asset retirement obligations	256		253
Environmental remediation costs	284		298
Other	589		580
Total Other Non-current Liabilities	5,137		5,270
Non-current debt	8,033		7,922
Total Non-current Liabilities	16,181		16,214
Total Liabilities	19,481		19,543
Commitments and Contingencies
Equity
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,734,757 and 387,678,630 shares issued; 386,624,231 and 386,568,104 shares outstanding, respectively	3		3
Additional paid in capital	17,683		17,679
Treasury stock	(47)		(47)
Retained earnings	1,819		1,714
Accumulated other comprehensive loss	(277)		(273)
Total Stockholders’ Equity	19,181		19,076
Non-controlling interests	879		885
Total Equity	20,060		19,961
Total Liabilities and Equity	$	39,541	$	39,504

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

7

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)

	Three Months Ended March 31,
	2022		2021
(Millions)
Cash Flow from Operating Activities:
Net income	$	427	$	321
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	261		247
Regulatory assets/liabilities amortization and carrying cost	2		21
Pension cost	8		17
Earnings from equity method investments	(253)		(1)
Distributions of earnings received from equity method investments	5		4
Unrealized loss on marked-to-market derivative contracts	3		53
Deferred taxes	51		(13)
Other non-cash items	—		(5)
Changes in operating assets and liabilities:
Current assets	(183)		(169)
Noncurrent assets	(127)		(93)
Current liabilities	196		39
Noncurrent liabilities	(2)		4
Net Cash Provided by Operating Activities	388		425
Cash Flow from Investing Activities:
Capital expenditures	(811)		(623)
Contributions in aid of construction	30		9
Proceeds from sale of assets	3		8
Proceeds from notes receivable from affiliates	—		5
Distributions received from equity method investments	2		1
Other investments and equity method investments, net	(172)		(39)
Net Cash Used in Investing Activities	(948)		(639)
Cash Flow from Financing Activities:
Non-current debt issuances	149		—
Repayments of non-current debt	(89)		(2)
Repayments of other short-term debt, net	(161)		(301)
Repayments of financing leases	(6)		(1)
Repurchase of common stock	—		(2)
Issuance of common stock	(1)		(1)
Distributions to noncontrolling interests	(1)		(3)
Contributions from noncontrolling interests	13		10
Dividends paid	(170)		(136)
Net Cash Used in Financing Activities	(266)		(436)
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(826)		(650)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	1,477		1,467
Cash, Cash Equivalents and Restricted Cash, End of Period	$	651	$	817
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	55	$	51
Cash paid for income taxes	$	5	$	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 December 31, 2020	309,077,300	$	3	$	13,665	$	(14)	$	1,666	$	(111)	$	15,209	$	617	$	15,826
Net income (loss)	—	—		—		—		334		—		334		(13)		321
Other comprehensive loss, net of tax of $(6)	—	—		—		—		—		(26)		(26)		—		(26)
Comprehensive income																295
Dividends declared, $0.44/share	—	—		—		—		(136)		—		(136)		—		(136)
Release of common stock held in trust	292,594	—		—		—		—		—		—		—		—
Issuance of common stock	53,311	—		(1)		—		—		—		(1)		—		(1)
Repurchase of common stock	(53,311)	—		—		(2)		—		—		(2)		—		(2)
Stock-based compensation	—	—		3		—		—		—		3		—		3
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3)		(3)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		10		10
As of March 31, 2021	309,369,894	$	3	$	13,667	$	(16)	$	1,864	$	(137)	$	15,381	$	611	$	15,992
As of December 31, 2021	386,568,104	$	3	$	17,679	$	(47)	$	1,714	$	(273)	$	19,076	$	885	$	19,961
Net income (loss)	—	—		—		—		445		—		445		(18)		427
Other comprehensive loss, net of tax of $(3)	—	—		—		—		—		(4)		(4)		—		(4)
Comprehensive income																423
Dividends declared, $0.44/share	—	—		—		—		(340)		—		(340)		—		(340)
Issuance of common stock	56,127	—		(1)		—		—		—		(1)		—		(1)
Stock-based compensation	—	—		5		—		—		—		5		—		5
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(1)		(1)
Contributions from noncontrolling interests	—	—		—		—		—		—		—		13		13
As of March 31, 2022	386,624,231	$	3	$	17,683	$	(47)	$	1,819	$	(277)	$	19,181	$	879	$	20,060

(*) Par value of share amounts is $0.01

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

9

Avangrid, Inc. and Subsidiaries

Notes to Condensed Consolidated Financial Statements

(unaudited)

Note 1. Background and Nature of Operations

Avangrid, Inc. (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 81.6% of the outstanding common stock of AVANGRID. The remaining outstanding shares are owned by various shareholders with approximately 18.4% of AVANGRID's outstanding shares publicly-traded on the New York Stock Exchange (NYSE).

Proposed Merger with PNMR

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 is expected to 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 Federal Energy Regulatory Commission (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. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. The Statement of Issues was filed on February 2, 2022 and the Brief in Chief was filed on April 7, 2022. The Answer Brief is currently due on June 13, 2022, and the Reply Brief is currently due on July 5, 2022 (pending any extensions granted to the parties). In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which AVANGRID, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of AVANGRID and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by AVANGRID and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. We cannot predict the outcome of this proceeding for the outstanding approvals.

The Merger Agreement 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

10

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.

The Merger Agreement (as amended) 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 April 20, 2023 (subject to a three-month extension by AVANGRID and PNMR by mutual consent 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).

In connection with the Merger, Iberdrola 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.

On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which sets forth certain terms and conditions relating to the Iberdrola Funding Commitment Letter (the Side Letter Agreement). The Side Letter Agreement provides that any drawing in the form of indebtedness made by the Corporation pursuant to the Funding Commitment Letter shall bear interest at an interest rate equal to 3-month LIBOR plus 0.75% per annum calculated on the basis of a 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, we shall pay Iberdrola a facility fee equal to 0.12% per annum on the undrawn portion of the funding commitment set forth in the Funding Commitment Letter.

On May 18, 2021, we issued 77,821,012 shares of common stock in two private placements. Iberdrola purchased 63,424,125 shares and Hyde Member LLC, a Delaware limited liability company and a wholly owned subsidiary of Qatar Investment Authority, purchased 14,396,887 shares of our common stock, par value $0.01 per share, at the purchase price of $51.40 per share, which was the closing price of the shares of our common stock on the NYSE as of May 11, 2021. Proceeds of the private placements were $4,000 million. $3,000 million of the proceeds were used to repay the Iberdrola Loan. After the effect of the private placements, Iberdrola retained its 81.6% ownership interest in AVANGRID.

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, 2021.

The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts 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.

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 months ended March 31, 2022, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2022.

Note 3. Significant Accounting Policies and New Accounting Pronouncements

The new accounting pronouncements we have adopted as of January 1, 2022, and reflected in our condensed consolidated financial statements are described below. There have been no other material changes to the significant accounting policies

11

described in our Form 10-K for the fiscal year ended December 31, 2021, except for those described below resulting from the adoption of new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB).

Adoption of New Accounting Pronouncements

(a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification

In March 2020, the FASB issued amendments and created ASC 848 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.

In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.

We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect our consolidated results of operations, financial position and cash flows.

(b) Disclosures by business entities about government assistance

In November 2021, the FASB issued amendments that apply to business entities (all entities except specified not-for-profit entities and employee benefit plans) that account for a transaction with a government by applying a grant or contribution accounting model by analogy to other accounting guidance (such as a grant model within International Accounting Standards 20 Accounting for Government Grants and Disclosure of Government Assistance, or ASC Subtopic 958-605, Not-For-Profit Entities—Revenue Recognition). Government assistance can include tax credits (excluding transactions within the scope of Topic 740, Income Taxes), cash grants, grants of other assets, and project grants. Often, government assistance is provided to an entity for a particular purpose, and the entity promises to take specific actions. Transactions with a government, as used in ASC 832, Government Assistance, include assistance administered by domestic, foreign, local (city, town, county, municipal), regional (state, provincial, territorial), and national (federal) governments and entities related to those governments. The amendments require annual disclosures in notes to financial statements about transactions with a government as follows: (1) information about the nature of the transactions and the related accounting policy used to account for the transactions, (2) the line items on the balance sheet and income statement affected by the transactions, and the amounts applicable to each financial statement line item, and (3) significant terms and conditions of the transactions, including commitments and contingencies. For entities within scope the amendments are effective for annual periods beginning after December 15, 2021, with early application permitted. The amendments are to be applied either (1) prospectively to transactions within the scope of the amendments that are reflected in financial statements at the date of initial application and new transactions that are entered into after the date of initial application or (2) retrospectively to those transactions. Our adoption of the amendments on January 1, 2022 did not materially affect our disclosures.

(c) Fair Value Hedging – Portfolio Layer Method

In March 2022, the FASB issued amendments to ASC 815 to provide additional guidance on hedge accounting. The update expands the current last-layer method that permits only one hedged layer to allow multiple hedged layers of a single closed portfolio. To reflect that expansion, the last-of-layer method is renamed the portfolio layer method. It also specifies that eligible hedging instruments in a single-layer hedge may include spot-starting or forward-starting constant notional or amortizing

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notional swaps. It also provides additional guidance on the accounting for and disclosure of hedge basis adjustments that are applicable to the portfolio layer method.

The amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. Early adoption is permitted on any date on or after the issuance date. We have elected to early apply the amendments effective April 1, 2022. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows.

Accounting Pronouncements Issued but Not Yet Adopted

The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2021, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Troubled Debt Restructurings and Vintage Disclosures

In March 2022, the FASB issued amendments to ASC 326 to provide guidance for troubled debt restructurings (TDRs) and vintage disclosures. For TDRs, the update requires entities to measure and record lifetime expected credit losses on an asset that is within scope of Topic 326. The prior guidance in Topic 310 of designating a loan as a TDR was considered unnecessarily complex. For vintage disclosures, the amendments require an entity to disclose current-period gross write-offs by year of origination for financing receivables and net investments in leases within the scope of Subtopic 326-20.

The amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively, except as provided in the next sentence. For the transition method related to the recognition of TDRs, an entity has the option to apply a modified retrospective transition method, resulting in a cumulative-effect adjustment to retained earnings in the period of adoption. Early adoption is permitted.

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. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. 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 FERC regulation, which establishes the prices and other terms of service. Long-term wholesale sales of electricity are based on

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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.

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 or a percentage 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 2022 upon commercial operation. Contract assets totaled $9 million at both March 31, 2022 and December 31, 2021, 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 $8 million and $16 million at March 31, 2022 and December 31, 2021, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $8 million and $4 million as revenue during the three months ended March 31, 2022 and 2021, respectively.

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Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2022 and 2021 are as follows:

	Three Months Ended March 31, 2022
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,170	$	—	$	—	$	1,170
Regulated operations – natural gas	721		—		—		721
Nonregulated operations – wind	—		220		—		220
Nonregulated operations – solar	—		7		—		7
Nonregulated operations – thermal	—		13		—		13
Other(a)	22		16		—		38
Revenue from contracts with customers	1,913		256		—		2,169
Leasing revenue	3		—		—		3
Derivative losses	—		(63)		—		(63)
Alternative revenue programs	12		—		—		12
Other revenue	7		5		—		12
Total operating revenues	$	1,935	$	198	$	—	$	2,133

	Three Months Ended March 31, 2021
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	942	$	—	$	—	$	942
Regulated operations – natural gas	564		—		—		564
Nonregulated operations – wind	—		371		—		371
Nonregulated operations – solar	—		4		—		4
Nonregulated operations – thermal	—		12		—		12
Other(a)	10		32		—		42
Revenue from contracts with customers	1,516		419		—		1,935
Leasing revenue	2		—		—		2
Derivative losses	—		(31)		—		(31)
Alternative revenue programs	47		—		—		47
Other revenue	8		5		—		13
Total operating revenues	$	1,573	$	393	$	—	$	1,966

(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 March 31, 2022 and December 31, 2021, accounts receivable balances related to contracts with customers were approximately $1,433 million and $1,220 million, respectively, including unbilled revenues of $402 million and $405 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

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As of March 31, 2022, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of March 31, 2022	2023		2024		2025		2026		2027		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	1	$	1	$	—	$	—	$	—	$	—	$	2
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	18		14		12		10		7		60		121
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	27		17		6		4		1		1		56
Total operating revenues	$	46	$	32	$	18	$	14	$	8	$	61	$	179

As of March 31, 2022, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2022 was $46 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. As of March 31, 2022, the total net amount of these items is approximately $867 million.

CMP Distribution 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 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. Commencing on 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 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order.

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 customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. We cannot predict the outcome of this investigation.

NYSEG and RG&E Rate Plans

On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. 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 rate plans continue the RAM designed to return or collect

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certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50.00%. The below table provides a summary of the approved 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	4.6	%	$	46	5.9	%	$	36	4.2	%
NYSEG Gas	$	—	—	%	$	2	0.8	%	$	3	1.6	%
RG&E Electric	$	17	3.8	%	$	14	3.2	%	$	16	3.3	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2	1.3	%

UI, CNG, SCG and BGC Rate Plans

In 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, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% 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 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, 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 an equity ratio of approximately 52.00%. 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 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (CNG) effective January 1, 2019 for a three-year rate plan with annual rate increases. 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.

In 2019, the Massachusetts Department of Public Utilities (DPU) approved new distribution rates for Berkshire Gas Company (BGC). The distribution rate increase is based on a 9.70% ROE and 54.00% 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. BGC expects to file an application to amend its distribution rates in the first half of 2022. We cannot predict the outcome of this proceeding.

Connecticut Energy 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 for certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.

Pursuant to the legislation, on October 30, 2020, PURA re-opened a docket related to new rate designs and review, expanding the scope to consider (a) the implementation of an interim rate decrease; (b) low-income rates; and (c) economic development rates. Separately, UI was due to make its annual RAM filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and RDM.

On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement, which addressed issues in both dockets.

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In an order dated June 23, 2021, PURA approved the as amended settlement agreement in its entirety and it was executed by the parties. The settlement agreement includes a contribution by UI of $5 million and provides customers rate credits of $50 million while allowing UI to collect $52 million in RAM, all over a 22-month period ending April 2023 and also includes a distribution base rate freeze through April 2023.

Pursuant to the legislation, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. The Company is reviewing the requirements of this program and evaluating next steps.

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

On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.

On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. We cannot predict the outcome of these appeals.

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 March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Pension and other post-retirement benefits cost deferrals	$	322	$	545
Pension and other post-retirement benefits	96		95
Storm costs	502		448
Rate adjustment mechanism	61		68
Revenue decoupling mechanism	59		68
Transmission revenue reconciliation mechanism	13		15
Contracts for differences	69		73
Hardship programs	25		24
Plant decommissioning	2		2
Deferred purchased gas	10		52
Deferred transmission expense	8		13
Environmental remediation costs	251		256
Debt premium	70		71
Unamortized losses on reacquired debt	22		23
Unfunded future income taxes	444		424
Federal tax depreciation normalization adjustment	141		142
Asset retirement obligation	20		20
Deferred meter replacement costs	49		46
COVID-19 cost recovery	19		21
Other	281		241
Total regulatory assets	2,464		2,647
Less: current portion	377		400
Total non-current regulatory assets	$	2,087	$	2,247

“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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“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 unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases.

“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” 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.

“Plant decommissioning” represents decommissioning and demolition expenses related to closing fossil plant facilities - Beebe & Russell.

“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 forty-six 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 25 to 35 years and for CMP 32.5 years beginning in 2020.

“Asset retirement obligations” 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 or are planned to be replaced by AMI 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 March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Energy efficiency portfolio standard	$	43	$	45
Gas supply charge and deferred natural gas cost	35		7
Pension and other post-retirement benefits cost deferrals	71		73
Carrying costs on deferred income tax bonus depreciation	20		23
Carrying costs on deferred income tax - Mixed Services 263(a)	6		7
2017 Tax Act	1,310		1,327
Rate Change Levelization	100		99
Revenue decoupling mechanism	20		13
Accrued removal obligations	1,201		1,192
Asset sale gain account	—		2
Economic development	26		26
Positive benefit adjustment	21		22
Theoretical reserve flow thru impact	6		6
Deferred property tax	19		22
Net plant reconciliation	15		16
Debt rate reconciliation	46		49
Rate refund – FERC ROE proceeding	35		35
Transmission congestion contracts	25		23
Merger-related rate credits	11		12
Accumulated deferred investment tax credits	23		24
Asset retirement obligation	18		18
Earning sharing provisions	15		13
Middletown/Norwalk local transmission network service collections	17		17
Low income programs	28		25
Non-firm margin sharing credits	17		15
New York 2018 winter storm settlement	5		5
Hedge gains	98		19
Other	279		194
Total regulatory liabilities	3,510		3,329
Less: current portion	499		307
Total non-current regulatory liabilities	$	3,011	$	3,022

“Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount 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 three years and began in 2020.

"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 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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

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“Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. 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 three years and began in 2020.

"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 three years and began in 2020.

“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.

"Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer 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 2020.

"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 in current rates is three years for NYSEG and two years for RG&E and began in 2020.

“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 three years and began in 2020.

“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 three years and began in 2020.

“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 three to five years and began in 2020.

"Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for 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 2020.

"Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. 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 2020.

"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.

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"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 the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. 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 2020.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During both the three months ended March 31, 2022 and 2021, $1 million of rate credits were applied against customer bills.

"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 earnings sharing threshold. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

"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 NYPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. The balance is being amortized through current rates over an amortization period of three years, beginning in 2020.

“Hedge gains” represents the deferred fair value gains on electric and gas hedge contracts.

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

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, fixed income 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. NYSEG and RG&E hedge up to approximately 55% of its forecasted winter demand through the use of financial transactions and storage withdrawals. 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 Intercontinental Exchange (ICE). We include the fair value measurements in Level 1 because we use prices quoted in an active market.

•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.

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•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 New York Mercantile Exchange (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 interest rate derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 12 for further discussion of interest rate contracts).

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.

The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value.

Restricted cash was $3 million as of both March 31, 2022 and December 31, 2021, respectively and is included in "Other Assets" on our condensed consolidated balance sheets.

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The financial instruments measured at fair value as of March 31, 2022 and December 31, 2021, respectively, consisted of:

As of March 31, 2022	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	36	$	17	$	—	$	—	$	53
Derivative assets
Derivative financial instruments - power	$	89	$	49	$	104	$	(79)	$	163
Derivative financial instruments - gas	13		65		4		(67)		15
Contracts for differences	—		—		2		—		2
Total	$	102	$	114	$	112	$	(146)	$	182
Derivative liabilities
Derivative financial instruments - power	$	(5)	$	(206)	$	(163)	$	243	$	(131)
Derivative financial instruments - gas	—		(38)		(2)		35		(5)
Contracts for differences	—		—		(71)		—		(71)
Derivative financial instruments – Other	—		(62)		—		—		(62)
Total	$	(5)	$	(306)	$	(236)	$	278	$	(269)

As of December 31, 2021	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	45	$	15	$	—	$	—	$	60
Derivative assets
Derivative financial instruments - power	$	31	$	39	$	85	$	(78)	$	77
Derivative financial instruments - gas	4		34		9		(32)		15
Contracts for differences	—		—		2		—		2
Total	$	35	$	73	$	96	$	(110)	$	94
Derivative liabilities
Derivative financial instruments - power	$	(16)	$	(137)	$	(90)	$	176	$	(67)
Derivative financial instruments - gas	(1)		(22)		—		18		(5)
Contracts for differences	—		—		(75)		—		(75)
Derivative financial instruments - Other	—		(77)		—		—		(77)
Total	$	(17)	$	(236)	$	(165)	$	194	$	(224)

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The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2022 and 2021, respectively, is as follows:

	Three Months Ended March 31,
(Millions)	2022		2021
Fair Value Beginning of Period,	$	(69)	$	13
Gains recognized in operating revenues	38		11
(Losses) recognized in operating revenues	(40)		(4)
Total gains recognized in operating revenues	(2)		7
Gains recognized in OCI	2		1
(Losses) recognized in OCI	(63)		(17)
Total gains (losses) recognized in OCI	(61)		(16)
Net change recognized in regulatory assets and liabilities	4		1
Purchases	(1)		—
Settlements	5		(4)
Fair Value as of March 31,	$	(124)	$	1
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)	$	7

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 March 31, 2022
Index	Avg.		Max.		Min.
NYMEX ($/MMBtu)	$	3.58	$	6.52	$	2.27
AECO ($/MMBtu)	$	2.69	$	5.69	$	1.53
Ameren ($/MWh)	$	38.09	$	93.59	$	18.01
COB ($/MWh)	$	50.49	$	231.90	$	9.15
ComEd ($/MWh)	$	34.53	$	86.32	$	14.98
ERCOT N hub ($/MWh)	$	39.26	$	140.00	$	13.66
ERCOT S hub ($/MWh)	$	37.80	$	140.00	$	13.88
Indiana hub ($/MWh)	$	40.20	$	93.81	$	20.74
Mid C ($/MWh)	$	47.52	$	229.90	$	5.15
Minn hub ($/MWh)	$	34.61	$	90.99	$	15.23
NoIL hub ($/MWh)	$	34.30	$	84.00	$	14.64
PJM W hub ($/MWh)	$	39.84	$	113.93	$	17.78

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 uncontracted wind positions. The power swaps are used to hedge uncontracted wind production in the West and Midwest.

We considered the measurement uncertainty regarding 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 uncontracted 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.

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

The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that 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	March 31, 2022
Risk of non-performance	0.56% - 0.67%
Discount rate	2.42% - 2.45%
Forward pricing ($ per KW-month)	$2.00 - $4.63

Fair Value of Debt

As of March 31, 2022 and December 31, 2021, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $8,495 million and $9,155 million as of March 31, 2022 and December 31, 2021, 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 operating and financing activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our condensed consolidated balance sheets in accordance with the accounting requirements concerning derivative instruments and hedging activities.

(a) Networks activities

The tables below present Networks' derivative positions as of March 31, 2022 and December 31, 2021, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:

As of March 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	98	$	7	$	—	$	4
Derivative liabilities	—		(4)		(15)		(61)
	98		3		(15)		(57)
Designated as hedging instruments
Derivative assets	1		—		—		—
Derivative liabilities	—		—		—		—
	1		—		—		—
Total derivatives before offset of cash collateral	99		3		(15)		(57)
Cash collateral receivable	—		—		—		1
Total derivatives as presented in the balance sheet	$	99	$	3	$	(15)	$	(56)

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As of December 31, 2021	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	29	$	7	$	12	$	4
Derivative liabilities	(12)		(4)		(27)		(64)
	17		3		(15)		(60)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		—
	—		—		(1)		—
Total derivatives before offset of cash collateral	17		3		(16)		(60)
Cash collateral receivable	—		—		—		—
Total derivatives as presented in the balance sheet	$	17	$	3	$	(16)	$	(60)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,	December 31,
As of	2022	2021
(Millions)
Wholesale electricity purchase contracts (MWh)	5.3	5.7
Natural gas purchase contracts (Dth)	8.4	9.4
Fleet fuel purchase contracts (Gallons)	1.4	2.0

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 our 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 March 31, 2022 and December 31, 2021 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2022 and 2021 are as follows:

(Millions)	Loss or Gain Recognized in Regulatory Assets/Liabilities				Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As of						Three Months Ended March 31,
March 31, 2022	Electricity		Natural Gas		2022	Electricity		Natural Gas
Regulatory assets	$	1	$	—	Purchased power, natural gas and fuel used	$	(45)	$	(9)
Regulatory liabilities	$	(85)	$	(13)
December 31, 2021					2021
Regulatory assets	$	—	$	—	Purchased power, natural gas and fuel used	$	2	$	(1)
Regulatory liabilities	$	(16)	$	(3)

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

PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2022, 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 $69 million, a gross derivative liability of $71 million ($68 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, 2021, 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 $73 million, a gross derivative liability of $75 million ($72 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2022 and 2021, respectively, were as follows:

	Three Months Ended March 31,
	2022		2021
(Millions)
Derivative assets	$	—	$	—
Derivative liabilities	$	4	$	1

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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 months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	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)
2022
Interest rate contracts	$	—	Interest expense	$	1	$	71
Commodity contracts	2		Purchased power, natural gas and fuel used	(1)		741
Foreign currency exchange contracts	—			—
Total	$	2		$	—
2021
Interest rate contracts	$	—	Interest expense	$	1	$	73
Commodity contracts	1		Purchased power, natural gas and fuel used	—		501
Foreign currency exchange contracts	(4)			—
Total	$	(3)		$	1

(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 $46 million and $47 million as of March 31, 2022 and December 31, 2021, respectively. For both the three months ended March 31, 2022 and 2020, Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million. Networks will amortize approximately $3 million of discontinued cash flow hedges for the remainder of 2022.

Unrealized gains of $2 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable as of March 31, 2022. Networks expects $1 of those gains will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months.

(b) Renewables activities

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

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

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

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The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,	December 31,
As of	2022	2021
(MWh/Dth in millions)
Wholesale electricity purchase contracts	4	4
Wholesale electricity sales contracts	9	10
Natural gas and other fuel purchase contracts	13	20
Financial power contracts	8	9
Basis swaps – purchases	25	30
Basis swaps – sales	1	—

The fair values of derivative contracts associated with Renewables' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Wholesale electricity purchase contracts	$	85	$	36
Wholesale electricity sales contracts	(162)		(77)
Natural gas and other fuel purchase contracts	—		6
Financial power contracts	22		35
Total	$	(55)	$	—

On May 27, 2021, Renewables entered into a forward interest rate swap, with a total notional amount of $935 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As part of the financial close of Vineyard Wind 1 described in Note 19, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of March 31, 2022 and December 31, 2021, the fair value of the interest rate swap was $2 million and $58 million, respectively, as a non-current liability. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred.

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The tables below present Renewables' derivative positions as of March 31, 2022 and December 31, 2021, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:

As of March 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	53	$	65	$	89	$	12
Derivative liabilities	(17)		(21)		(115)		(12)
	36		44		(26)		—
Designated as hedging instruments
Derivative assets	—		—		2		2
Derivative liabilities	—		—		(141)		(105)
	—		—		(139)		(103)
Total derivatives before offset of cash collateral	36		44		(165)		(103)
Cash collateral (payable) receivable	—		—		69		62
Total derivatives as presented in the balance sheet	$	36	$	44	$	(96)	$	(41)

As of December 31, 2021	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	29	$	70	$	52	$	9
Derivative liabilities	(11)		(14)		(65)		(11)
	18		56		(13)		(2)
Designated as hedging instruments
Derivative assets	—		—		5		6
Derivative liabilities	—		—		(67)		(142)
	—		—		(62)		(136)
Total derivatives before offset of cash collateral	18		56		(75)		(138)
Cash collateral payable	—		—		27		57
Total derivatives as presented in the balance sheet	$	18	$	56	$	(48)	$	(81)

Derivatives not designated as hedging instruments

The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2022, consisted of:

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	Three Months Ended March 31, 2022
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	9	$	3
Wholesale electricity sales contracts	(1)		(40)
Financial power contracts	(2)		(21)
Financial and natural gas contracts	(1)		(25)
Total gain (loss) included in operating revenues	$	5	$	(83)	$	2,133
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	37
Financial power contracts	—		1
Financial and natural gas contracts	—		37
Total gain included in purchased power, natural gas and fuel used	$	—	$	75	$	741
Total Gain (Loss)	$	5	$	(8)

The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2021, consisted of:

	Three Months Ended March 31, 2021
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	7	$	—
Wholesale electricity sales contracts	—		(17)
Financial power contracts	(5)		(16)
Financial and natural gas contracts	—		(4)
Total gain (loss) included in operating revenues	$	2	$	(37)	$	1,966
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	10
Financial power contracts	—		1
Financial and natural gas contracts	—		4
Total loss included in purchased power, natural gas and fuel used	$	—	$	15	$	501
Total Gain (Loss)	$	2	$	(22)

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of (Gain) Reclassified from Accumulated OCI into Income	(Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2022
Commodity contracts	$	(112)	Operating revenues	$	11	$	2,133
2021
Commodity contracts	$	(28)	Operating revenues	$	(3)	$	1,966

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

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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 $137 million of losses included in accumulated OCI at March 31, 2022, 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 months ended March 31, 2022 and 2021.

(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.

As of March 31, 2022 and December 31, 2021, the net loss in accumulated OCI related to previously settled interest rate contracts was $46 million and $48 million, respectively. For both the three months ended March 31, 2022 and 2021, we amortized into income $2 million of the loss related to settled interest rate contracts. We will amortize approximately $7 million of the net loss on the interest rate contracts for the remainder of 2022.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	(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)
2022
Interest rate contracts	$	—	Interest expense	$	2	$	71
2021
Interest rate contracts	$	—	Interest expense	$	2	$	73

(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 which end in 2025 and 2029.

On July 15, 2021, Corporate entered into an interest rate swap to hedge the fair value of $750 million of existing debt included in "Non-current debt" on our consolidated balance sheets. The interest rate swap is designated and qualifies as a fair value hedge. The change in the fair value of the interest rate swap and the offsetting change in the fair value of the underlying debt are reported as components of "Interest expense."

The effects on our consolidated financial statements as of and for the three months ended March 31, 2022 and 2021 are as follows:

	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
(Millions)	As of March 31, 2022			Three Months Ended March 31, 2022
Current Liabilities	$	(4)	Interest Expense	$	(2)	$	71
Non-current liabilities	$	(57)
	Cumulative effect on hedged debt
Current debt	$	4
Non-current debt	$	57

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	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
(Millions)	As of December 31, 2021			Three Months Ended March 31, 2021
Current Assets	$	—	Interest Expense	$	—	$	73
Non-current liabilities	$	(19)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	19

(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 ratings on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2022, UI would have had to post an aggregate of approximately $20 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. As of March 31, 2022 and December 31, 2021, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $82 million and $67 million, respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows.

Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of March 31, 2022 was $1 million, for which we have posted collateral.

Note 8. Contingencies and Commitments

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 probable 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).

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On October 16, 2014, the FERC issued its decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners.

CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $27 million and $8 million, respectively, as of March 31, 2022, which has not changed since December 31, 2021, 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. On November 19, 2020, FERC issued an order addressing arguments raised on rehearing of its May 21, 2020 order making minor adjustments to certain typographical errors with regard to some of the case inputs it included in its Risk Premium model analysis. However, those minor adjustments did not affect the outcome of the case, leaving the 10.02% ROE established by the May 21, 2020 order in place. Parties to these orders affecting the MISO transmission owners’ base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO’s submitted an amici curia brief in support of the MISO transmission owners’ on March 17, 2021. 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.

On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (Supplemental NOPR) that proposes to eliminate the 50 basis-point ROE incentive for utilities who join Regional Transmission Organizations after three years of membership. The NETOs submitted initial comments in opposition to the Supplemental NOPR on June 25, 2021 and reply comments on July 26, 2021. If the elimination of the 50 basis-point ROE incentive adder becomes final, we estimate we would have an approximately $3 million reduction in earnings per year. We cannot predict the outcome of this proceeding.

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

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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. 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. On June 17, 2021, the FERC issued an Order Establishing Limited Remand remanding the case to the administrative law judge for additional detailed findings and legal analysis with respect to the impact of the conduct of one of the parties other than Renewables on their long-term contracts. The order did not address any of the other findings, including all of the findings with respect to Renewables, which remain pending. There is no specific timetable for the administrative law judge’s ruling. On July 9, 2021, Renewables filed a motion requesting that the FERC expeditiously issue a final decision with respect to the Renewables long-term contract rather than waiting for the administrative law judge’s ruling. We cannot predict the outcome of this proceeding.

New York State Public Service Commission Show Cause Order Regarding Greenlight Pole Attachments

On November 20, 2020, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Show Cause Order) regarding alleged violations of the NYPSC’s 2004 Order Adopting Policy Statement on Pole Attachments, dated August 6, 2004 (the 2004 Pole Order) by RG&E, Greenlight Networks, Inc, (Greenlight), and Frontier Communications (Frontier). The alleged violations detailed in the Show Cause Order arise from Greenlight’s installation of unauthorized and substandard communications attachments throughout RG&E’s and Frontier’s service territories. The Show Cause Order directs RG&E to show cause within 30 days why the NYPSC should not pursue civil and/or administrative penalties or initiate a prudency proceeding or civil action for injunctive relief for more than 11,000 alleged violations of the 2004 Pole Order. Under NY Public Service Law Section 25-a, each alleged violation carries a potential penalty of up to $100,000 where it can be shown that the violator failed to “reasonably comply” with a statute or NYPSC order.

RG&E, Greenlight and Frontier filed respective notices to initiate settlement negotiations with respect to the alleged violations and to extend the deadline for filing a response to the Show Cause Order. The NYPSC granted the extension requests initiating settlement discussions. On or about August 12, 2021, the NYPSC approved a settlement entered into by NYDPS and RG&E providing for, among other things, RG&E’s payment of $3 million, which will be used to support the State of New York’s broadband initiative for underserved areas. This settlement amount could increase to a maximum of $5 million if RG&E does not resolve certain identified safety violations caused by Greenlight’s pole attachments on or before December 31, 2021. We have met all compliance requirements of the settlement and filed the final compliance statement with the NYPSC on January 12, 2022.

Beatrice Corwin Living Irrevocable Trust, by and through Its Authorized Trustee, Robert Corwin v. Iberdrola, S.A., et. al.

On January 8, 2021, the Beatrice Corwin Living Irrevocable Trust, by and through its Authorized Trustee, Robert Corwin filed a complaint in the Supreme Court of the State of New York Westchester County against Iberdrola and the members of the Company’s Board of Directors, as defendants, and the Company, as a nominal defendant with respect to certain counts contained in the complaint. The complaint alleges certain violations of fiduciary duties by Iberdrola and the members of the Company’s Board of Directors related to the existence of certain pre-emptive rights provided to Iberdrola in the Shareholder Agreement between the Company and Iberdrola, dated December 16, 2015, and the binding nature of such rights. On March 29, 2021, the parties stipulated to and requested, and the Supreme Court of the State of New York Westchester County issued an Order providing for, the transfer of the venue of the complaint to the Supreme Court, County of New York. On May 20, 2021, the matter was transferred to New York County and assigned to the Commercial Division of the Supreme Court, County of New York. On September 3, 2021, the plaintiffs filed an amended verified complaint (i) dropping claims concerning the purported breach of AVANGRID’s articles of incorporation and New York’s statute concerning equal treatment among shareholders, (ii) adding and modifying their claims related to the duty of good faith and loyalty and (iii) adding allegations concerning the Iberdrola Loan and the May 2021 private placement of our common shares to Iberdrola and Hyde Partners, LLC. In addition, the plaintiffs are now purporting to bring a class action lawsuit. On October 22, 2021, we and our board of directors filed a motion to dismiss and Iberdrola filed a motion to dismiss and an application to stay discovery pending resolution of dispositive motions. On December 8, 2021, the plaintiffs filed an omnibus opposition to the motions to dismiss and the defendants' filed a reply to such motion on January 14, 2022. On March 17, 2022, the Court heard oral arguments and at the conclusion of the hearing granted the defendants' motion to dismiss.

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Guarantee Commitments to Third Parties

As of March 31, 2022, we had approximately $488 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including $4 million related to Vineyard Wind. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind as described in Note 19, which is in addition to the amounts above. These instruments provide financial assurance to the business and trading partners of AVANGRID, its subsidiaries and equity method investees in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of March 31, 2022, neither we nor our subsidiaries have any liabilities recorded for these instruments.

NECEC Commitments

On January 4, 2021, CMP transferred the New England Clean Energy Connect, or NECEC, project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately $9 million was paid through the end of 2021. In December 2021 the remaining future payments were suspended following the halt in construction of the NECEC project.

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 $7 million related to eleven of the twenty-six sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation 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. As of March 31, 2022, our estimate for costs to remediate these sites ranges from $14 million to $22 million. 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; and three sites are part of Maine’s Voluntary Response Action Program with two such sites part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.

As of March 31, 2022, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $160 million to $273 million. Our estimate could change materially based on facts and circumstances derived from site investigations, changes in required remedial actions, changes in technology relating to remedial alternatives and changes to current laws and regulations.

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

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or had an ownership interest in one or more such properties contaminated as a result of MGP-related activities. Under the existing regulations, the cleanup of such sites requires state and at times, federal, regulators’ involvement and approval before cleanup can commence. In certain cases, such contamination has been evaluated, characterized and remediated. In other cases, the sites have been evaluated and characterized, but not yet remediated. Finally, at some of these sites, the scope of the contamination has not yet been fully characterized; as of March 31, 2022, no liability was recorded related to these sites 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 both March 31, 2022 and December 31, 2021, the liability associated with our MGP sites in Connecticut was $113 million, 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.

As of March 31, 2022 and December 31, 2021, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $300 million and $303 million, 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 2081.

FirstEnergy

NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the sixteen sites in dispute. In 2008, the District Court issued a decision and order in RG&E's favor requiring FirstEnergy to pay RG&E for past and future clean-up costs at the two MGP sites in dispute. FirstEnergy remains liable for a substantial share of clean up expenses at the MGP sites. Based on projections as of March 31, 2022, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $14 million and $7 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable.

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, and oral arguments have taken place. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. The plaintiffs filed a petition to appeal to the Connecticut Supreme Court, which was denied, leaving only the claim against UI for unjust enrichment. 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

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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 continued its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order.

As of March 31, 2022 and December 31, 2021, the amount reserved related to English Station was $21 million and $22 million, respectively. Since inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of this matter.

Note 10. Post-retirement and Similar Obligations

We made no pension contributions for the three months ended March 31, 2022. We expect to make additional contributions of $23 million for the remainder of 2022.

The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2022 and 2021, respectively, consisted of:

	Three Months Ended March 31,
	2022		2021
(Millions)
Service cost	$	8	$	10
Interest cost	24		22
Expected return on plan assets	(45)		(50)
Amortization of:
Prior service costs	1		—
Actuarial loss	18		35
Curtailments and settlements	2		—
Net Periodic Benefit Cost	$	8	$	17

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2022 and 2021, respectively, consisted of: 

	Three Months Ended March 31,
	2022		2021
(Millions)
Service cost	$	1	$	1
Interest cost	3		2
Expected return on plan assets	(2)		(2)
Amortization of:
Prior service costs	—		(2)
Actuarial loss	(1)		1
Net Periodic Benefit Cost	$	1	$	—

In March 2022 the AVANGRID board approved plan amendments to freeze pension benefit accruals and contribution credits for Networks non-union employees effective June 30, 2022. The balance sheet impact from these amendments was a reduction in pension liabilities and regulatory assets of approximately $200 million at March 31, 2022. The plan changes resulted in a curtailment charge of $2 million. Our expected rate of return on assets (EROA) was updated for certain plans based on our de-risking glide-path model. This approach reduces investment risk as the plan’s funded status improves, resulting in our weighted average EROA for 2022 declining from 6.3% used in the first quarter calculation of pension costs to 5.9%, which will be used for the remainder of the year.

Note 11. Equity

As of both March 31, 2022 and December 31, 2021, we had 112,543 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2022 and 2021, we released 0 and 292,594 shares of common stock held in trust, respectively.

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

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allow AVANGRID to maintain Iberdrola's relative ownership percentage at 81.6%. The stock repurchase program may be suspended or discontinued at any time upon notice. As of March 31, 2022, a total of 997,983 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 $47 million as of March 31, 2022.

Accumulated Other Comprehensive Loss 

Accumulated Other Comprehensive Loss for the three months ended March 31, 2022 and 2021, respectively, consisted of:

	As of December 31,		Three Months Ended March 31,		As of March 31,		As of December 31,		Three Months Ended March 31,		As of March 31,
	2021		2022		2022		2020		2021		2021
(Millions)
Change in revaluation of defined benefit plans	$	(10)	$	—	$	(10)	$	(12)	$	—	$	(12)
(Loss) gain on nonqualified pension plans, net of income tax expense of $3 for 2022	(28)		9		(19)		(20)		—		(20)
Unrealized (loss) gain from equity method investment, net of income tax expense of $5 for 2022 (a)	(9)		15		6		—		—		—
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(15) for 2022 and $(5) for 2021	(194)		(39)		(233)		(35)		(27)		(62)
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $4 for 2022 and $(1) for 2021 (b)	(32)		11		(21)		(44)		1		(43)
Loss on derivatives qualifying as cash flow hedges	(226)		(28)		(254)		(79)		(26)		(105)
Accumulated Other Comprehensive Loss	$	(273)	$	(4)	$	(277)	$	(111)	$	(26)	$	(137)

(a)    Foreign currency and interest rate contracts.

(b)    Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our 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 months ended March 31, 2022 and 2021, 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 months ended March 31, 2022 and 2021, respectively, consisted of:

	Three Months Ended March 31,
	2022		2021
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	445	$	334
Denominator:
Weighted average number of shares outstanding - basic	386,698,132		309,495,250
Weighted average number of shares outstanding - diluted	387,114,285		309,736,266
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	1.15	$	1.08
Earnings Per Common Share, Diluted	$	1.15	$	1.08

On March 30, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on July 1, 2022 to shareholders of record at the close of business on June 4, 2022.

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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 nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment.

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

The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments 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 months ended March 31, 2022, consisted of:

Three Months Ended March 31, 2022	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,935	$	198	$	—	$	2,133
Depreciation and amortization	161		100		—		261
Operating income	319		(18)		1		302
Earnings from equity method investments	3		250		—		253
Interest expense, net of capitalization	50		3		18		71
Income tax expense (benefit)	31		41		(4)		68
Adjusted net income	254		211		(15)		450
Capital expenditures	355		454		2		811
As of March 31, 2022
Property, plant and equipment	18,882		10,825		12		29,719
Equity method investments	149		285		—		434
Total assets	$	26,329	$	12,747	$	465	$	39,541

(a) Includes Corporate and intersegment eliminations.

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Segment information for the three months ended March 31, 2021 and as of December 31, 2021, consisted of:

Three Months Ended March 31, 2021	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,573	$	393	$	—	$	1,966
Depreciation and amortization	156		91		—		247
Operating income	313		92		1		406
Earnings (losses) from equity method investments	2		(1)		—		1
Interest expense, net of capitalization	53		—		20		73
Income tax expense (benefit)	42		(9)		(19)		14
Adjusted net income	229		123		2		354
Capital expenditures	531		92		—		623
As of December 31, 2021
Property, plant and equipment	18,737		10,118		11		28,866
Equity method investments	148		412		—		560
Total assets	$	26,126	$	12,578	$	800	$	39,504

(a) Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2022 and 2021, respectively, is as follows:

	Three Months Ended March 31,
	2022		2021
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	450	$	354
Adjustments:
Mark-to-market earnings - Renewables (1)	(3)		(20)
Impact of COVID-19 (2)	(2)		(6)
Income tax impact of adjustments	2		7
Net Income Attributable to Avangrid, Inc.	$	445	$	334

(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)     Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions.

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 months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	2022				2021
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(12)	$	—	$	(13)
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(3)	$	—	$	(2)
Vineyard Wind	$	2	$	—	$	4	$	—
Iberdrola Solutions	$	—	$	—	$	7	$	(38)
Other	$	—	$	(1)	$	1	$	(1)

Related party balances as of March 31, 2022 and December 31, 2021, respectively, consisted of:

As of	March 31, 2022				December 31, 2021
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	2	$	(10)	$	3	$	(43)
Iberdrola Financiación, S.A.	$	—	$	(2)	$	—	$	(9)
Vineyard Wind	$	2	$	(8)	$	8	$	(8)
Iberdrola Solutions	$	—	$	(2)	$	—	$	(2)
Other	$	—	$	(3)	$	—	$	(1)

Transactions with Iberdrola 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.

We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balance of $2 million as both March 31, 2022 and December 31, 2021. Renewables also has financial forward power contracts with Iberdrola Solutions to hedge Renewables' merchant wind exposure in Texas.

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.

AVANGRID optimizes its liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both March 31, 2022 and December 31, 2021, was $0.

AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of March 31, 2022 and December 31, 2021, there was no outstanding amount under this credit facility.

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

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Note 15. Other Financial Statement Items

Accounts receivable and unbilled revenue, net

Accounts receivable and unbilled revenues, net as of March 31, 2022 and December 31, 2021 consisted of:

As of	March 31, 2022		December 31, 2021
(Millions)
Trade receivables and unbilled revenues	$	1,629	$	1,420
Allowance for credit losses	(153)		(151)
Accounts receivable and unbilled revenues, net	$	1,476	$	1,269

The change in the allowance for credit losses for the three months ended March 31, 2022 and 2021 consisted of:

	Three Months Ended March 31,
(Millions)	2022		2021
As of Beginning of Period,	$	151	$	108
Current period provision	20		39
Write-off as uncollectible	(18)		(12)
As of March 31,	$	153	$	135

The Deferred Payment Arrangements (DPA) receivable balance was $112 million and $108 million at March 31, 2022 and December 31, 2021, respectively. The allowance for credit losses for DPAs at March 31, 2022 and December 31, 2021 was $71 million and $68 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2022 and 2021, was $3 million and $5 million, respectively.

Prepayments and other current assets

Included in prepayments and other current assets are $120 million and $95 million of prepaid other taxes as of March 31, 2022 and December 31, 2021, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of March 31, 2022 and December 31, 2021, respectively, were as follows:

	March 31,		December 31,
As of	2022		2021
(Millions)
Property, plant and equipment
Accumulated depreciation	$	10,830	$	10,589
Intangible assets
Accumulated amortization	$	321	$	317

Debt

Long-term debt issuance

On January 31, 2022, UI issued $150 million aggregate principal amount of unsecured notes maturing in 2032 at a fixed interest rate of 2.25%.

Supplier Financing Arrangements

We operate a supplier financing arrangement. We arranged for the extension of payment terms with some suppliers, which could elect to be paid by a financial institution earlier than maturity under supplier financing arrangements. Due to the interest cost associated with these arrangements, the balances are classified as "Notes payable" on our consolidated balance sheets. The balance relates to capital expenditures and, therefore, is treated as non-cash activity, and is reported under financing activity of the consolidated statement of cash flows when the balance is paid. As of March 31, 2022 and December 31, 2021, the amount of notes payable under supplier financing arrangements was $35 million and $161 million, respectively. As of March 31, 2022 and December 31, 2021, the weighted average interest rate on the balance was 2.08% and 0.82%, respectively.

Other current liabilities

Included in other current liabilities are $178 million and $204 million of advances received as of March 31, 2022 and December 31, 2021, respectively.

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Note 16. Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2022, was 13.7%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act and the equity component of allowance for funds used during construction, partially offset by the tax on gain from the offshore joint venture restructuring transaction (see Note 19 for further details on the transaction), which is reflected in total in the first quarter as a discrete adjustment.

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2021, was 4.2%, 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.

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).

Performance Stock Units

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 March 2022, 46,737 shares of common stock were issued to settle the third and final installment payment under this plan.

During March 2022, 17,501 additional PSUs were granted to certain officers and employees of AVANGRID. The PSUs will vest upon achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and will be payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.22 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date.

Restricted Stock Units

In January 2022, 17,500 RSUs were granted to an officer of AVANGRID with immediate vesting. The fair value on the grant date was determined based on a price of $48.16 per share. The RSU grant was settled, net of applicable taxes, by issuing 9,390 shares of common stock.

Phantom Share Units

In March 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards 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 March 2022, $2 million was paid to settle the third and final installment under this plan.

In February 2022, 9,000 Phantom Shares were granted to certain AVANGRID executives and employees. These awards vest in three equal installments in 2022 - 2024 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.

As of March 31, 2022 and December 31, 2021, the total liability was $0 and $2 million, respectively, which is included in other current and non-current liabilities.

The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2022 and 2021, was $5 million and $4 million, respectively.

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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.

The assets and liabilities of the VIEs totaled approximately $2,006 million and $91 million, respectively, at March 31, 2022. As of December 31, 2021, the assets and liabilities of VIEs totaled approximately $2,039 million and $119 million, respectively. At March 31, 2022 and December 31, 2021, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.

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.

At March 31, 2022, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus VII and Aeolus VIII are our consolidated VIEs.

Our El Cabo, Patriot, Aeolus VII and Aeolus VIII 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.

Note 19. Equity Method Investments

Renewables holds a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners (CIP). Prior to a restructuring transaction that took place on January 10, 2022, Vineyard Wind held acquired easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. The first easement area acquired was Lease Area 501 which contains 166,886 acres located southeast of Martha's Vineyard. Lease Area 501 was subsequently divided in 2021 creating Lease Area 534. In 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm (Vineyard Wind 1) and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. The Vineyard Wind 1 project will be located on Lease Area 501.

In December 2019, the Park City Wind project was selected and approved to provide 804 MW of offshore wind in Connecticut. In December 2021, the Commonwealth Wind project was selected to provide 1,232 MW of offshore wind primarily through contracts with the electric distribution companies in Massachusetts, subject to final regulatory approvals. Both projects are located in Lease Area 534.

Vineyard Wind acquired a second offshore easement contract from BOEM (Lease Area 522). Renewables initially contributed $100 million to Vineyard Wind to acquire the easement contract, which was proportionally more than CIP's contribution. Pursuant to a joint bidding agreement between Renewables and CIP, CIP had the option to reimburse Renewables an amount, plus interest, to restore its 50% interest in the easement contract. In December 2020, CIP exercised this option and reimbursed Renewables $33 million, plus interest.

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On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Among other items, the Vineyard Wind 1 project was transferred into a separate joint venture with Vineyard Wind 1 Pledgor LLC as the top holding company, which Renewables holds a 50% voting interest. Concurrently, Renewables entered into a credit agreement with certain banks to provide future term loans and letters of credit up to a maximum of approximately $1.2 billion to finance a portion of its share of the cost of Vineyard Wind 1 at the maturity of the Vineyard Wind 1 project construction loan. Any term loans mature by October 15, 2031, subject to certain extension provisions. Renewables also entered into an Equity Contribution Agreement in which Renewables agreed to, among other things, make certain equity contributions to fund certain costs of developing and constructing the Vineyard Wind 1 project in accordance with the credit agreement. In addition, we issued a guaranty up to $827 million for Renewables' equity contributions under the Equity Contribution Agreement. As part of the Vineyard Wind 1 financial close, $152 million of Renewables prior contributions for the Vineyard Wind 1 project were returned.

On September 15, 2021, Renewables entered into a restructuring agreement with CIP with respect to Vineyard Wind. The restructuring closed on January 10, 2022 and effectively dissolved Vineyard Wind. As part of the restructuring, Renewables acquired full ownership of Park City Wind LLC containing Lease Area 534, including the Park City Wind project and Commonwealth Wind project in Lease Area 534, and CIP acquired OCS-A 0522 LLC containing Lease Area 522. Immediately following Vineyard Wind's dissolution of interests in Park City Wind LLC and OCS-A 0522 LLC, Vineyard Wind solely provides construction and management services to Vineyard Wind 1, which are outsourced to third party service providers, and no longer owns the rights to any lease areas, and therefore no longer has substantive operations. As part of the restructuring and effective dissolution, Renewables received a liquidating distribution and made an incremental payment of approximately $168 million to CIP. Consequently, Renewables recognized a pretax gain of $246 million and an after tax gain of $181 million, driven by the increase in the market value of its acquired interest in the leases and related development activities over its carrying value. The gain is classified in Earnings from equity method investments in the condensed consolidated statement of income.

Vineyard Wind 1 Pledgor LLC is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. As of March 31, 2022 and December 31, 2021, the carrying amount of Renewables' investments in Vineyard Wind LLC and Vineyard Wind 1 Pledgor LLC was $15 million and $141 million, respectively.

Note 20. Subsequent Event

On April 6, 2022, NYSEG issued $67 million aggregate principal amount of Pollution Control Bonds maturing in 2028. The bonds bear a 4.00% fixed coupon and were priced at 104.15% to yield 3.3%.

On April 29, 2022, we closed on a TEF agreement, receiving $14 million from a tax equity investor related to the Lund Hill solar farm that reached partial mechanical completion on the same date. A further investment from our investor is expected shortly after the project’s commercial operations in the amount of $58 million, expected in August. Lund Hill will be owned by Solis Power I, LLC.

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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, 2021 and 2020, and for the three years ended December 31, 2021, included in our Annual Report on Form 10-K for the year ended December 31, 2021, filed with the Securities and Exchange Commission, or the SEC, on February 23, 2022, 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 aspires to be the leading sustainable energy company in the United States. Our purpose is to work every day to deliver a more accessible clean energy model that promotes healthier, more sustainable communities. A commitment to sustainability is firmly entrenched in the values and principles that guide AVANGRID, with environmental, social, governance and financial sustainability key priorities driving our business strategy.

AVANGRID has approximately $40 billion in assets and operations in 24 states concentrated in our 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 8.9 gigawatts of electricity capacity, primarily through wind and solar 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, was named among the World’s Most Ethical companies in 2022 for the fourth consecutive year by the Ethisphere Institute and is listed by Forbes and Just Capital as one of the 2022 Just 100, an annual ranking of the most just U.S. public companies. AVANGRID employs approximately 7,300 people. Iberdrola S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.6% of the outstanding shares of AVANGRID common stock. The remaining outstanding shares are owned by various shareholders with approximately 18.4% of AVANGRID's outstanding shares publicly-traded on the New York Stock Exchange (NYSE). AVANGRID's primary businesses 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 distribution, transmission and generation 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 utility customers as of March 31, 2022.

Networks, a Maine corporation, holds 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.

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Renewables has a combined wind, solar and thermal installed capacity of 8,869 megawatts, or MW, as of March 31, 2022, including Renewables’ share of joint projects, of which 7,956 MW was installed wind capacity. Renewables targets to contract or hedge 85% to 95% of its capacity under long-term PPAs and hedges to limit market volatility. As of March 31, 2022, approximately 73% of the capacity was contracted with PPAs for an average period of approximately 9 years and an additional 15% of production was hedged. AVANGRID is one of the three largest wind operators in the United States based on installed capacity as of March 31, 2022, Renewables strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables installed capacity includes 66 wind farms and four solar facilities in 21 states across the United States.

Texas Weather Event

During February 2021, Texas and the surrounding region experienced unprecedented extreme cold weather, resulting in outages impacting millions in the state. Avangrid Renewables safely operated our Texas wind generation facilities during this event meeting all of our delivery obligations in Texas and producing excess energy that was sold based on the rules established at the time by the Energy Reliability Council of Texas, or ERCOT. If the received payments are adjusted by ERCOT, it could adversely affect our results of operations.

In connection with the Texas Weather Event, more than 150 defendants including certain Renewables subsidiaries in Texas were named in a civil petition filed in Texas state court by more than 160 plaintiffs alleging a variety of legal theories, including negligence and gross negligence, product liability and strict liability, strict liability-abnormally dangerous activity, negligent misrepresentation, misrepresentation, fraud, civil conspiracy, breach of continuing duty to warn, breach of express warranties and breach of implied warranty of fitness for a particular purpose. A second lawsuit was filed in Texas state court in April 2021 naming more than a hundred defendants including certain Renewables subsidiaries in Texas based on similar theories of liability. A third matter, filed by a number of insurance carriers on subrogation grounds against several generators including one of Renewables' subsidiaries was filed in January 2022. We have not been served in this new litigation. We cannot predict the outcome of this matter.

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 is expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID, or the Merger. PNMR is a publicly-owned holding company with two regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR's electric utilities are the Public Service Company of New Mexico and the Texas-New Mexico Power Company. Following consummation of the Merger, AVANGRID will expand its geographic and regulatory diversity with ten regulated electric and gas companies in six states to help expand our growing leadership position in transforming the U.S. energy industry.

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 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.

On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which sets forth certain terms and conditions relating to the Funding Commitment Letter (the Side Letter Agreement). The Side Letter Agreement provides that any drawing in the form of indebtedness made by AVANGRID pursuant to the Funding Commitment Letter shall bear interest at an interest rate equal to 3-month LIBOR plus 0.75% per annum calculated on the basis of a 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, we shall pay Iberdrola a facility fee equal to 0.12% per annum on the undrawn portion of the funding commitment set forth in the Funding Commitment Letter.

On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order

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rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. The Statement of Issues was filed on February 2, 2022 and the Brief in Chief was filed on April 7, 2022. The Answer Brief is currently due on June 13, 2022, and the Reply Brief is currently due on July 5, 2022 (pending any extensions granted to the parties). In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement, or the Amendment, pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the New Mexico Public Regulation Commission, or NMPRC, has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. We cannot predict the outcome of this proceeding for the outstanding approvals.

The Merger Agreement 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.

The Merger Agreement (as amended) 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 April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent 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).

In connection with the Merger, Iberdrola 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.

Business Environment

The COVID-19 pandemic continues to cause global economic disruption and volatility in financial markets and the United States economy. We continue to monitor developments affecting both our workforce and our customers and will take precautions that we determine are necessary or appropriate, regularly communicate with our customers regarding the tools and resources available and to help our customers stay informed during this public health crisis, and continue to actively monitor 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. In addition, we are experiencing changes in inflation levels resulting from various supply chain disruptions, increased business and labor costs, increased financing costs from changes in the Federal Reserve's monetary policy and other disruptions caused by global economic conditions, including the COVID-19 pandemic and the Russia and Ukraine conflict described below. 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 or global economic trends 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.

In February 2022, Russia invaded Ukraine resulting in the United States, Canada, the European Union and other countries imposing economic sanctions on Russia. AVANGRID is monitoring the broader economic impact of this conflict,

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which may include further sanctions, supply chain instability, and potential retaliatory action by the Russian government against us. AVANGRID is taking steps intended to mitigate the potential risks from this continued conflict. To date, there has been no material impact on our operations or financial performance as a result of the conflict; however, we cannot predict the extent of these effects, given the evolving nature of the conflict, on our business, results of operations or financial condition.

AVANGRID is monitoring the Department of Commerce's, or DOC, anti-circumvention petition alleging that solar panels and cells shipped from Vietnam, Thailand, Malaysia and Cambodia have circumvented tariffs imposed on Chinese solar panels and cells. The petition calls for anti-dumping and countervailing duties to be applied to solar panels and cells and could be retroactive to the filing date. Renewables is taking steps intended to mitigate potential risks to their solar project development portfolio. To date, there has been no material impact on Renewables' operations or financial performance as a result of this investigation; however, given the uncertainty of the resolution by the DOC and related effects to the solar panel supply chain, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

Summary of Results of Operations

Our operating revenues increased by 8%, from $1,966 million for the three months ended March 31, 2021 to $2,133 million for the three months ended March 31, 2022.

Networks business revenues increased mainly due to rate increases in New York effective December 1, 2020. Renewables revenues decreased mainly due to a decrease in merchant prices driven mainly by lower demand as compared to the first quarter of 2021 when demand was higher during the Texas storm.

Net income attributable to AVANGRID increased by 33% from $334 million for the three months ended March 31, 2021 to $445 million for the three months ended March 31, 2022, primarily due to higher Networks revenues from the New York rate case activity and a gain recognized in the current period from the offshore joint venture restructuring transaction in Renewables.

Adjusted net income (a non-GAAP financial measure) increased by 27% from $354 million for the three months ended March 31, 2021 to $450 million for the three months ended March 31, 2022. The increase is primarily due to a $88 million increase in Renewables driven by a gain recognized in the current period from the offshore joint venture restructuring transaction, a $25 million increase in Networks driven primarily by rate increases in New York effective December 1, 2020, offset by $17 million decrease in Corporate mainly driven by unfavorable tax expense in the period.

For additional information and reconciliation of the non-GAAP adjusted net income to net income attributable to AVANGRID, see “—Non-GAAP Financial Measures”.

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

Legislative and Regulatory Update

We are subject to complex and stringent energy, environmental and other laws and regulations at the federal, state and local levels as well as rules within the independent system operator, or ISO, markets in which we participate. Federal and state legislative and regulatory actions continue to change how our business is regulated. We actively participate in the regulatory process 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, 2021.

Customer Disconnections

Due to the COVID-19 pandemic, all of our regulated utilities suspended customer disconnections commencing in March 2020. In New York, we had voluntarily suspended disconnections for non-payment. 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, which occurred on June 24, 2021. Due to the winter disconnection moratorium period, disconnections did not resume until April 2022.

CMP Metering and Billing Investigation

On February 19, 2020, the MPUC issued an order in CMP’s distribution rate case proceeding 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, which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required

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rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order.

CMP Standard Offer Uncollectible Adder Investigation

On August 19, 2020, the MPUC issued a Notice of Investigation to open an investigation into 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 go into effect January 1, 2022. The investigation also included a review of CMP’s credit and collection practices.

On June 22, 2021, CMP and the Maine Office of the Public Advocate executed and filed with the MPUC a Stipulation resolving all matters in this proceeding, which requires CMP to credit the residential and small non-residential standard-offer retainage account for $4 million. On June 29, 2021, the MPUC issued an Order Approving Stipulation pursuant to which the MPUC approved the Stipulation and closed the investigation.

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 $141 million and $142 million, respectively, for this item at March 31, 2022 and December 31, 2021.

CMP began recovering its regulatory asset in 2020. In 2017, the NYPSC commenced an audit of the power tax regulatory assets. 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 2022.

New England Clean Energy Connect

The NECEC project requires certain permits, including environmental, from multiple state and federal agencies and a presidential permit from the U.S. Department of Energy, or DOE, authorizing the construction, operation, maintenance and connection of facilities for the transmission of electric energy at the international border between the United States and Canada. On January 8, 2020, the Maine Land Use Planning Commission, or LUPC, granted the LUPC Certification for the NECEC. The Maine Department of Environmental Protection, or MDEP, granted Site Location of Development Act, Natural Resources Protection Act, and Water Quality Certification permits for the NECEC by an Order dated May 11, 2020. The MDEP Order has been appealed by certain intervenors. The Maine Board of Environmental Protection, or BEP, will consider the appeals of the MDEP Order, as well as the appeal of MDEP’s December 4, 2020 Order approving the transfer of the permits for the project to NECEC Transmission LLC on May 17 and May 18, 2022. In addition, certain intervenors have appealed MDEP’s May 7, 2021 Order approving certain minor revisions. This appeal remains pending before the BEP. We cannot predict the outcome of these proceedings.

On November 6, 2020, the project received the required approvals from the U.S. Army Corps of Engineers, or Army Corps, pursuant to Section 10 of the Rivers and Harbor Act of 1899 and Section 404 of the Clean Water Act. A complaint for declaratory and injunctive relief asking the court to vacate or remand the Section 404 Clean Water Act permit for the NECEC project filed by three environmental groups is currently pending before the District Court in Maine.

ISO-NE issued the final System Impact Study (SIS) for NECEC on May 13, 2020, determining the upgrades required to permit the interconnection of NECEC to the ISO-NE system. On July 9, 2020, the project received the formal I.3.9 approval associated with this interconnection request. CMP, NECEC Transmission LLC and ISO-NE executed an interconnection agreement. With respect to the upgrade required at the Seabrook Station, on October 13, 2020, AVANGRID and NECEC Transmission LLC filed a complaint with the FERC and an amended complaint on March 26, 2021. On October 5, 2020, NextEra Energy Seabrook, LLC filed a petition for declaratory order. Both proceedings are currently pending before FERC. We cannot predict the outcome of these proceedings.

On January 14, 2021, the DOE issued a Presidential Permit granting permission to NECEC Transmission LLC to construct, operate, maintain and connect electric transmission facilities at the international border of the United States and Canada. On March 26, 2021, the plaintiffs challenging the Army Corps permit filed a motion for leave before the District Court in Maine to supplement their complaint to add claims against DOE in connection with the Presidential Permit. On April 20, 2021, the District Court granted the plaintiffs motion to amend the complaint. On April 22, 2021 the plaintiffs filed their amended complaint asking the Court, among other things, to vacate, set aside, remand or stay the Presidential Permit. This

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challenge to the Presidential Permit is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.

On August 10, 2021, the Maine Superior Court issued a ruling reversing the Maine Bureau of Parks and Lands’, or BPL, decision to grant a lease over a small area of public reserved lands to host a small section of the NECEC project. On August 13, 2021, BPL, and NECEC Transmission LLC appealed this ruling and prior decisions and orders in the case. The appeal is currently pending before the Maine Supreme Judicial Court sitting as the Law Court, or the Maine Law Court. As a result of the appeal, the Maine Superior Court decision vacating the lease is stayed. On September 15, 2021, the Maine Law Court ordered NECEC Transmission LLC to refrain from construction activities on the public reserved lands lease area during the pendency of the appeal. Oral argument before the Law Court is scheduled for May 10, 2022. We cannot predict the outcome of this proceeding.

On November 2, 2021, Maine voters approved, by virtue of a referendum, L.D. 1295 (I.B. 1) (130th Legis. 2021), “An Act To Require Legislative Approval of Certain Transmission Lines, Require Legislative Approval of Certain Transmission Lines and Facilities and Other Projects on Public Reserved Lands and Prohibit the Construction of Certain Transmission Lines in the Upper Kennebec Region” (the “Initiative”). The Initiative (i) requires, retroactive to 2020, legislative approval for the construction of any high-impact transmission line in Maine, with approval by a 2/3 vote of all members elected to each House of the Maine Legislature required for such lines crossing or utilizing public lands; (ii) prohibits, retroactive to 2020, construction of a high-impact electric transmission line in the Upper Kennebec Region and (iii) requires, retroactive to 2014, the vote of 2/3 of all members elected to each House of the Maine Legislature for a lease by BPL of public reserved lands for transmission lines and similar linear projects.

On November 3, 2021, Networks and NECEC Transmission LLC filed a lawsuit challenging the constitutionality of the Initiative and requesting injunctive relief preventing retroactive enforcement of the Initiative to the NECEC transmission project. Networks and NECEC Transmission LLC also requested a preliminary injunction preventing such retroactive enforcement during the pendency of the lawsuit.

On November 23, 2021, the MDEP issued an Order finding that the Initiative constitutes a changed circumstance justifying the suspension of the MDEP permits for the NECEC project. This MDEP-ordered suspension will remain effective unless and until a court grants Networks and NECEC Transmission LLC’s request for a preliminary injunction and allows continued construction of the NECEC project pending the final outcome of the legal challenge to the Initiative, or, if a court does not grant a preliminary injunction, until final disposition of the legal challenge in favor of Networks and NECEC Transmission LLC. In its order, the MDEP ruled that, so long as such MDEP permits are suspended, all construction must stop, subject to the performance and completion of certain activities required by the Order. The MDEP also stated in its Order that in the event that the current ordered suspension ended, it would promptly consider whether to suspend the MDEP permits for the NECEC in light of the ruling from the Maine Superior Court reversing BPL’s decision to grant a lease over public reserved lands for the NECEC project.

On December 16, 2021, the Maine Business & Consumer Court denied Networks and NECEC Transmission LLC’s request for a preliminary injunction temporarily precluding application of the Initiative to the NECEC transmission project. The Initiative took effect on December 19, 2021. On December 22, 2021, Networks and NECEC Transmission LLC moved that the Business & Consumer Court report its decision to the Maine Law Court for an interlocutory appeal under the applicable rule of appellate procedure. On December 28, 2021, the Business & Consumer Court granted this motion, thereby sending its decision to the Law Court for review. Briefing on the report took place between February and April 2022. Oral argument before the Law Court is scheduled for May 10, 2022. We cannot predict the outcome of these proceedings.

At the municipal level, twenty-one towns have granted municipal approvals to date.

Construction of the NECEC project started in January 2021 and was halted in November 2021. Construction remains stopped pending a decision by the Maine Law Court on the report of the Business & Consumer Court decision that denied Networks and NECEC Transmission LLC’s request for preliminary injunction preventing enforcement of the Initiative against the NECEC project during the pendency of the challenge against the Initiative. NECEC Transmission LLC has communicated to the counterparties to its agreements, including, without limitation, vendors, suppliers and TSA parties, the suspension of the MDEP permit, the Initiative and the status of the pending challenge. There are potentially adverse implications arising out of the suspension of the MDEP permit, the Initiative and the pending challenge, which may have negative impacts on the NECEC project, including impacts related to increased project construction costs and a decrease in expected returns. We cannot predict the outcome of the pending challenge against the Initiative. The company estimates a commercial operation date in December 2024, assuming construction activities resume in 2022. As of March 31, 2022, we have capitalized approximately $561 million for the NECEC project.

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

On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.

On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. We cannot predict the outcome of these appeals.

Connecticut Energy 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 for certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.

Pursuant to the legislation, on October 30, 2020, PURA re-opened a docket related to new rate designs and review, expanding the scope to consider (a) the implementation of an interim rate decrease; (b) low-income rates; and (c) economic development rates. Separately, UI was due to make its annual rate adjustment mechanism, or RAM, filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and Revenue Decoupling Mechanism.

On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement.

In an order dated June 23, 2021, PURA approved the as amended settlement agreement in its entirety and it was executed by the parties. The settlement agreement includes a contribution by UI of $5 million and provides customers rate credits of $50 million while allowing UI to collect $52 million in RAM, all over a 22-month period ending April 2023 and also includes a distribution base rate freeze through April 2023.

Pursuant to the legislation, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers.

Proposed New York Legislation in Response to the Tropical Storm Isaias

Proposed legislation has been introduced that would amend the public service law to, among other things, increase potential penalties and give greater discretion to the NYPSC to assess penalties for violations of the Public Service Law, Regulations, or Orders of the NYPSC. We cannot predict the outcome of this proposed legislation.

CMP Generator Interconnection Investigation

On February 10, 2021, two solar developer associations petitioned the MPUC to open an investigation into CMP’s generator interconnection practices and the estimates CMP provided to developers related to expected interconnection costs. On April 6, 2021, the MPUC issued a Notice of Formal Investigation related to the prudency and reasonableness of CMP’s actions with respect to the interconnection of generation to its distribution system. The Hearing Examiners in the matter have issued a procedural order setting a discovery schedule, CMP has responded to data requests and a technical conference has been conducted. On September 21, 2021, the MPUC staff issued a Bench Memorandum providing the staff’s assessment (i) whether CMP has followed a course of conduct that a capably managed utility would have followed in light of existing and reasonably knowable circumstances and (ii) if not, what steps should be taken, including penalties and changes to ensure that CMP acts reasonably on a forward going basis. In the Bench Memorandum, staff found that CMP’s conduct, and related management

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actions and inactions, raise significant issues regarding prudency. Specifically, staff found that CMP did not adequately prepare for the large volume of generator interconnection applications that resulted from “An Act To Promote Solar Energy Projects and Distributed Generation Resources in Maine”, enacted by the Maine legislature in 2019. MPUC staff recommends that the MPUC require that CMP to file a detailed plan to better integrate planning across relevant departments in the generator interconnection process with the MPUC. CMP’s response to the Bench Memorandum was filed on October 12, 2021. On January 11, 2022, an uncontested Stipulation settling this matter and two other dockets was filed with the MPUC. All but two parties to the three proceedings joined the Stipulation and the two non-signatory parties do not oppose the Stipulation. In the Stipulation, among other things, the Stipulating Parties agree to support resolution of all issues, that CMP shall pay $150,000 to be used to support a facilitator for the MPUC’s DG Interconnection Working Group for a period of two years and $550,000 to fund up to six contracted analyst resources to support the interconnection process for a period of two years. Also, CMP has agreed to meet certain published cluster study timelines subject to qualifications set forth in the Stipulation. The MPUC will consider the Stipulation at a future meeting, the date of which to be determined. We cannot predict the outcome of this investigation or any potential penalties that may be assessed.

Maine Government-Run Power Referendum and Legislation to Ensure Utility Accountability

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 ballot. The proponents did not submit signatures in January 2022, the deadline to place the referendum on the November 2022 ballot, but have made statements that they intend to continue to collect sufficient signatures to present the referendum in a general election. We cannot predict the outcome of this request or any potential referendum.

In February 2022, a bill, L.D. 1959, An Act To Ensure Transmission and Distribution Utility Accountability was introduced in the Maine Legislature. The bill provides additional Maine PUC requirements on Maine large electric utilities, including CMP, to ensure customer service and reliability. The bill would also impose penalties for poor performance, add more protection for whistleblowers who report illegal or improper behavior by a utility, authorize the PUC to audit utilities’ financial information, require utilities to submit regular plans to address the impact of climate change on their infrastructure, and initiate a proceeding for divestiture subject to constitutional protections due process and just compensation. The bill, as amended, has passed the Maine Legislature in April 2022 and would become effective in 2022 unless vetoed by the Maine Governor.

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Results of Operations

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

	Three Months Ended								Three Months Ended
	March 31, 2022								March 31, 2021
	Total		Networks		Renewables		Other(1)		Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	2,133	$	1,935	$	198	$	—	$	1,966	$	1,573	$	393	$	—
Operating Expenses
Purchased power, natural gas and fuel used	741		756		(15)		—		501		449		52		—
Operations and maintenance	651		539		113		(1)		642		506		139		(3)
Depreciation and amortization	261		161		100		—		247		156		91		—
Taxes other than income taxes	178		160		18		—		170		149		19		2
Total Operating Expenses	1,831		1,616		216		(1)		1,560		1,260		301		(1)
Operating Income	302		319		(18)		1		406		313		92		1
Other Income (Expense)
Other income (expense)	11		12		1		(2)		1		6		(6)		1
Earnings (losses) from equity method investments	253		3		250		—		1		2		(1)		—
Interest expense, net of capitalization	(71)		(50)		(3)		(18)		(73)		(53)		—		(20)
Income (Loss) Before Income Tax	495		284		230		(19)		335		268		85		(18)
Income tax expense (benefit)	68		31		41		(4)		14		42		(9)		(19)
Net Income (Loss)	427		253		189		(15)		321		226		94		1
Net loss (income) attributable to noncontrolling interests	18		(1)		19		—		13		(1)		14		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	445	$	252	$	208	$	(15)	$	334	$	225	$	108	$	1

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

Comparison of Period to Period Results of Operations

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

Operating Revenues

Our operating revenues increased by $167 million, or 8%, from $1,966 million for the three months ended March 31, 2021 to $2,133 million for the three months ended March 31, 2022, as detailed by segment below:

Networks

Operating revenues increased by $362 million, or 23%, from $1,573 million for the three months ended March 31, 2021 to $1,935 million for the three months ended March 31, 2022. Electricity and gas revenues increased by $26 million, primarily due to rate increases in New York effective December 1, 2020, $6 million favorable impact from increased deferrals, $6 million increase in late payment fees, and $2 million of other. Electricity and gas revenues changed due to the following items that have offsets within the income statement: an increase of $307 million in purchased power and purchased gas (offset in purchased power) driven by higher average pricing in commodities in the period and an increase of $15 million in flow through amortizations (offset in operating expenses).

Renewables

Operating revenues decreased by $195 million, or 50%, from $393 million for the three months ended March 31, 2021, to $198 million for the three months ended March 31, 2022. The decrease in operating revenues was primarily due to a $139 million decrease in merchant prices driven mainly by lower demand as compared to the first quarter of 2021 when demand was higher during the Texas storm, $19 million in power trading driven by lower average prices in the first quarter of 2022 compared to the same period of 2021, $2 million from other revenues in the period and unfavorable MtM changes of $43 million on energy derivative transactions entered for economic hedging purposes, offset by $3 million from curtailment payments and an increase of $5 million driven by 292 GWh higher wind generation output in the current period.

Purchased Power, Natural Gas and Fuel Used

Purchased power, natural gas and fuel used increased by $240 million, or 48%, from $501 million for the three months ended March 31, 2021 to $741 million for the three months ended March 31, 2022, as detailed by segment below:

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Networks

Purchased power, natural gas and fuel used increased by $307 million, or 68%, from $449 million for the three months ended March 31, 2021 to $756 million for the three months ended March 31, 2022. The increase is primarily driven by a $307 million increase in average commodity prices and an overall increase in electricity and gas units procured due to higher degree days in the period.

Renewables

Purchased power, natural gas and fuel used decreased by $67 million, or 129%, from $52 million for the three months ended March 31, 2021 to $(15) million for the three months ended March 31, 2022. The decrease is primarily due to favorable MtM changes on derivatives of $60 million driven by market price changes in the period and a decrease of $7 million in power and gas purchases due to lower average prices in the current period.

Operations and Maintenance

Operations and maintenance expenses increased by $9 million, or 1%, from $642 million for the three months ended March 31, 2021 to $651 million for the three months ended March 31, 2022, as detailed by segment below:

Networks

Operations and maintenance expenses increased by $33 million, or 7%, from $506 million for the three months ended March 31, 2021 to $539 million for the three months ended March 31, 2022. The increase is driven by increased business costs of $24 million and $2 million increase in other expenses, offset by an $8 million decrease in uncollectible expenses due to lower bad debt provision in the current period. In addition, there were increases of $15 million in flow-through amortizations (which is offset in revenue).

Renewables

Operations and maintenance expenses decreased by $26 million, or 19%, from $139 million for the three months ended March 31, 2021 to $113 million for the three months ended March 31, 2022. The decrease is primarily due to a $16 million bad debt provision recorded in the first quarter of 2021 driven by an increase in uncollectibles billed during the Texas storm, decrease of $14 million in land rents and maintenance costs driven by a lower number of new sites in 2022 compared to the same period of 2021, offset by a $4 million increase in personnel costs driven primarily by increase in headcount in the period.

Depreciation and Amortization

Depreciation and amortization for the three months ended March 31, 2022 was $261 million compared to $247 million for the three months ended March 31, 2021, an increase of $14 million. The increase is driven by $8 million from plant additions in Networks and Renewables in the period and $6 million increase driven by amortization of a deferred gain recorded in the first quarter of 2021.

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

Other income (expense) and equity earnings (losses) increased by $262 million from $2 million for the three months ended March 31, 2021 to $264 million for the three months ended March 31, 2022. The increase is primarily due to $252 million of favorable equity earnings, driven by a $246 million gain recognized in the current period from the offshore joint venture restructuring transaction in Renewables, a $6 million increase due to the write-off of certain development projects in Renewables in the first quarter of 2021, and $4 million in other increases in the period.

Interest Expense, Net of Capitalization

Interest expense for the three months ended March 31, 2022 and 2021 was $71 million and $73 million, respectively. The change is primarily due to a decrease of $2 million in interest expense driven by a favorable impact from the fair value hedge of the debt in Other.

Income Tax

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2022 was 13.7%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act and the equity component of allowance for funds used during construction, partially offset by the tax on gain from the offshore joint venture restructuring transaction, which is reflected in total in the first quarter as a discrete adjustment. The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2021 was 4.2%, which was 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.

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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, adjusted EBITDA and adjusted EBITDA with Tax Credits as 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 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 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. 

We define adjusted EBITDA as adjusted net income adjusted to fully exclude the effects of net (loss) income attributable to noncontrolling interests, income tax expense (benefit), depreciation and amortization, interest expense, net of capitalization, other (income) expense and (earnings) losses from equity method investments. We further define adjusted EBITDA with tax credits as adjusted EBITDA adding back the pre-tax effect of retained Production Tax Credits (PTCs) and Investment Tax Credits (ITCs) and PTCs allocated to tax equity investors. The most directly comparable U.S. GAAP measure to adjusted EBITDA and adjusted EBITDA with tax credits is net income.

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

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

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The following tables provide a reconciliation between Net Income attributable to AVANGRID and non-GAAP measures Adjusted Net Income, Adjusted EBITDA and Adjusted EBITDA with Tax Credits by segment for the three months ended March 31, 2022 and 2021, respectively:

	Three Months Ended March 31, 2022
	Total		Networks		Renewables		Corporate*
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	445	$	252	$	208	$	(15)
Adjustments:
Mark-to-market earnings – Renewables	3		—		3		—
Impact of COVID-19	2		2		—		—
Income tax impact of adjustments (1)	(2)		(1)		(1)		—
Adjusted Net Income (2)	$	450	$	254	$	211	$	(15)
Net (loss) income attributable to noncontrolling interests	(18)		1		(19)		—
Income tax expense (benefit)	70		32		42		(4)
Depreciation and amortization	261		161		100		—
Interest expense, net of capitalization	71		50		3		18
Other (income) expense	(11)		(12)		(1)		2
(Earnings) losses from equity method investments	(253)		(3)		(250)		—
Adjusted EBITDA (3)	$	569	$	482	$	85	$	2
Retained PTCs and ITCs	43		—		43		—
PTCs allocated to tax equity investors	29		—		29		—
Adjusted EBITDA with Tax Credits (3)	$	641	$	482	$	158	$	2

	Three Months Ended March 31, 2021
	Total		Networks		Renewables		Corporate*
	(in millions)
Net Income (Loss) Attributable to Avangrid, Inc.	$	334	$	225	$	108	$	1
Adjustments:
Mark-to-market earnings – Renewables	20		—		20		—
Impact of COVID-19	6		6		—		—
Income tax impact of adjustments (1)	(7)		(2)		(5)		—
Adjusted Net Income (2)	$	354	$	229	$	123	$	2
Net (loss) income attributable to noncontrolling interests	(13)		1		(14)		—
Income tax expense (benefit)	21		44		(4)		(19)
Depreciation and amortization	247		156		91		—
Interest expense, net of capitalization	73		53		—		20
Other (income) expense	(1)		(6)		6		(1)
(Earnings) losses from equity method investments	(1)		(2)		1		—
Adjusted EBITDA (3)	$	680	$	474	$	204	$	2
Retained PTCs and ITCs	50		—		50		—
PTCs allocated to tax equity investors	22		—		22		—
Adjusted EBITDA with Tax Credits (3)	$	752	$	474	$	276	$	2

(1)Income tax impact of adjustments: 2022 - $(1) million from MtM earnings and $(1) million from impact of COVID-19 for the three months ended March 31, 2022, respectively; 2021 - $(5) million from MtM earnings and $(2) million from impact of COVID-19 for the three months ended March 31, 2021, respectively.

(2)Adjusted Net Income is a non-GAAP financial measure and is presented after excluding costs incurred in connection with the COVID-19 pandemic and the impact from mark-to-market activities in Renewables.

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(3)Adjusted EBITDA is a non-GAAP financial measure defined as adjusted net income adjusted to fully exclude the effects of net (loss) income attributable to noncontrolling interests, income tax expense (benefit), depreciation and amortization, interest expense, net of capitalization, other (income) expense and (earnings) losses from equity method investments. We further define adjusted EBITDA with tax credits as adjusted EBITDA adding back the pre-tax effect of retained PTCs and ITCs and PTCs allocated to tax equity investors.

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

Three Months Ended March 31, 2022 Compared to Three Months Ended March 31, 2021

Adjusted net income

Our adjusted net income increased by $96 million, or 27%, from $354 million for the three months ended March 31, 2021 to $450 million for the three months ended March 31, 2022. The increase is primarily due to a $88 million increase in Renewables driven by a gain recognized in the current period from the offshore joint venture restructuring transaction, a $25 million increase in Networks driven primarily by rate increases in New York effective December 1, 2020, offset by $17 million decrease in Corporate mainly driven by unfavorable tax expense in the period.

The following tables reconcile Net Income attributable to AVANGRID to Adjusted Net Income (non-GAAP), and EPS attributable to AVANGRID to adjusted EPS (non-GAAP) for the three months ended March 31, 2022 and 2021, respectively:

	Three Months Ended
	March 31,
(Millions)	2022		2021
Networks	$	252	$	225
Renewables	208		108
Corporate (1)	(15)		1
Net Income	$	445	$	334
Adjustments:
Mark-to-market earnings - Renewables (2)	3		20
Impact of COVID-19 (3)	2		6
Income tax impact of adjustments	(2)		(7)
Adjusted Net Income (4)	$	450	$	354

	Three Months Ended
	March 31,
	2022		2021
Networks	$	0.65	$	0.73
Renewables	0.54		0.35
Corporate (1)	(0.04)		—
Net Income	$	1.15	$	1.08
Adjustments:
Mark-to-market earnings - Renewables (2)	0.01		0.07
Impact of COVID-19 (3)	0.01		0.02
Income tax impact of adjustments	—		(0.02)
Adjusted Earnings Per Share (4)	$	1.16	$	1.14

(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)Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions.

(4)Adjusted net income and adjusted earnings per share are non-GAAP financial measures and are presented after excluding 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

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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 and throughout the three months ended March 31, 2022.

Liquidity Position

We optimize our liquidity within the United States through a series of arms-length intercompany lending arrangements with our subsidiaries and among our 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 $3,575 million from the lenders committed to the AVANGRID 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 March 31, 2022 and December 31, 2021, respectively:

	As of March 31,		As of December 31,
	2022		2021
	(in millions)
Cash and cash equivalents	$	648	$	1,474
AVANGRID Credit Facility	3,575		3,575
Iberdrola Group Credit Facility	500		500
Less: borrowings	—		—
Total	$	4,723	$	5,549

AVANGRID Commercial Paper Program

AVANGRID has a commercial paper program with a limit of $2 billion that is backstopped by the AVANGRID Credit Facility (described below). As of both March 31, 2022 and April 28, 2022, there was $0 of commercial paper outstanding.

AVANGRID Credit Facility

AVANGRID and its subsidiaries, NYSEG, RG&E, CMP, UI, CNG, SCG and BGC, each of which are joint borrowers, have a revolving credit facility with a syndicate of banks, or the AVANGRID Credit Facility, that provides for maximum borrowings of up to $3,575 million in the aggregate, which was executed on November 23, 2021. The agreement contained a commitment from lenders, which expired on April 20, 2022 to increase maximum borrowings to $4,000 million upon the joinder of PNM and TNMP as borrowers under the AVANGRID Credit Facility.

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 November 23, 2021, the executed AVANGRID Credit Facility increased AVANGRID's maximum sublimit from $1,500 million to $2,500 million. The AVANGRID Credit Facility contains pricing that is sensitive to AVANGRID’s consolidated greenhouse gas emissions intensity. The Credit Facility also contains negative covenants, including one that sets the ratio of maximum allowed consolidated debt to consolidated total capitalization at 0.65 to 1.00, for each borrower. Under the AVANGRID Credit Facility, each of the borrowers will pay an annual facility fee that is dependent on their credit rating. The initial facility fees will range from 10 to 22.5 basis points. The maturity date for the AVANGRID Credit Facility is November 22, 2026. As of both March 31, 2022 and April 28, 2022, we had no borrowings outstanding under this credit facility.

Since the AVANGRID credit facility is also a backstop to the AVANGRID commercial paper program, the total amount available under the facility as of both March 31, 2022 and April 28, 2022 was $3,575 million.

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 March 31, 2022 and April 28, 2022, we had no borrowings outstanding under this credit facility.

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Capital Resources

On January 31, 2022, UI issued $150 million aggregate principal amount of unsecured notes maturing in 2032 at a fixed interest rate of 2.25%.

On April 6, 2022, NYSEG issued $67 million aggregate principal amount of Pollution Control Bonds maturing in 2028. The bonds bear a 4.00% fixed coupon and were priced at 104.15% to yield 3.3%.

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 $1.9 billion in capital expenditures through the remainder of 2022. This estimate is subject to continuing review and actual capital expenditures may vary significantly. For example, the U.S. Department of Commerce's anti-circumvention petition alleging that solar panels and cells shipped from Vietnam, Thailand, Malaysia and Cambodia could result in higher than expected costs for projects beyond 2022. As a result, the timing and ultimate cost associated with solar panels and cells and related project capital expenditures may vary from our current expectations.

Cash Flows

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

The following is a summary of the cash flows by activity for the three months ended March 31, 2022 and 2021, respectively:

	Three Months Ended
	March 31,
	2022		2021
	(in millions)
Net cash provided by operating activities	$	388	$	425
Net cash used in investing activities	(948)		(639)
Net cash used in financing activities	(266)		(436)
Net decrease in cash, cash equivalents and restricted cash	$	(826)	$	(650)

Operating Activities

The cash from operating activities for the three months ended March 31, 2022 compared to the three months ended March 31, 2021 decreased by $37 million, primarily attributable to a net decrease current assets and liabilities driven by timing of cash collections and cash disbursements during the period.

Investing Activities

For the three months ended March 31, 2022, net cash used in investing activities was $948 million, which was comprised of $811 million of capital expenditures and $168 million of payment for the offshore joint venture restructuring transaction, partially offset by $30 million of contributions in aid of construction.

For the three months ended March 31, 2021, net cash used in investing activities was $639 million, which was comprised of $623 million of capital expenditures and $39 million of other investments and equity method investments, partially offset by $9 million of contributions in aid of construction and $13 million of proceeds from the sale of assets and notes receivable from affiliates.

Financing Activities

For the three months ended March 31, 2022, financing activities used $266 million in cash reflecting primarily a net decrease in non-current debt and current notes payable of $101 million, distributions to non-controlling interests of $1 million and dividends of $170 million, offset by contribution from non-controlling interests of $13 million in the period.

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For the three months ended March 31, 2021, financing activities used $436 million in cash reflecting primarily a net decrease in non-current debt and current notes payable of $303 million, distributions to non-controlling interests of $3 million and dividends of $136 million, offset by contribution from non-controlling interests of $10 million in the period.

Off-Balance Sheet Arrangements

There have been no material changes in our off-balance sheet arrangements during the three months ended March 31, 2022 as compared to those reported for the fiscal year ended December 31, 2021 in our Form 10-K.

Contractual Obligations

There have been no material changes in contractual and contingent obligations during the three months ended March 31, 2022 as compared to those reported for the fiscal year ended December 31, 2021 in our Form 10-K.

Critical Accounting Policies and Estimates

We have prepared the accompanying condensed consolidated financial statements provided herein in accordance with U.S. GAAP. In preparing the accompanying condensed consolidated financial statements, our management has made certain estimates and assumptions that affect the reported amounts of assets, liabilities, stockholders’ equity, revenues and expenses and the disclosures thereof. While we believe that these policies and estimates used are appropriate, actual future events can and often do result in outcomes that can be materially different from these estimates. As of March 31, 2022, the only notable changes to the significant accounting policies described in our Form 10-K for the fiscal year ending December 31, 2021, are with respect to our adoption of the new accounting pronouncements described in the Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2022.

New Accounting Standards

We review new accounting standards to determine the expected financial effect, if any, that the adoption of each such standard will have. The new accounting pronouncements we have adopted as of January 1, 2022, and reflected in our condensed consolidated financial statements are described in Note 3 of our condensed consolidated financial statements for the three months ended March 31, 2022.

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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;

•the ability to recruit and retain a highly qualified and diverse workforce in the competitive labor market;

•changes in amount, timing or ability to complete capital projects;

•adverse developments in general market, business, economic, labor, regulatory and political conditions including, without limitation, the impacts of inflation, deflation, supply-chain interruptions and changing prices and labor costs, including the Department of Commerce's anti-circumvention petition that could adversely impact renewable solar energy projects;

•the impacts of climate change, fluctuations in weather patterns and extreme weather events;

•technological developments;

•the impact of extraordinary external events, such as any cyber breaches or other incidents, grid disturbances, acts of war or terrorism, civil or social unrest, natural disasters, pandemic health events or other similar occurrences, including the ongoing geopolitical conflict with Russia and Ukraine;

•the impact of any change to applicable laws and regulations, including those subject to referendums and legal challenges, affecting the ownership and operations of electric and gas utilities and renewable energy generation facilities, respectively, including, without limitation, those relating to the environment and climate change, taxes, price controls, regulatory approval and permitting;

•our ability to close the proposed Merger (as defined in "Note 1 - Background and Nature of Operations" to the accompanying unaudited condensed consolidated financial statements under Part I, Item 1 of this report), the anticipated timing and terms of the proposed Merger, our ability to realize the anticipated benefits of the proposed Merger and our ability to manage the risks of the proposed Merger;

•the COVID-19 pandemic, its impact on business and economic conditions, including but not limited to impacts from consumer payment behavior and supply chain delays, and the pace of recovery from the pandemic;

•the implementation of changes in accounting standards;

•adverse publicity or other reputational harm; and

•other presently unknown unforeseen factors.

Should one or more of these risks or uncertainties materialize, or should any of the underlying assumptions prove incorrect, actual results may vary in material respects from those expressed or implied by these forward-looking statements. You should not place undue reliance on these forward-looking statements. We do not undertake any obligation to update or revise any forward-looking statements to reflect events or circumstances after the date of this report, whether as a result of new information, future events or otherwise, except as may be required under applicable securities laws. Other risk factors are detailed from time to time in our reports filed with the SEC, and we encourage you to consult such disclosures.

Item 3. Quantitative and Qualitative Disclosures about Market Risk

There have been no material changes in our market risk during the three months ended March 31, 2022, as compared to those reported for the fiscal year ended December 31, 2021 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

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Report on Form 10-Q. Based on such evaluation, our CEO and CFO have concluded that as of such date, our disclosure controls and procedures were effective.

Changes in Internal Control

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

Limitations on Effectiveness of Controls and Procedures

In designing and evaluating the disclosure controls and procedures, management recognizes that any controls and procedures, no matter how well designed and operated, can provide only reasonable assurance of achieving the desired control objectives. In addition, the design of disclosure controls and procedures must reflect the fact that there are resource constraints 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, 2021. The only significant changes to our risk factors relate to following items:

There is a risk new tariffs imposed on imported goods could result in, among other items, increases in capital expenditures in projects, negative impacts of expected returns, impacts to the completion and delivery of projects, abandonment of the development on projects, which could have a material effect on AVANGRID's business, financial condition, and results of operations.

Changes in tariffs may affect the final cost of a significant portion of capital expenses in projects, with renewable projects being more exposed. Tariffs have been imposed in the recent years to imports of solar panels, aluminum and steel, among other goods or raw materials. Currently, the Department of Commerce, or DOC, is conducting an inquiry into an anti-circumvention petition alleging that solar panels and cells shipped from Vietnam, Thailand, Malaysia and Cambodia have circumvented tariffs imposed on Chinese solar panels and cells. The petition calls for anti-dumping and countervailing duties to be applied to solar panels and cells and could be retroactive to the filing date. If imposed, this tariff could affect, among other items, capital expenditures, expected returns on approved projects, completion and delivery of projects, and abandonment of the development on projects and associated contracts, including related costs.

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

AVANGRID’s operations are subject to, and influenced by, complex and comprehensive federal, state and local regulation and legislation. This is impactful for all areas of the business but particularly in the emerging development of offshore and solar generation. In late March, the House passed the Coast Guard Authorization Act of 2022. If enacted, the bill may only allow foreign vessels to operate on the Outer Continental Shelf if they have (a) a U.S. crew or (b) the crew of the nation of which the vessel is from. If passed, this legislation could affect expected timelines and returns on approved projects. Additionally, legislation seeking to block the import of products made with forced labor in certain areas of China could prevent some suppliers from importing, among other products, solar panels into the U.S. or cause significant delay in panel delivery. This legislation could have an impact on solar project development, construction activities and project returns.

Russian forces launched an invasion of Ukraine on February 24, 2022. This action could exacerbate existing risk factors highlighted in our Form 10-K for the fiscal year ended December 31, 2021.

The recent geopolitical developments may further intensify risk factors highlighted in our Form 10-K for the fiscal year ended December 31, 2021 including, but not limited to, risks around inflation, supply chain delays and heightened cybersecurity threats.

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

On April 27, 2022, Robert D. Kump, the President and Deputy Chief Executive Officer of the Company, provided notice of his intention to retire from the Company, effective June 24, 2022.

67

Item 6. Exhibits

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

Exhibit Number	Description
10.1	Form of Phantom Award Agreement.†
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.

68

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: April 29, 2022	By:	/s/ Dennis V. Arriola
		Dennis V. Arriola
		Director and Chief Executive Officer

Date: April 29, 2022	By:	/s/ Patricia C. Cosgel
		Patricia C. Cosgel
		Interim Chief Financial Officer

69

EX-10.1

EXHIBIT 10.1

AVANGRID, INC.

AMENDED AND RESTATED OMNIBUS INCENTIVE PLAN

PHANTOM SHARE UNIT GRANT NOTICE

Avangrid, Inc., a New York corporation (the "Company"), pursuant to its Amended and Restated Omnibus Incentive Plan, as amended from time to time (the "Plan"), hereby grants to the holder listed below ("Participant") the number of Phantom Share Units (the "Units") set forth below. The Units are subject to the terms and conditions set forth in this Phantom Share Unit Grant Notice (the "Grant Notice") and the Phantom Share Unit Agreement attached hereto as Exhibit A (the "Agreement") and the Plan, which are incorporated herein by reference. Unless otherwise defined herein, the terms defined in the Plan shall have the same defined meanings in the Grant Notice and the Agreement.

Participant:

Grant Date:

Number of Units:

Vesting Schedule:    The Units shall vest in four equal installments on [__________], [__________], [__________], and [__________], respectively, and will be settled in a cash amount equal to the number of Units multiplied by the Fair Market Value of the Company’s common shares on the respective vesting dates, provided that the Participant remains continuously employed with the Company or any of its Subsidiaries through such date. In addition, to the extent not previously forfeited, the Units shall also continue to vest upon (i) the Participant's death or termination of employment due to Disability, or (ii) Retirement with the consent of the Company, or (iii) termination of the Participant's employment by the Company without Cause or the Participant's resignation of employment for Good Reason, in either case following the occurrence of a Change in Control.

By his or her signature, and the Company's signature below, Participant agrees to be bound by the terms and conditions of the Plan, the Agreement and the Grant Notice. Participant has reviewed the Agreement, the Plan and the Grant Notice in their entirety, has had an opportunity to obtain the advice of counsel prior to executing the Grant Notice and fully understands all provisions of the Grant Notice, the Agreement and the Plan. Participant hereby agrees to acceptas binding, conclusive and final all decisions or interpretations of the Administrator upon any questionsarising under the Plan, the Grant Notice or the Agreement.

AVANGRID, INC.	PARTICIPANT
By: ______________________________________	By: ______________________________________
Print Name:	Print Name:
Title:	Title:

EXHIBIT A

TO PHANTOM SHARE UNIT GRANT NOTICE

PHANTOM SHARE UNITAGREEMENT

Pursuant to the Grant Notice to which this Agreement is attached, the Company has granted to Participant the number of Units set forth in the Grant Notice.

ARTICLE I. GENERAL

1.1Defined Terms. Capitalized terms not specifically defined herein shall have the meanings specified in the Plan or the Grant Notice.

1.2Incorporation of Terms of Plan. The Units to be issued to Participant hereunder are subject to the terms and conditions set forth in this Agreement and the Plan, which is incorporated herein by reference. In the event of any inconsistency between the Plan and this Agreement, the terms of the Plan shall control.

ARTICLE II

AWARD OF PHANTOM SHARE UNITS; RESTRICTIVE COVENANTS

2.1Award of Units. In consideration of Participant's past and/or continued employment with or service to the Company or any Subsidiary and for other good and valuable consideration, effective as of the grant date set forth in the Grant Notice (the "Grant Date"), the Company has granted to Participant the number of Units set forth in the Grant Notice, upon the terms and conditions set forth in the Grant Notice, the Plan and this Agreement, subject to adjustments as provided in Section 8 of the Plan. Each vested Unit will be settled in cash pursuant to the terms of Section 2.3, at the times and subject to the conditions set forth herein, subject to the provisions of Section 2.3(a). However, unless and until the Units have vested, Participant will have no right to the payment subject thereto. Prior to the actual delivery of any cash payment, the Units will represent an unsecured obligation of the Company, payable only from the general assets of the Company.

2.2Vesting of Units.

(a)Subject to Participant's continued employment with or service to the Company or a Subsidiary on each applicable vesting date and subject to the terms of this Agreement, the Units shall vest in such amounts and at such times as are set forth in the Grant Notice.

(b)In the event Participant incurs a Termination of Service, except as may be otherwise provided by the Administrator or as set forth in a written agreement between Participant and the Company, Participant shall immediately forfeit any and all Units granted under this Agreement which have not vested or do not vest on or prior to the date on which such Termination of Service occurs, and Participant's rights in any such Units which are not so vestedshall lapse and expire.

2.3Distribution or Payment.

(a)Participant's vested Units shall be settled in cash and paid in four equal cash payments calculated pursuant to Section 2.3(b), as soon as administratively practicable following the vesting of the applicable Units pursuant to Section 2.2, and, in any event, within sixty (60) days following such vesting. Notwithstanding the foregoing, the Company may delay a distribution or payment in settlement of Units if it reasonably determines that such payment or distribution will violate Federal securities laws or any other Applicable Law, provided that such distribution or payment shall be made at the earliest date at which the Company reasonably determines that the making of such distribution or payment will not cause such violation, as required by Treasury Regulation Section 1.409A-2(b)(7)(ii), and provided further that no payment shall be delayed under this Section 2.3(a) if such delay will result in a violation of Section 409A of the Code.

(b)The amount of cash payable with respect to each vested Unit shall be equal to the Fair Market Value of a Share on the vesting date set forth in the Grant Notice.

2.4Tax Withholding. Notwithstanding any other provision of this Agreement:

(a)The Company and its Subsidiaries have the authority to deduct or withhold, or require Participant to remit to the Company or the applicable Subsidiary, an amount sufficient to satisfy applicable federal, state, local and foreign taxes (including the employee portion of any FICA obligation) required by law to be withheld with respect to any taxable event arising pursuant to this Agreement. The Company and its Subsidiaries may withhold by the deduction of such amount from the cash payment payable to Participant as set forth in Section 2.3(a);

(b)Participant is ultimately liable and responsible for all taxes owed in connection with the Units, regardless of any action the Company or any Subsidiary takes with respect to any tax withholding obligations that arise in connection with the Units. Neither the Company nor any Subsidiary makes any representation or undertaking regarding the treatment of any tax withholding in connection with the awarding, vesting or payment of the Units. The Company and the Subsidiaries do not commit and are under no obligation to structure the Units to reduce or eliminate Participant's tax liability.

2.5Rights as Shareholder. Neither Participant nor any person claiming under or through Participant will have any of the rights or privileges of a Shareholder of the Company in respect of any Shares deliverable hereunder.

2.6Fair Market Value.“Fair Market Value” for the purposes of this Agreement and the Grant Notice means, as of any date, the value of Common Stock on such date as determined by such reasonable methods or procedures as may be established from time to time by the Administrator in accordance with the requirements of the Code and all Applicable Laws. Unless otherwise determined by the Administrator, the Fair Market Value of Common Stock shall be determined as follows: (i) if the Common Stock is listed on any established stock exchange, its Fair Market Value will be the closing sales price for such Common Stock as quoted on such exchange for such date, or if no sale occurred on such date, the last day preceding such date during which a sale occurred, as reported in The Wall Street Journal or another source the Administrator deems reliable; (ii) if the Common Stock is not traded on a stock exchange but is quoted on a national market or other quotation system, the closing sales price on such date, or if no sales occurred on such date, then on the last date preceding such date during which a sale occurred, as reported in The Wall Street Journal or another source the Administrator deems reliable; or (iii) without an established market for the Common Stock, the Administrator will determine the Fair Market Value in its discretion.

2.7Effect of a Change in Control.

(a)If a Change in Control occurs prior to a vesting date and the Participant’s employment status is terminated after the Change in Control Date but before the vesting date as a result of the Participant’s resignation for Good Reason or by the Corporation without Cause, then the Units granted hereunder will continue to vest.

(i)“Cause” means: (1) if the Participant is a party to an employment or service agreement with the Company or its Affiliates and such agreement provides for a definition of Cause, the definition contained therein; or (2) if no such agreement exists, or if such agreement does not define Cause: (i) the commission of, or plea of guilty or no contest to, a felony or a crime involving moral turpitude or the commission of any other act involving willful malfeasance or material fiduciary breach with respect to the Company or an Affiliate; (ii) conduct that results in or is reasonably likely to result in harm to the reputation or business of the Company or any of its Affiliates; (iii) gross negligence or willful misconduct with respect to the Company or an Affiliate; or (iv) material violation of state or federal securities laws. The Independent Compensation

Forum, in its absolute discretion, shall determine the effect of all matters and questions relating to whether a Participant has been discharged for Cause.

(ii)“Good Reason” means (1) if the Participant is a party to an employment or service agreement with the Company or its Affiliates and such agreement provides for a definition of Good Reason, the definition contained therein; or (2) if no such agreement exists or if such agreement does not define Good Reason, the occurrence of one or more of the following without the Participant’s express written consent, which circumstances are not remedied by the Company within thirty (30) days of its receipt of a written notice from the Participant describing the applicable circumstances (which notice must be provided by the Participant within ninety (90) days of the Participant’s knowledge of the applicable circumstances): (i) any material, adverse change in the Participant’s duties, responsibilities, authority, title, status or reporting structure; (ii) a material reduction in the Participant’s base salary or bonus opportunity; or (iii) a geographical relocation of the Participant’s principal office location by more than one hundred (100) miles.

ARTICLE III.

OTHER PROVISIONS

3.1Administration. The Administrator shall have the power to interpret the Plan, the Grant Notice and this Agreement and to adopt such rules for the administration, interpretation and application of the Plan, the Grant Notice and this Agreement as are consistent therewith and to interpret, amend or revoke any such rules. Allactions taken, and all interpretations and determinations made by the Administrator will be final and binding upon Participant, the Company and all other interested persons. To the extent allowable pursuant to Applicable Law, no member of the Committee or the Board will be personally liable for any action, determination or interpretation made with respect to the Plan, the Grant Notice or this Agreement.

3.2Units Not Transferable. The Units may not be sold, pledged, assigned or transferred in any manner other than by will or the laws of descent and distribution. No Units or any interest or right therein or part thereof shall be liable for the debts, contracts or engagements of Participant or his or her successors in interest or shall be subject to disposition by transfer, alienation, anticipation, pledge, encumbrance, assignment or any other means whether such disposition be voluntary or involuntary or by operation of law by judgment, levy, attachment, garnishment or any other legal or equitable proceedings (including bankruptcy), and any attempted disposition thereof shall be null and void and of no effect, except to the extent that such disposition is permitted by the preceding sentence.

3.3Adjustments. The Administrator may accelerate the vesting of all or a portion of the Units in such circumstances as it, in its sole discretion, may determine. Participant acknowledges that the Units are subject to adjustment, modification and termination in certain events as provided in this Agreement and Section 8 of the Plan.

3.4Titles. Titles are provided herein for convenience only and are not to serve as a basis for interpretation or construction of this Agreement.

3.5Governing Law, The laws of the State of New York shall govern the interpretation, validity, administration, enforcement and performance of the terms of this Agreement regardless of the law that might be applied under principles of conflicts of laws.

3.6Conformity toSecurities Laws. Participant acknowledges that the Plan, the Grant Notice and this Agreement are intended to conform to the extent necessary with all Applicable Laws, including, without limitation, the provisions of the Securities Act and the Exchange Act, and any and all regulations and rules promulgated thereunder by the Securities and Exchange Commission, and state securities laws and regulations. Notwithstanding anything herein to the contrary, the Plan shall be administered, and the Units are granted, only in such a manner as to conform to Applicable Law. To the extent permitted by Applicable Law, the Plan and this Agreement shall be deemed amended to the extentnecessary to conform to Applicable Law.

3.7Amendment, Suspension and Termination. To the extent permitted by the Plan, this Agreement may be wholly or partially amended or otherwise modified, suspended or terminated at any time or from time to time by the Administrator or the Board, provided that, except as may otherwise be provided by the Plan, no amendment, modification, suspension or termination of this Agreement shall adversely affect the Units in any material way without the prior written consent of Participant.

3.8Successors and Assigns. The Company may assign any of its rights under this Agreement to single or multiple assignees, and this Agreement shall inure to the benefit of thesuccessors and assigns of the Company. Subject to the restrictions on transfer set forth in Section 3.2 and the Plan, this Agreement shall be binding upon and inure to the benefit of the heirs, legatees, legal representatives, successors and assigns of the parties hereto.

3.9Limitations Applicable to Section 16 Persons. Notwithstanding any other provision of the Plan or this Agreement, if Participant is subject to Section 16 of the Exchange Act, the Plan, the Units (including Units which result from the deemed reinvestment of Dividend Equivalents), the Dividend Equivalents, the Grant Notice and this Agreement shall be subject to any additional limitations set forth in any applicable exemptive rule under Section 16 of the Exchange Act (including any amendment to Rule 16b-3 of the Exchange Act) that are requirements for the application of such exemptive rule. To the extent permitted by Applicable Law, this Agreement shall be deemed amended to the extent necessary to conform to such applicable exemptive rule.

3.10Not a Contract of Employment. Nothing in this Agreement or in the Plan shall confer upon Participant any right to continue to serve as an employee or other service provider of the Company or any Subsidiary or shall interfere with or restrict in any way the rights of the Company and its Subsidiaries, which rights are hereby expressly reserved, to discharge or terminate the services of Participant at any time for any reason whatsoever, with or without cause, except to the extent expressly provided otherwise in a written agreement between the Company or a Subsidiary and Participant.

3.11Entire Agreement. The Plan, the Grant Notice and this Agreement (including any exhibit hereto) constitute the entire agreement of the parties and supersede in their entirety all prior undertakings and agreements of the Company and Participant with respect to the subject matter hereof.

3.12Section 409A. This Award is not intended to constitute "nonqualified deferred compensation" within the meaning of Section 409A of the Code (together with any Department of Treasury regulations and other interpretive guidance issued thereunder, including without limitation any such regulations or other guidance that may be issued after the date hereof, "Section 409A"). However, notwithstanding any other provision of the Plan, the Grant Notice or this Agreement, if at any time the Administrator determines that this Award (or any portion thereof) may be subject to Section 409A, the Administrator shall have the right in its sole discretion (without any obligation to do so or to indemnify Participant or any other person for failure to do so) to adopt such amendments to the Plan, the Grant Notice or this Agreement, or adopt other policies and procedures (including amendments, policies and procedures with retroactive effect), or take any other actions, as the Administrator determines are necessary or appropriate for this Award either to be exempt from the application of Section 409A or to comply with the requirements of Section 409A.

3.13Limitation on Participant's Rights. Participation in the Plan confers no rights or interests other than as herein provided. This Agreement creates only a contractual obligation on the part of the Company as to amounts payable and shall not be construed as creating a trust. Neither the Plan nor any underlying program, in and of itself, has any assets. Participant shall have only the rights of a general unsecured creditor of the Company with respect to amounts credited and benefits payable, if any, with respect to the Units and Dividend Equivalents.

3.14Severability. The invalidity or unenforceability of any provision of the Plan, Grant Notice, or this Agreement shall not affect the validity or enforceability of any other provision of the Plan, Grant Notice, or this Agreement, and each provision of the Plan, Grant Notice, and this Agreement shall be severable and enforceable to the extent permitted by law.

3.15Counterparts. The Grant Notice may be executed in one or more counterparts, including by way of any electronic signature, subject to Applicable Law, each of which shall be deemed an original and all of which together shall constitute one instrument.

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Dennis V. Arriola, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Avangrid, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 29, 2022	/s/ Dennis V. Arriola
	Dennis V. Arriola
	Director and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Patricia C. Cosgel, certify that:

1. I have reviewed this quarterly report on Form 10-Q of Avangrid, Inc.;

2. Based on my knowledge, this report does not contain any untrue statement of a material fact or omit to state a material fact necessary to make the statements made, in light of the circumstances under which such statements were made, not misleading with respect to the period covered by this report;

3. Based on my knowledge, the financial statements, and other financial information included in this report, fairly present in all material respects the financial condition, results of operations and cash flows of the registrant as of, and for, the periods presented in this report;

4. The registrant’s other certifying officer and I are responsible for establishing and maintaining disclosure controls and procedures (as defined in Exchange Act Rules 13a-15(e) and 15d-15(e)) and internal control over financial reporting (as defined in Exchange Act Rules 13a-15(f) and 15d-15(f)) for the registrant and have:

a) Designed such disclosure controls and procedures, or caused such disclosure controls and procedures to be designed under our supervision, to ensure that material information relating to the registrant, including its consolidated subsidiaries, is made known to us by others within those entities, particularly during the period in which this report is being prepared;

b) Designed such internal control over financial reporting, or caused such internal control over financial reporting to be designed under our supervision, to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles;

c) Evaluated the effectiveness of the registrant’s disclosure controls and procedures and presented in this report our conclusions about the effectiveness of the disclosure controls and procedures, as of the end of the period covered by this report based on such evaluation; and

d) Disclosed in this report any change in the registrant’s internal control over financial reporting that occurred during the registrant’s most recent fiscal quarter (the registrant’s fourth fiscal quarter in the case of an annual report) that has materially affected, or is reasonably likely to materially affect, the registrant’s internal control over financial reporting; and

5. The registrant’s other certifying officer and I have disclosed, based on our most recent evaluation of internal control over financial reporting, to the registrant’s auditors and the audit committee of the registrant’s board of directors (or persons performing the equivalent functions):

a) All significant deficiencies and material weaknesses in the design or operation of internal control over financial reporting which are reasonably likely to adversely affect the registrant’s ability to record, process, summarize and report financial information; and

b) Any fraud, whether or not material, that involves management or other employees who have a significant role in the registrant’s internal control over financial reporting.

Date: April 29, 2022	/s/ Patricia C. Cosgel
	Patricia C. Cosgel
	Interim Chief Financial Officer

EX-32

EXHIBIT 32

CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

Pursuant to 18 U.S.C. Section 1350, the undersigned, Dennis V. Arriola and Patricia C. Cosgel, the Chief Executive Officer and Interim Chief Financial Officer, respectively, of Avangrid, Inc. (the “issuer”), do each hereby certify that the issuer’s quarterly report on Form 10-Q for the quarter ended March 31, 2022, to which this certification is attached as an exhibit (the “report”), fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)) and that information contained in the report fairly presents, in all material respects, the financial condition and results of operations of the issuer.

/s/ Dennis V. Arriola

Dennis V. Arriola

Director and Chief Executive Officer

Avangrid, Inc.

April 29, 2022

/s/ Patricia C. Cosgel

Patricia C. Cosgel

Interim Chief Financial Officer

Avangrid, Inc.

April 29, 2022

XML

Cover Page - shares	3 Months Ended
	Mar. 31, 2022	Apr. 28, 2022
Cover [Abstract]
Document Type	10-Q
Document Quarterly Report	true
Document Period End Date	Mar. 31, 2022
Document Transition Report	false
Entity File Number	001-37660
Entity Registrant Name	Avangrid, Inc.
Entity Incorporation, State or Country Code	NY
Entity Tax Identification Number	14-1798693
Entity Address, Address Line One	180 Marsh Hill Road
Entity Address, City or Town	Orange,
Entity Address, State or Province	CT
Entity Address, Postal Zip Code	06477
City Area Code	207
Local Phone Number	629-1190
Title of 12(b) Security	Common Stock, par value $0.01 per share
Trading Symbol	AGR
Security Exchange Name	NYSE
Entity Current Reporting Status	Yes
Entity Interactive Data Current	Yes
Entity Filer Category	Large Accelerated Filer
Entity Small Business	false
Entity Emerging Growth Company	false
Entity Shell Company	false
Entity Common Stock, Shares Outstanding		386,624,231
Amendment Flag	false
Document Fiscal Year Focus	2022
Document Fiscal Period Focus	Q1
Entity Central Index Key	0001634997
Current Fiscal Year End Date	--12-31

XML

Condensed Consolidated Statements of Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Income Statement [Abstract]
Operating Revenues	$ 2,133	$ 1,966
Operating Expenses
Purchased power, natural gas and fuel used	741	501
Operations and maintenance	651	642
Depreciation and amortization	261	247
Taxes other than income taxes	178	170
Total Operating Expenses	1,831	1,560
Operating Income	302	406
Other Income and (Expense)
Other income (expense)	11	1
Earnings from equity method investments	253	1
Interest expense, net of capitalization	(71)	(73)
Income Before Income Tax	495	335
Income tax expense	68	14
Net Income	427	321
Net loss attributable to noncontrolling interests	18	13
Net Income Attributable to Avangrid, Inc.	$ 445	$ 334
Earnings Per Common Share, Basic (in dollars per share)	$ 1.15	$ 1.08
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.15	$ 1.08
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	386,698,132	309,495,250
Diluted (in shares)	387,114,285	309,736,266

XML

Condensed Consolidated Statements of Comprehensive Income (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Net Income	$ 427	$ 321
Other Comprehensive Income (Loss)
Gain on nonqualified pension plans, net of income taxes of $3 and $0, respectively	9	0
Unrealized gain from equity method investment, net of income taxes of $5 and $0, respectively	15	0
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(15) and $(5), respectively	(39)	(27)
Reclassification to net income of loss on cash flow hedges, net of income taxes $4 and $(1), respectively	11	1
Other Comprehensive Income (Loss)	(4)	(26)
Comprehensive Income	423	295
Net loss attributable to noncontrolling interests	18	13
Comprehensive Income Attributable to Avangrid, Inc.	$ 441	$ 308

XML

Condensed Consolidated Statements of Comprehensive Income (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Comprehensive Income [Abstract]
Gain on nonqualified pension plans, taxes	$ 3	$ 0
Unrealized gain from equity method investment, taxes	5	0
Unrealized (loss) gain during the period on derivatives qualifying as cash flow hedges, tax	(15)	(5)
Reclassification to net income of losses on cash flow hedges, tax expense (benefit)	$ 4	$ (1)

XML

Condensed Consolidated Balance Sheets (unaudited) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Current Assets
Cash and cash equivalents	$ 648	$ 1,474
Accounts receivable and unbilled revenues, net	1,476	1,269
Accounts receivable from affiliates	4	11
Derivative assets	135	35
Fuel and gas in storage	91	139
Materials and supplies	217	204
Prepayments and other current assets	281	245
Regulatory assets	377	400
Total Current Assets	3,229	3,777
Total Property, Plant and Equipment ($1,941 and $1,959 related to VIEs, respectively)	29,719	28,866
Operating lease right-of-use assets	156	148
Equity method investments	434	560
Other investments	58	61
Regulatory assets	2,087	2,247
Other Assets
Goodwill	3,119	3,119
Intangible assets	289	293
Derivative assets	47	59
Other	403	374
Total Other Assets	3,858	3,845
Total Assets	39,541	39,504
Current Liabilities
Current portion of debt	281	372
Notes payable	33	159
Notes payable to affiliates	2	2
Interest accrued	86	69
Accounts payable and accrued liabilities	1,343	1,586
Accounts payable to affiliates	15	61
Dividends payable	340	170
Taxes accrued	76	43
Operating lease liabilities	10	12
Derivative liabilities	115	64
Other current liabilities	500	484
Regulatory liabilities	499	307
Total Current Liabilities	3,300	3,329
Regulatory liabilities	3,011	3,022
Other Non-current Liabilities
Deferred income taxes	2,125	2,016
Deferred income	1,113	1,130
Pension and other postretirement	473	684
Operating lease liabilities	143	149
Derivative liabilities	154	160
Asset retirement obligations	256	253
Environmental remediation costs	284	298
Other	589	580
Total Other Non-current Liabilities	5,137	5,270
Non-current debt	8,033	7,922
Total Non-current Liabilities	16,181	16,214
Total Liabilities	19,481	19,543
Commitments and Contingencies
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,734,757 and 387,678,630 shares issued; 386,624,231 and 386,568,104 shares outstanding, respectively	3	3
Additional paid in capital	17,683	17,679
Treasury stock	(47)	(47)
Retained earnings	1,819	1,714
Accumulated other comprehensive loss	(277)	(273)
Total Stockholders’ Equity	19,181	19,076
Non-controlling interests	879	885
Total Equity	20,060	19,961
Total Liabilities and Equity	$ 39,541	$ 39,504

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Condensed Consolidated Balance Sheets (unaudited) (Parenthetical) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Property, plant and equipment	$ 29,719	$ 28,866
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	500,000,000	500,000,000
Common stock, issued (in shares)	387,734,757	387,678,630
Common stock, outstanding (in shares)	386,624,231	386,568,104
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 1,941	$ 1,959

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Condensed Consolidated Statements of Cash Flows (unaudited) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Cash Flow from Operating Activities:
Net Income	$ 427	$ 321
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	261	247
Regulatory assets/liabilities amortization and carrying cost	2	21
Pension cost	8	17
Earnings from equity method investments	(253)	(1)
Distributions of earnings received from equity method investments	5	4
Unrealized loss on marked-to-market derivative contracts	3	53
Deferred taxes	51	(13)
Other non-cash items	0	(5)
Changes in operating assets and liabilities:
Current assets	(183)	(169)
Noncurrent assets	(127)	(93)
Current liabilities	196	39
Noncurrent liabilities	(2)	4
Net Cash Provided by Operating Activities	388	425
Cash Flow from Investing Activities:
Capital expenditures	(811)	(623)
Contributions in aid of construction	30	9
Proceeds from sale of assets	3	8
Proceeds from notes receivable from affiliates	0	5
Distributions received from equity method investments	2	1
Other investments and equity method investments, net	(172)	(39)
Net Cash Used in Investing Activities	(948)	(639)
Cash Flow from Financing Activities:
Non-current debt issuances	149	0
Repayments of non-current debt	(89)	(2)
Repayments of other short-term debt, net	(161)	(301)
Repayments of financing leases	(6)	(1)
Repurchase of common stock	0	(2)
Issuance of common stock	(1)	(1)
Distributions to noncontrolling interests	(1)	(3)
Contributions from noncontrolling interests	13	10
Dividends paid	(170)	(136)
Net Cash Used in Financing Activities	(266)	(436)
Net Decrease in Cash, Cash Equivalents and Restricted Cash	(826)	(650)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	1,477	1,467
Cash, Cash Equivalents and Restricted Cash, End of Period	651	817
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	55	51
Cash paid for income taxes	$ 5	$ 4

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Condensed Consolidated Statements of Changes in Equity (unaudited) - USD ($) $ in Millions		Total	Total Stockholders’ Equity	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Accumulated Other Comprehensive Loss	Noncontrolling Interests
Balance, beginning of period (in shares) at Dec. 31, 2020	[1]			309,077,300
Balance, beginning of period at Dec. 31, 2020		$ 15,826	$ 15,209	$ 3		$ 13,665	$ (14)	$ 1,666	$ (111)	$ 617
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		321	334					334		(13)
Other comprehensive loss, net of tax		(26)	(26)						(26)
Comprehensive Income		295
Dividends declared		(136)	(136)					(136)
Release of common stock held in trust (in shares)	[1]			292,594
Issuances of common stock (in shares)	[1]			53,311
Issuance of common stock		(1)	(1)			(1)
Repurchase of common stock (in shares)	[1]			(53,311)
Repurchase of common stock		(2)	(2)				(2)
Stock-based compensation		3	3			3
Distributions to noncontrolling interests		(3)								(3)
Contributions from noncontrolling interests		10								10
Balance, end of period (in shares) at Mar. 31, 2021	[1]			309,369,894
Balance, end of period at Mar. 31, 2021		$ 15,992	15,381	$ 3		13,667	(16)	1,864	(137)	611
Balance, beginning of period (in shares) at Dec. 31, 2021		386,568,104		386,568,104	[1]
Balance, beginning of period at Dec. 31, 2021		$ 19,961	19,076	$ 3		17,679	(47)	1,714	(273)	885
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income (loss)		427	445					445		(18)
Other comprehensive loss, net of tax		(4)	(4)						(4)
Comprehensive Income		423
Dividends declared		(340)	(340)					(340)
Issuances of common stock (in shares)	[1]			56,127
Issuance of common stock		(1)	(1)			(1)
Stock-based compensation		5	5			5
Distributions to noncontrolling interests		(1)								(1)
Contributions from noncontrolling interests		$ 13								13
Balance, end of period (in shares) at Mar. 31, 2022		386,624,231		386,624,231	[1]
Balance, end of period at Mar. 31, 2022		$ 20,060	$ 19,181	$ 3		$ 17,683	$ (47)	$ 1,819	$ (277)	$ 879

[1] (*) Par value of share amounts is $0.01

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Condensed Consolidated Statements of Changes in Equity (unaudited) (Parenthetical) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Statement of Stockholders' Equity [Abstract]
Other comprehensive loss, tax	$ (3)	$ (6)
Dividends declared (in dollars per share)	$ 0.44	$ 0.44
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01

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Background and Nature of Operations

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Background and Nature of Operations

Background and Nature of Operations

Avangrid, 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 81.6% of the outstanding common stock of AVANGRID. The remaining outstanding shares are owned by various shareholders with approximately 18.4% of AVANGRID's outstanding shares publicly-traded on the New York Stock Exchange (NYSE).

Proposed Merger with PNMR

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 is expected to 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 Federal Energy Regulatory Commission (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. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. The Statement of Issues was filed on February 2, 2022 and the Brief in Chief was filed on April 7, 2022. The Answer Brief is currently due on June 13, 2022, and the Reply Brief is currently due on July 5, 2022 (pending any extensions granted to the parties). In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which AVANGRID, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of AVANGRID and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by AVANGRID and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. We cannot predict the outcome of this proceeding for the outstanding approvals.

The Merger Agreement 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.

The Merger Agreement (as amended) 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 April 20, 2023 (subject to a three-month extension by AVANGRID and PNMR by mutual consent 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).

In connection with the Merger, Iberdrola 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.

On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which sets forth certain terms and conditions relating to the Iberdrola Funding Commitment Letter (the Side Letter Agreement). The Side Letter Agreement provides that any drawing in the form of indebtedness made by the Corporation pursuant to the Funding Commitment Letter shall bear interest at an interest rate equal to 3-month LIBOR plus 0.75% per annum calculated on the basis of a 360-day year for the actual number of days elapsed and, commencing on the date of the Funding Commitment Letter, we shall pay Iberdrola a facility fee equal to 0.12% per annum on the undrawn portion of the funding commitment set forth in the Funding Commitment Letter.

On May 18, 2021, we issued 77,821,012 shares of common stock in two private placements. Iberdrola purchased 63,424,125 shares and Hyde Member LLC, a Delaware limited liability company and a wholly owned subsidiary of Qatar Investment Authority, purchased 14,396,887 shares of our common stock, par value $0.01 per share, at the purchase price of $51.40 per share, which was the closing price of the shares of our common stock on the NYSE as of May 11, 2021. Proceeds of the private placements were $4,000 million. $3,000 million of the proceeds were used to repay the Iberdrola Loan. After the effect of the private placements, Iberdrola retained its 81.6% ownership interest in AVANGRID.

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Basis of Presentation

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Basis of Presentation

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, 2021.

The accompanying unaudited financial statements are prepared on a consolidated basis and include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts 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.

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 months ended March 31, 2022, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2022.

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Significant Accounting Policies and New Accounting Pronouncements

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Significant Accounting Policies and New Accounting Pronouncements

Significant Accounting Policies and New Accounting PronouncementsThe new accounting pronouncements we have adopted as of January 1, 2022, 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, 2021, except for those described below resulting from the adoption of new authoritative accounting guidance issued by the Financial Accounting Standards Board (FASB).

Adoption of New Accounting Pronouncements

(a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification

In March 2020, the FASB issued amendments and created ASC 848 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.

In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.

We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect our consolidated results of operations, financial position and cash flows.

(b) Disclosures by business entities about government assistance

In November 2021, the FASB issued amendments that apply to business entities (all entities except specified not-for-profit entities and employee benefit plans) that account for a transaction with a government by applying a grant or contribution accounting model by analogy to other accounting guidance (such as a grant model within International Accounting Standards 20 Accounting for Government Grants and Disclosure of Government Assistance, or ASC Subtopic 958-605, Not-For-Profit Entities—Revenue Recognition). Government assistance can include tax credits (excluding transactions within the scope of Topic 740, Income Taxes), cash grants, grants of other assets, and project grants. Often, government assistance is provided to an entity for a particular purpose, and the entity promises to take specific actions. Transactions with a government, as used in ASC 832, Government Assistance, include assistance administered by domestic, foreign, local (city, town, county, municipal), regional (state, provincial, territorial), and national (federal) governments and entities related to those governments. The amendments require annual disclosures in notes to financial statements about transactions with a government as follows: (1) information about the nature of the transactions and the related accounting policy used to account for the transactions, (2) the line items on the balance sheet and income statement affected by the transactions, and the amounts applicable to each financial statement line item, and (3) significant terms and conditions of the transactions, including commitments and contingencies. For entities within scope the amendments are effective for annual periods beginning after December 15, 2021, with early application permitted. The amendments are to be applied either (1) prospectively to transactions within the scope of the amendments that are reflected in financial statements at the date of initial application and new transactions that are entered into after the date of initial application or (2) retrospectively to those transactions. Our adoption of the amendments on January 1, 2022 did not materially affect our disclosures.

(c) Fair Value Hedging – Portfolio Layer Method

In March 2022, the FASB issued amendments to ASC 815 to provide additional guidance on hedge accounting. The update expands the current last-layer method that permits only one hedged layer to allow multiple hedged layers of a single closed portfolio. To reflect that expansion, the last-of-layer method is renamed the portfolio layer method. It also specifies that eligible hedging instruments in a single-layer hedge may include spot-starting or forward-starting constant notional or amortizing

notional swaps. It also provides additional guidance on the accounting for and disclosure of hedge basis adjustments that are applicable to the portfolio layer method.

The amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. Early adoption is permitted on any date on or after the issuance date. We have elected to early apply the amendments effective April 1, 2022. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows.

Accounting Pronouncements Issued but Not Yet Adopted

The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2021, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Troubled Debt Restructurings and Vintage Disclosures

In March 2022, the FASB issued amendments to ASC 326 to provide guidance for troubled debt restructurings (TDRs) and vintage disclosures. For TDRs, the update requires entities to measure and record lifetime expected credit losses on an asset that is within scope of Topic 326. The prior guidance in Topic 310 of designating a loan as a TDR was considered unnecessarily complex. For vintage disclosures, the amendments require an entity to disclose current-period gross write-offs by year of origination for financing receivables and net investments in leases within the scope of Subtopic 326-20.

The amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively, except as provided in the next sentence. For the transition method related to the recognition of TDRs, an entity has the option to apply a modified retrospective transition method, resulting in a cumulative-effect adjustment to retained earnings in the period of adoption. Early adoption is permitted.

We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.

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Revenue

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Revenue

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. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. 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 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.

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 or a percentage 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 2022 upon commercial operation. Contract assets totaled $9 million at both March 31, 2022 and December 31, 2021, 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 $8 million and $16 million at March 31, 2022 and December 31, 2021, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $8 million and $4 million as revenue during the three months ended March 31, 2022 and 2021, respectively.

Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2022 and 2021 are as follows:

	Three Months Ended March 31, 2022
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,170	$	—	$	—	$	1,170
Regulated operations – natural gas	721		—		—		721
Nonregulated operations – wind	—		220		—		220
Nonregulated operations – solar	—		7		—		7
Nonregulated operations – thermal	—		13		—		13
Other(a)	22		16		—		38
Revenue from contracts with customers	1,913		256		—		2,169
Leasing revenue	3		—		—		3
Derivative losses	—		(63)		—		(63)
Alternative revenue programs	12		—		—		12
Other revenue	7		5		—		12
Total operating revenues	$	1,935	$	198	$	—	$	2,133

	Three Months Ended March 31, 2021
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	942	$	—	$	—	$	942
Regulated operations – natural gas	564		—		—		564
Nonregulated operations – wind	—		371		—		371
Nonregulated operations – solar	—		4		—		4
Nonregulated operations – thermal	—		12		—		12
Other(a)	10		32		—		42
Revenue from contracts with customers	1,516		419		—		1,935
Leasing revenue	2		—		—		2
Derivative losses	—		(31)		—		(31)
Alternative revenue programs	47		—		—		47
Other revenue	8		5		—		13
Total operating revenues	$	1,573	$	393	$	—	$	1,966

(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 March 31, 2022 and December 31, 2021, accounts receivable balances related to contracts with customers were approximately $1,433 million and $1,220 million, respectively, including unbilled revenues of $402 million and $405 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

As of March 31, 2022, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of March 31, 2022	2023		2024		2025		2026		2027		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	1	$	1	$	—	$	—	$	—	$	—	$	2
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	18		14		12		10		7		60		121
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	27		17		6		4		1		1		56
Total operating revenues	$	46	$	32	$	18	$	14	$	8	$	61	$	179

As of March 31, 2022, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2022 was $46 million.

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Regulatory Assets and Liabilities

3 Months Ended

Mar. 31, 2022

Regulated Operations [Abstract]

Regulatory Assets and Liabilities

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. As of March 31, 2022, the total net amount of these items is approximately $867 million.

CMP Distribution 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 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. Commencing on 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 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order.

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 customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. We cannot predict the outcome of this investigation.

NYSEG and RG&E Rate Plans

On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG & RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. 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 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. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed earnings sharing mechanism, the equity ratio is the lower of the actual equity ratio or 50.00%. The below table provides a summary of the approved 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	4.6	%	$	46	5.9	%	$	36	4.2	%
NYSEG Gas	$	—	—	%	$	2	0.8	%	$	3	1.6	%
RG&E Electric	$	17	3.8	%	$	14	3.2	%	$	16	3.3	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2	1.3	%

UI, CNG, SCG and BGC Rate Plans

In 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, among other things, provide for annual tariff increases and an ROE of 9.10% based on a 50.00% 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 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018. The new tariffs also include an RDM and Distribution Integrity Management Program (DIMP) mechanism, 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 an equity ratio of approximately 52.00%. 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 2018, PURA approved new tariffs for Connecticut Natural Gas Corporation (CNG) effective January 1, 2019 for a three-year rate plan with annual rate increases. 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.

In 2019, the Massachusetts Department of Public Utilities (DPU) approved new distribution rates for Berkshire Gas Company (BGC). The distribution rate increase is based on a 9.70% ROE and 54.00% 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. BGC expects to file an application to amend its distribution rates in the first half of 2022. We cannot predict the outcome of this proceeding.

Connecticut Energy 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 for certain penalties and reimbursements to customers after storm outages greater than 96 hours and extends rate case timelines.

Pursuant to the legislation, on October 30, 2020, PURA re-opened a docket related to new rate designs and review, expanding the scope to consider (a) the implementation of an interim rate decrease; (b) low-income rates; and (c) economic development rates. Separately, UI was due to make its annual RAM filing on March 8, 2021 for the approval of its RAM Rate Components reconciliations: Generation Services Charges, By-passable Federally Mandated Congestion Costs, System Benefits Charge, Transmission Adjustment Charge and RDM.

On March 9, 2021, UI, jointly with the Office of the CT Attorney General, the Office of CT Consumer Counsel, DEEP and PURA’s Office of Education, Outreach, and Enforcement entered into a settlement agreement and filed a motion to approve the settlement agreement, which addressed issues in both dockets.

In an order dated June 23, 2021, PURA approved the as amended settlement agreement in its entirety and it was executed by the parties. The settlement agreement includes a contribution by UI of $5 million and provides customers rate credits of $50 million while allowing UI to collect $52 million in RAM, all over a 22-month period ending April 2023 and also includes a distribution base rate freeze through April 2023.

Pursuant to the legislation, PURA opened a docket to consider the implementation of the associated customer compensation and reimbursement provisions in emergency events where customers were without power for more than 96 consecutive hours. On June 30, 2021, PURA issued a final decision implementing the legislative mandate to create a program pursuant to which residential customers will receive $25 for each day without power after 96 hours and also receive reimbursement of $250 for spoiled food and medicine. The decision emphasizes that no costs incurred in connection with this program are recoverable from customers. The Company is reviewing the requirements of this program and evaluating next steps.

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

On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.

On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. We cannot predict the outcome of these appeals.

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.

Regulatory assets as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Pension and other post-retirement benefits cost deferrals	$	322	$	545
Pension and other post-retirement benefits	96		95
Storm costs	502		448
Rate adjustment mechanism	61		68
Revenue decoupling mechanism	59		68
Transmission revenue reconciliation mechanism	13		15
Contracts for differences	69		73
Hardship programs	25		24
Plant decommissioning	2		2
Deferred purchased gas	10		52
Deferred transmission expense	8		13
Environmental remediation costs	251		256
Debt premium	70		71
Unamortized losses on reacquired debt	22		23
Unfunded future income taxes	444		424
Federal tax depreciation normalization adjustment	141		142
Asset retirement obligation	20		20
Deferred meter replacement costs	49		46
COVID-19 cost recovery	19		21
Other	281		241
Total regulatory assets	2,464		2,647
Less: current portion	377		400
Total non-current regulatory assets	$	2,087	$	2,247

“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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“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 unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases.

“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” 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.

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

“Plant decommissioning” represents decommissioning and demolition expenses related to closing fossil plant facilities - Beebe & Russell.

“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 forty-six 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 25 to 35 years and for CMP 32.5 years beginning in 2020.

“Asset retirement obligations” 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 or are planned to be replaced by AMI 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.

Regulatory liabilities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Energy efficiency portfolio standard	$	43	$	45
Gas supply charge and deferred natural gas cost	35		7
Pension and other post-retirement benefits cost deferrals	71		73
Carrying costs on deferred income tax bonus depreciation	20		23
Carrying costs on deferred income tax - Mixed Services 263(a)	6		7
2017 Tax Act	1,310		1,327
Rate Change Levelization	100		99
Revenue decoupling mechanism	20		13
Accrued removal obligations	1,201		1,192
Asset sale gain account	—		2
Economic development	26		26
Positive benefit adjustment	21		22
Theoretical reserve flow thru impact	6		6
Deferred property tax	19		22
Net plant reconciliation	15		16
Debt rate reconciliation	46		49
Rate refund – FERC ROE proceeding	35		35
Transmission congestion contracts	25		23
Merger-related rate credits	11		12
Accumulated deferred investment tax credits	23		24
Asset retirement obligation	18		18
Earning sharing provisions	15		13
Middletown/Norwalk local transmission network service collections	17		17
Low income programs	28		25
Non-firm margin sharing credits	17		15
New York 2018 winter storm settlement	5		5
Hedge gains	98		19
Other	279		194
Total regulatory liabilities	3,510		3,329
Less: current portion	499		307
Total non-current regulatory liabilities	$	3,011	$	3,022

“Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount 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 three years and began in 2020.

"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 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. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“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 through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

"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 three years and began in 2020.

“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.

"Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer 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 2020.

"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 in current rates is three years for NYSEG and two years for RG&E and began in 2020.

“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 three years and began in 2020.

“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 three years and began in 2020.

“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 three to five years and began in 2020.

"Deferred property tax" represents the difference between actual expense for property taxes recoverable from customers and the amount provided for 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 2020.

"Net plant reconciliation" represents the reconciliation of the actual electric and gas net plant and book depreciation to the targets set forth in the 2020 Joint Proposal. 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 2020.

"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 the Nine Mile 2 Nuclear Plant transmission congestion contract at RG&E. 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 2020.

“Merger-related rate credits” resulted from the acquisition of UIL. This is being used to moderate increases in rates. During both the three months ended March 31, 2022 and 2021, $1 million of rate credits were applied against customer bills.

"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 earnings sharing threshold. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

"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 NYPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. The balance is being amortized through current rates over an amortization period of three years, beginning in 2020.

“Hedge gains” represents the deferred fair value gains on electric and gas hedge contracts.

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

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Fair Value of Financial Instruments and Fair Value Measurements

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments and Fair Value Measurements

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, fixed income 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. NYSEG and RG&E hedge up to approximately 55% of its forecasted winter demand through the use of financial transactions and storage withdrawals. 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 Intercontinental Exchange (ICE). We include the fair value measurements in Level 1 because we use prices quoted in an active market.

•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 New York Mercantile Exchange (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 interest rate derivative instruments based on a model whose inputs are observable, such as the London Interbank Offered Rate (LIBOR) forward interest rate curves. We include the fair value measurement for these contracts in Level 2 (See Note 12 for further discussion of interest rate contracts).

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.

The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value.

Restricted cash was $3 million as of both March 31, 2022 and December 31, 2021, respectively and is included in "Other Assets" on our condensed consolidated balance sheets.

The financial instruments measured at fair value as of March 31, 2022 and December 31, 2021, respectively, consisted of:

As of March 31, 2022	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	36	$	17	$	—	$	—	$	53
Derivative assets
Derivative financial instruments - power	$	89	$	49	$	104	$	(79)	$	163
Derivative financial instruments - gas	13		65		4		(67)		15
Contracts for differences	—		—		2		—		2
Total	$	102	$	114	$	112	$	(146)	$	182
Derivative liabilities
Derivative financial instruments - power	$	(5)	$	(206)	$	(163)	$	243	$	(131)
Derivative financial instruments - gas	—		(38)		(2)		35		(5)
Contracts for differences	—		—		(71)		—		(71)
Derivative financial instruments – Other	—		(62)		—		—		(62)
Total	$	(5)	$	(306)	$	(236)	$	278	$	(269)

As of December 31, 2021	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	45	$	15	$	—	$	—	$	60
Derivative assets
Derivative financial instruments - power	$	31	$	39	$	85	$	(78)	$	77
Derivative financial instruments - gas	4		34		9		(32)		15
Contracts for differences	—		—		2		—		2
Total	$	35	$	73	$	96	$	(110)	$	94
Derivative liabilities
Derivative financial instruments - power	$	(16)	$	(137)	$	(90)	$	176	$	(67)
Derivative financial instruments - gas	(1)		(22)		—		18		(5)
Contracts for differences	—		—		(75)		—		(75)
Derivative financial instruments - Other	—		(77)		—		—		(77)
Total	$	(17)	$	(236)	$	(165)	$	194	$	(224)

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2022 and 2021, respectively, is as follows:

	Three Months Ended March 31,
(Millions)	2022		2021
Fair Value Beginning of Period,	$	(69)	$	13
Gains recognized in operating revenues	38		11
(Losses) recognized in operating revenues	(40)		(4)
Total gains recognized in operating revenues	(2)		7
Gains recognized in OCI	2		1
(Losses) recognized in OCI	(63)		(17)
Total gains (losses) recognized in OCI	(61)		(16)
Net change recognized in regulatory assets and liabilities	4		1
Purchases	(1)		—
Settlements	5		(4)
Fair Value as of March 31,	$	(124)	$	1
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)	$	7

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 March 31, 2022
Index	Avg.		Max.		Min.
NYMEX ($/MMBtu)	$	3.58	$	6.52	$	2.27
AECO ($/MMBtu)	$	2.69	$	5.69	$	1.53
Ameren ($/MWh)	$	38.09	$	93.59	$	18.01
COB ($/MWh)	$	50.49	$	231.90	$	9.15
ComEd ($/MWh)	$	34.53	$	86.32	$	14.98
ERCOT N hub ($/MWh)	$	39.26	$	140.00	$	13.66
ERCOT S hub ($/MWh)	$	37.80	$	140.00	$	13.88
Indiana hub ($/MWh)	$	40.20	$	93.81	$	20.74
Mid C ($/MWh)	$	47.52	$	229.90	$	5.15
Minn hub ($/MWh)	$	34.61	$	90.99	$	15.23
NoIL hub ($/MWh)	$	34.30	$	84.00	$	14.64
PJM W hub ($/MWh)	$	39.84	$	113.93	$	17.78

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 uncontracted wind positions. The power swaps are used to hedge uncontracted wind production in the West and Midwest.

We considered the measurement uncertainty regarding 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 uncontracted generation, with decreases in gas prices resulting in unrealized gains and increases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.

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

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

The determination of fair value of the CfDs (see Note 7 for further details on CfDs) was based on a probability-based expected cash flow analysis that was discounted at risk-free interest rates, as applicable, and an adjustment for non-performance risk using credit default swap rates. Certain management assumptions were required, including development of pricing that 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	March 31, 2022
Risk of non-performance	0.56% - 0.67%
Discount rate	2.42% - 2.45%
Forward pricing ($ per KW-month)	$2.00 - $4.63

Fair Value of Debt

As of March 31, 2022 and December 31, 2021, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $8,495 million and $9,155 million as of March 31, 2022 and December 31, 2021, 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.

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Derivative Instruments and Hedging

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging

Derivative Instruments and Hedging

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

(a) Networks activities

The tables below present Networks' derivative positions as of March 31, 2022 and December 31, 2021, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:

As of March 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	98	$	7	$	—	$	4
Derivative liabilities	—		(4)		(15)		(61)
	98		3		(15)		(57)
Designated as hedging instruments
Derivative assets	1		—		—		—
Derivative liabilities	—		—		—		—
	1		—		—		—
Total derivatives before offset of cash collateral	99		3		(15)		(57)
Cash collateral receivable	—		—		—		1
Total derivatives as presented in the balance sheet	$	99	$	3	$	(15)	$	(56)

As of December 31, 2021	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	29	$	7	$	12	$	4
Derivative liabilities	(12)		(4)		(27)		(64)
	17		3		(15)		(60)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		—
	—		—		(1)		—
Total derivatives before offset of cash collateral	17		3		(16)		(60)
Cash collateral receivable	—		—		—		—
Total derivatives as presented in the balance sheet	$	17	$	3	$	(16)	$	(60)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,	December 31,
As of	2022	2021
(Millions)
Wholesale electricity purchase contracts (MWh)	5.3	5.7
Natural gas purchase contracts (Dth)	8.4	9.4
Fleet fuel purchase contracts (Gallons)	1.4	2.0

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 our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations.

The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2022 and December 31, 2021 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2022 and 2021 are as follows:

(Millions)	Loss or Gain Recognized in Regulatory Assets/Liabilities				Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As of						Three Months Ended March 31,
March 31, 2022	Electricity		Natural Gas		2022	Electricity		Natural Gas
Regulatory assets	$	1	$	—	Purchased power, natural gas and fuel used	$	(45)	$	(9)
Regulatory liabilities	$	(85)	$	(13)
December 31, 2021					2021
Regulatory assets	$	—	$	—	Purchased power, natural gas and fuel used	$	2	$	(1)
Regulatory liabilities	$	(16)	$	(3)

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

PURA has determined that costs associated with these CfDs will be fully recoverable by UI and CL&P through electric rates, and UI has deferred recognition of costs (a regulatory asset) or obligations (a regulatory liability), including carrying costs. For those CfDs signed by CL&P, UI records its approximate 20% portion pursuant to the cost-sharing agreement noted above. As of March 31, 2022, 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 $69 million, a gross derivative liability of $71 million ($68 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, 2021, 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 $73 million, a gross derivative liability of $75 million ($72 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2022 and 2021, respectively, were as follows:

	Three Months Ended March 31,
	2022		2021
(Millions)
Derivative assets	$	—	$	—
Derivative liabilities	$	4	$	1

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	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)
2022
Interest rate contracts	$	—	Interest expense	$	1	$	71
Commodity contracts	2		Purchased power, natural gas and fuel used	(1)		741
Foreign currency exchange contracts	—			—
Total	$	2		$	—
2021
Interest rate contracts	$	—	Interest expense	$	1	$	73
Commodity contracts	1		Purchased power, natural gas and fuel used	—		501
Foreign currency exchange contracts	(4)			—
Total	$	(3)		$	1

(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 $46 million and $47 million as of March 31, 2022 and December 31, 2021, respectively. For both the three months ended March 31, 2022 and 2020, Networks recorded net derivative losses related to discontinued cash flow hedges of $1 million. Networks will amortize approximately $3 million of discontinued cash flow hedges for the remainder of 2022.

Unrealized gains of $2 million on hedge derivatives are reported in OCI because the forecasted transactions are considered to be probable as of March 31, 2022. Networks expects $1 of those gains will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months.

(b) Renewables activities

Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its 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 March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,	December 31,
As of	2022	2021
(MWh/Dth in millions)
Wholesale electricity purchase contracts	4	4
Wholesale electricity sales contracts	9	10
Natural gas and other fuel purchase contracts	13	20
Financial power contracts	8	9
Basis swaps – purchases	25	30
Basis swaps – sales	1	—

The fair values of derivative contracts associated with Renewables' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Wholesale electricity purchase contracts	$	85	$	36
Wholesale electricity sales contracts	(162)		(77)
Natural gas and other fuel purchase contracts	—		6
Financial power contracts	22		35
Total	$	(55)	$	—

On May 27, 2021, Renewables entered into a forward interest rate swap, with a total notional amount of $935 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As part of the financial close of Vineyard Wind 1 described in Note 19, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of March 31, 2022 and December 31, 2021, the fair value of the interest rate swap was $2 million and $58 million, respectively, as a non-current liability. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred.

The tables below present Renewables' derivative positions as of March 31, 2022 and December 31, 2021, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:

As of March 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	53	$	65	$	89	$	12
Derivative liabilities	(17)		(21)		(115)		(12)
	36		44		(26)		—
Designated as hedging instruments
Derivative assets	—		—		2		2
Derivative liabilities	—		—		(141)		(105)
	—		—		(139)		(103)
Total derivatives before offset of cash collateral	36		44		(165)		(103)
Cash collateral (payable) receivable	—		—		69		62
Total derivatives as presented in the balance sheet	$	36	$	44	$	(96)	$	(41)

As of December 31, 2021	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	29	$	70	$	52	$	9
Derivative liabilities	(11)		(14)		(65)		(11)
	18		56		(13)		(2)
Designated as hedging instruments
Derivative assets	—		—		5		6
Derivative liabilities	—		—		(67)		(142)
	—		—		(62)		(136)
Total derivatives before offset of cash collateral	18		56		(75)		(138)
Cash collateral payable	—		—		27		57
Total derivatives as presented in the balance sheet	$	18	$	56	$	(48)	$	(81)

Derivatives not designated as hedging instruments

The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2022, consisted of:

	Three Months Ended March 31, 2022
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	9	$	3
Wholesale electricity sales contracts	(1)		(40)
Financial power contracts	(2)		(21)
Financial and natural gas contracts	(1)		(25)
Total gain (loss) included in operating revenues	$	5	$	(83)	$	2,133
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	37
Financial power contracts	—		1
Financial and natural gas contracts	—		37
Total gain included in purchased power, natural gas and fuel used	$	—	$	75	$	741
Total Gain (Loss)	$	5	$	(8)

The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2021, consisted of:

	Three Months Ended March 31, 2021
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	7	$	—
Wholesale electricity sales contracts	—		(17)
Financial power contracts	(5)		(16)
Financial and natural gas contracts	—		(4)
Total gain (loss) included in operating revenues	$	2	$	(37)	$	1,966
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	10
Financial power contracts	—		1
Financial and natural gas contracts	—		4
Total loss included in purchased power, natural gas and fuel used	$	—	$	15	$	501
Total Gain (Loss)	$	2	$	(22)

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of (Gain) Reclassified from Accumulated OCI into Income	(Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2022
Commodity contracts	$	(112)	Operating revenues	$	11	$	2,133
2021
Commodity contracts	$	(28)	Operating revenues	$	(3)	$	1,966

(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 $137 million of losses included in accumulated OCI at March 31, 2022, 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 months ended March 31, 2022 and 2021.

(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.

As of March 31, 2022 and December 31, 2021, the net loss in accumulated OCI related to previously settled interest rate contracts was $46 million and $48 million, respectively. For both the three months ended March 31, 2022 and 2021, we amortized into income $2 million of the loss related to settled interest rate contracts. We will amortize approximately $7 million of the net loss on the interest rate contracts for the remainder of 2022.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	(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)
2022
Interest rate contracts	$	—	Interest expense	$	2	$	71
2021
Interest rate contracts	$	—	Interest expense	$	2	$	73

(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 which end in 2025 and 2029.

On July 15, 2021, Corporate entered into an interest rate swap to hedge the fair value of $750 million of existing debt included in "Non-current debt" on our consolidated balance sheets. The interest rate swap is designated and qualifies as a fair value hedge. The change in the fair value of the interest rate swap and the offsetting change in the fair value of the underlying debt are reported as components of "Interest expense."

The effects on our consolidated financial statements as of and for the three months ended March 31, 2022 and 2021 are as follows:

	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
(Millions)	As of March 31, 2022			Three Months Ended March 31, 2022
Current Liabilities	$	(4)	Interest Expense	$	(2)	$	71
Non-current liabilities	$	(57)
	Cumulative effect on hedged debt
Current debt	$	4
Non-current debt	$	57

	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
(Millions)	As of December 31, 2021			Three Months Ended March 31, 2021
Current Assets	$	—	Interest Expense	$	—	$	73
Non-current liabilities	$	(19)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	19

(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 ratings on senior debt were to fall below investment grade. If such an event had occurred as of March 31, 2022, UI would have had to post an aggregate of approximately $20 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. As of March 31, 2022 and December 31, 2021, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $82 million and $67 million, respectively. Derivative instruments settlements and collateral payments are included throughout the “Changes in operating assets and liabilities” section of operating activities in our condensed consolidated statements of cash flows.

Certain of our derivative instruments contain provisions that require us to maintain an investment grade credit rating on our debt from each of the major credit rating agencies. If our debt were to fall below investment grade, we would be in violation of those provisions and the counterparties to the derivative instruments could request immediate payment or demand immediate and ongoing full overnight collateralization on derivative instruments in net liability positions. The aggregate fair value of all derivative instruments with credit risk related contingent features that are in a liability position as of March 31, 2022 was $1 million, for which we have posted collateral.

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Contingencies and Commitments

3 Months Ended

Mar. 31, 2022

Commitments and Contingencies Disclosure [Abstract]

Contingencies and Commitments

Contingencies and Commitments

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 probable and can be reasonably estimated. We do not provide for accrual of legal costs expected to be incurred in connection with a loss contingency.

Transmission - ROE Complaint – CMP and UI

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

On October 16, 2014, the FERC issued its decision in Complaint I, setting the base ROE at 10.57% and a maximum total ROE of 11.74% (base plus incentive ROEs) for the October 2011 – December 2012 period as well as prospectively from October 16, 2014. On March 3, 2015, the FERC upheld its decision and further clarified that the 11.74% ROE cap will be applied on a project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners.

CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $27 million and $8 million, respectively, as of March 31, 2022, which has not changed since December 31, 2021, 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. On November 19, 2020, FERC issued an order addressing arguments raised on rehearing of its May 21, 2020 order making minor adjustments to certain typographical errors with regard to some of the case inputs it included in its Risk Premium model analysis. However, those minor adjustments did not affect the outcome of the case, leaving the 10.02% ROE established by the May 21, 2020 order in place. Parties to these orders affecting the MISO transmission owners’ base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO’s submitted an amici curia brief in support of the MISO transmission owners’ on March 17, 2021. 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.

On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (Supplemental NOPR) that proposes to eliminate the 50 basis-point ROE incentive for utilities who join Regional Transmission Organizations after three years of membership. The NETOs submitted initial comments in opposition to the Supplemental NOPR on June 25, 2021 and reply comments on July 26, 2021. If the elimination of the 50 basis-point ROE incentive adder becomes final, we estimate we would have an approximately $3 million reduction in earnings per year. We cannot predict the outcome of this proceeding.

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. 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. On June 17, 2021, the FERC issued an Order Establishing Limited Remand remanding the case to the administrative law judge for additional detailed findings and legal analysis with respect to the impact of the conduct of one of the parties other than Renewables on their long-term contracts. The order did not address any of the other findings, including all of the findings with respect to Renewables, which remain pending. There is no specific timetable for the administrative law judge’s ruling. On July 9, 2021, Renewables filed a motion requesting that the FERC expeditiously issue a final decision with respect to the Renewables long-term contract rather than waiting for the administrative law judge’s ruling. We cannot predict the outcome of this proceeding.

New York State Public Service Commission Show Cause Order Regarding Greenlight Pole Attachments

On November 20, 2020, the NYPSC issued an Order Instituting Proceeding and to Show Cause (the Show Cause Order) regarding alleged violations of the NYPSC’s 2004 Order Adopting Policy Statement on Pole Attachments, dated August 6, 2004 (the 2004 Pole Order) by RG&E, Greenlight Networks, Inc, (Greenlight), and Frontier Communications (Frontier). The alleged violations detailed in the Show Cause Order arise from Greenlight’s installation of unauthorized and substandard communications attachments throughout RG&E’s and Frontier’s service territories. The Show Cause Order directs RG&E to show cause within 30 days why the NYPSC should not pursue civil and/or administrative penalties or initiate a prudency proceeding or civil action for injunctive relief for more than 11,000 alleged violations of the 2004 Pole Order. Under NY Public Service Law Section 25-a, each alleged violation carries a potential penalty of up to $100,000 where it can be shown that the violator failed to “reasonably comply” with a statute or NYPSC order.

RG&E, Greenlight and Frontier filed respective notices to initiate settlement negotiations with respect to the alleged violations and to extend the deadline for filing a response to the Show Cause Order. The NYPSC granted the extension requests initiating settlement discussions. On or about August 12, 2021, the NYPSC approved a settlement entered into by NYDPS and RG&E providing for, among other things, RG&E’s payment of $3 million, which will be used to support the State of New York’s broadband initiative for underserved areas. This settlement amount could increase to a maximum of $5 million if RG&E does not resolve certain identified safety violations caused by Greenlight’s pole attachments on or before December 31, 2021. We have met all compliance requirements of the settlement and filed the final compliance statement with the NYPSC on January 12, 2022.

Beatrice Corwin Living Irrevocable Trust, by and through Its Authorized Trustee, Robert Corwin v. Iberdrola, S.A., et. al.

On January 8, 2021, the Beatrice Corwin Living Irrevocable Trust, by and through its Authorized Trustee, Robert Corwin filed a complaint in the Supreme Court of the State of New York Westchester County against Iberdrola and the members of the Company’s Board of Directors, as defendants, and the Company, as a nominal defendant with respect to certain counts contained in the complaint. The complaint alleges certain violations of fiduciary duties by Iberdrola and the members of the Company’s Board of Directors related to the existence of certain pre-emptive rights provided to Iberdrola in the Shareholder Agreement between the Company and Iberdrola, dated December 16, 2015, and the binding nature of such rights. On March 29, 2021, the parties stipulated to and requested, and the Supreme Court of the State of New York Westchester County issued an Order providing for, the transfer of the venue of the complaint to the Supreme Court, County of New York. On May 20, 2021, the matter was transferred to New York County and assigned to the Commercial Division of the Supreme Court, County of New York. On September 3, 2021, the plaintiffs filed an amended verified complaint (i) dropping claims concerning the purported breach of AVANGRID’s articles of incorporation and New York’s statute concerning equal treatment among shareholders, (ii) adding and modifying their claims related to the duty of good faith and loyalty and (iii) adding allegations concerning the Iberdrola Loan and the May 2021 private placement of our common shares to Iberdrola and Hyde Partners, LLC. In addition, the plaintiffs are now purporting to bring a class action lawsuit. On October 22, 2021, we and our board of directors filed a motion to dismiss and Iberdrola filed a motion to dismiss and an application to stay discovery pending resolution of dispositive motions. On December 8, 2021, the plaintiffs filed an omnibus opposition to the motions to dismiss and the defendants' filed a reply to such motion on January 14, 2022. On March 17, 2022, the Court heard oral arguments and at the conclusion of the hearing granted the defendants' motion to dismiss.

Guarantee Commitments to Third Parties

As of March 31, 2022, we had approximately $488 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including $4 million related to Vineyard Wind. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind as described in Note 19, which is in addition to the amounts above. These instruments provide financial assurance to the business and trading partners of AVANGRID, its subsidiaries and equity method investees in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of March 31, 2022, neither we nor our subsidiaries have any liabilities recorded for these instruments.

NECEC Commitments

On January 4, 2021, CMP transferred the New England Clean Energy Connect, or NECEC, project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks. Among other things, NECEC Transmission LLC and/or CMP committed to approximately $90 million of future payments to support various programs in the state of Maine, of which approximately $9 million was paid through the end of 2021. In December 2021 the remaining future payments were suspended following the halt in construction of the NECEC project.

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Environmental Liabilities

3 Months Ended

Mar. 31, 2022

Environmental Remediation Obligations [Abstract]

Environmental Liabilities

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 $7 million related to eleven of the twenty-six sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation 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. As of March 31, 2022, our estimate for costs to remediate these sites ranges from $14 million to $22 million. 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; and three sites are part of Maine’s Voluntary Response Action Program with two such sites part of Maine’s Uncontrolled Sites Program. The remaining sites are not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.

As of March 31, 2022, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $160 million to $273 million. 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; as of March 31, 2022, no liability was recorded related to these sites 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 both March 31, 2022 and December 31, 2021, the liability associated with our MGP sites in Connecticut was $113 million, 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.

As of March 31, 2022 and December 31, 2021, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $300 million and $303 million, 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 2081.

FirstEnergy

NYSEG and RG&E each sued FirstEnergy under the Comprehensive Environmental Response, Compensation, and Liability Act to recover environmental cleanup costs at certain former MGP sites, which are included in the discussion above. In 2011, the District Court issued a decision and order in NYSEG’s favor, which was upheld on appeal, requiring FirstEnergy to pay NYSEG for past and future clean-up costs at the sixteen sites in dispute. In 2008, the District Court issued a decision and order in RG&E's favor requiring FirstEnergy to pay RG&E for past and future clean-up costs at the two MGP sites in dispute. FirstEnergy remains liable for a substantial share of clean up expenses at the MGP sites. Based on projections as of March 31, 2022, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $14 million and $7 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable.

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, and oral arguments have taken place. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. The plaintiffs filed a petition to appeal to the Connecticut Supreme Court, which was denied, leaving only the claim against UI for unjust enrichment. 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 continued its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order.

As of March 31, 2022 and December 31, 2021, the amount reserved related to English Station was $21 million and $22 million, respectively. Since inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of this matter.

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Post-retirement and Similar Obligations

3 Months Ended

Mar. 31, 2022

Retirement Benefits [Abstract]

Post-retirement and Similar Obligations

Post-retirement and Similar Obligations

We made no pension contributions for the three months ended March 31, 2022. We expect to make additional contributions of $23 million for the remainder of 2022.

The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2022 and 2021, respectively, consisted of:

	Three Months Ended March 31,
	2022		2021
(Millions)
Service cost	$	8	$	10
Interest cost	24		22
Expected return on plan assets	(45)		(50)
Amortization of:
Prior service costs	1		—
Actuarial loss	18		35
Curtailments and settlements	2		—
Net Periodic Benefit Cost	$	8	$	17

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2022 and 2021, respectively, consisted of: 

	Three Months Ended March 31,
	2022		2021
(Millions)
Service cost	$	1	$	1
Interest cost	3		2
Expected return on plan assets	(2)		(2)
Amortization of:
Prior service costs	—		(2)
Actuarial loss	(1)		1
Net Periodic Benefit Cost	$	1	$	—

In March 2022 the AVANGRID board approved plan amendments to freeze pension benefit accruals and contribution credits for Networks non-union employees effective June 30, 2022. The balance sheet impact from these amendments was a reduction in pension liabilities and regulatory assets of approximately $200 million at March 31, 2022. The plan changes resulted in a curtailment charge of $2 million. Our expected rate of return on assets (EROA) was updated for certain plans based on our de-risking glide-path model. This approach reduces investment risk as the plan’s funded status improves, resulting in our weighted average EROA for 2022 declining from 6.3% used in the first quarter calculation of pension costs to 5.9%, which will be used for the remainder of the year.

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Equity

3 Months Ended

Mar. 31, 2022

Equity [Abstract]

Equity

Equity

As of both March 31, 2022 and December 31, 2021, we had 112,543 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2022 and 2021, we released 0 and 292,594 shares of common stock held in trust, respectively.

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 81.6%. The stock repurchase program may be suspended or discontinued at any time upon notice. As of March 31, 2022, a total of 997,983 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 $47 million as of March 31, 2022.

Accumulated Other Comprehensive Loss 

Accumulated Other Comprehensive Loss for the three months ended March 31, 2022 and 2021, respectively, consisted of:

	As of December 31,		Three Months Ended March 31,		As of March 31,		As of December 31,		Three Months Ended March 31,		As of March 31,
	2021		2022		2022		2020		2021		2021
(Millions)
Change in revaluation of defined benefit plans	$	(10)	$	—	$	(10)	$	(12)	$	—	$	(12)
(Loss) gain on nonqualified pension plans, net of income tax expense of $3 for 2022	(28)		9		(19)		(20)		—		(20)
Unrealized (loss) gain from equity method investment, net of income tax expense of $5 for 2022 (a)	(9)		15		6		—		—		—
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(15) for 2022 and $(5) for 2021	(194)		(39)		(233)		(35)		(27)		(62)
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $4 for 2022 and $(1) for 2021 (b)	(32)		11		(21)		(44)		1		(43)
Loss on derivatives qualifying as cash flow hedges	(226)		(28)		(254)		(79)		(26)		(105)
Accumulated Other Comprehensive Loss	$	(273)	$	(4)	$	(277)	$	(111)	$	(26)	$	(137)

(a)    Foreign currency and interest rate contracts.

(b)    Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

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Earnings Per Share

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding. During the three months ended March 31, 2022 and 2021, 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 months ended March 31, 2022 and 2021, respectively, consisted of:

	Three Months Ended March 31,
	2022		2021
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	445	$	334
Denominator:
Weighted average number of shares outstanding - basic	386,698,132		309,495,250
Weighted average number of shares outstanding - diluted	387,114,285		309,736,266
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	1.15	$	1.08
Earnings Per Common Share, Diluted	$	1.15	$	1.08

On March 30, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on July 1, 2022 to shareholders of record at the close of business on June 4, 2022.

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Segment Information

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Segment Information

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 nine rate regulated operating segments. These operating segments generally offer the same services distributed in similar fashions, have the same types of customers, have similar long-term economic characteristics and are subject to similar regulatory requirements, allowing these operations to be aggregated into one reportable segment.

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

The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments 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 months ended March 31, 2022, consisted of:

Three Months Ended March 31, 2022	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,935	$	198	$	—	$	2,133
Depreciation and amortization	161		100		—		261
Operating income	319		(18)		1		302
Earnings from equity method investments	3		250		—		253
Interest expense, net of capitalization	50		3		18		71
Income tax expense (benefit)	31		41		(4)		68
Adjusted net income	254		211		(15)		450
Capital expenditures	355		454		2		811
As of March 31, 2022
Property, plant and equipment	18,882		10,825		12		29,719
Equity method investments	149		285		—		434
Total assets	$	26,329	$	12,747	$	465	$	39,541

(a) Includes Corporate and intersegment eliminations.

Segment information for the three months ended March 31, 2021 and as of December 31, 2021, consisted of:

Three Months Ended March 31, 2021	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,573	$	393	$	—	$	1,966
Depreciation and amortization	156		91		—		247
Operating income	313		92		1		406
Earnings (losses) from equity method investments	2		(1)		—		1
Interest expense, net of capitalization	53		—		20		73
Income tax expense (benefit)	42		(9)		(19)		14
Adjusted net income	229		123		2		354
Capital expenditures	531		92		—		623
As of December 31, 2021
Property, plant and equipment	18,737		10,118		11		28,866
Equity method investments	148		412		—		560
Total assets	$	26,126	$	12,578	$	800	$	39,504

(a) Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2022 and 2021, respectively, is as follows:

	Three Months Ended March 31,
	2022		2021
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	450	$	354
Adjustments:
Mark-to-market earnings - Renewables (1)	(3)		(20)
Impact of COVID-19 (2)	(2)		(6)
Income tax impact of adjustments	2		7
Net Income Attributable to Avangrid, Inc.	$	445	$	334

(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)     Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions.

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Related Party Transactions

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Related Party Transactions

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

Related party transactions for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	2022				2021
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(12)	$	—	$	(13)
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(3)	$	—	$	(2)
Vineyard Wind	$	2	$	—	$	4	$	—
Iberdrola Solutions	$	—	$	—	$	7	$	(38)
Other	$	—	$	(1)	$	1	$	(1)

Related party balances as of March 31, 2022 and December 31, 2021, respectively, consisted of:

As of	March 31, 2022				December 31, 2021
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	2	$	(10)	$	3	$	(43)
Iberdrola Financiación, S.A.	$	—	$	(2)	$	—	$	(9)
Vineyard Wind	$	2	$	(8)	$	8	$	(8)
Iberdrola Solutions	$	—	$	(2)	$	—	$	(2)
Other	$	—	$	(3)	$	—	$	(1)

Transactions with Iberdrola 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.

We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable balance of $2 million as both March 31, 2022 and December 31, 2021. Renewables also has financial forward power contracts with Iberdrola Solutions to hedge Renewables' merchant wind exposure in Texas.

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.

AVANGRID optimizes its liquidity position as part of the Iberdrola Group and is a party to a liquidity agreement with a financial institution, along with certain members of the Iberdrola Group. Cash surpluses remaining after meeting the liquidity requirements of AVANGRID and its subsidiaries may be deposited at the financial institution. Deposits, or credit balances, serve as collateral against the debit balances of other parties to the liquidity agreement. The balance at both March 31, 2022 and December 31, 2021, was $0.

AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of March 31, 2022 and December 31, 2021, there was no outstanding amount under this credit facility.

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

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Other Financial Statement Items

3 Months Ended

Mar. 31, 2022

Balance Sheet Related Disclosures [Abstract]

Other Financial Statement Items

Other Financial Statement Items

Accounts receivable and unbilled revenue, net

Accounts receivable and unbilled revenues, net as of March 31, 2022 and December 31, 2021 consisted of:

As of	March 31, 2022		December 31, 2021
(Millions)
Trade receivables and unbilled revenues	$	1,629	$	1,420
Allowance for credit losses	(153)		(151)
Accounts receivable and unbilled revenues, net	$	1,476	$	1,269

The change in the allowance for credit losses for the three months ended March 31, 2022 and 2021 consisted of:

	Three Months Ended March 31,
(Millions)	2022		2021
As of Beginning of Period,	$	151	$	108
Current period provision	20		39
Write-off as uncollectible	(18)		(12)
As of March 31,	$	153	$	135

The Deferred Payment Arrangements (DPA) receivable balance was $112 million and $108 million at March 31, 2022 and December 31, 2021, respectively. The allowance for credit losses for DPAs at March 31, 2022 and December 31, 2021 was $71 million and $68 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2022 and 2021, was $3 million and $5 million, respectively.

Prepayments and other current assets

Included in prepayments and other current assets are $120 million and $95 million of prepaid other taxes as of March 31, 2022 and December 31, 2021, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of March 31, 2022 and December 31, 2021, respectively, were as follows:

	March 31,		December 31,
As of	2022		2021
(Millions)
Property, plant and equipment
Accumulated depreciation	$	10,830	$	10,589
Intangible assets
Accumulated amortization	$	321	$	317

Debt

Long-term debt issuance

On January 31, 2022, UI issued $150 million aggregate principal amount of unsecured notes maturing in 2032 at a fixed interest rate of 2.25%.

Supplier Financing Arrangements

We operate a supplier financing arrangement. We arranged for the extension of payment terms with some suppliers, which could elect to be paid by a financial institution earlier than maturity under supplier financing arrangements. Due to the interest cost associated with these arrangements, the balances are classified as "Notes payable" on our consolidated balance sheets. The balance relates to capital expenditures and, therefore, is treated as non-cash activity, and is reported under financing activity of the consolidated statement of cash flows when the balance is paid. As of March 31, 2022 and December 31, 2021, the amount of notes payable under supplier financing arrangements was $35 million and $161 million, respectively. As of March 31, 2022 and December 31, 2021, the weighted average interest rate on the balance was 2.08% and 0.82%, respectively.

Other current liabilities

Included in other current liabilities are $178 million and $204 million of advances received as of March 31, 2022 and December 31, 2021, respectively.

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Income Tax Expense	3 Months Ended
	Mar. 31, 2022
Income Tax Disclosure [Abstract]
Income Tax Expense	Income Tax ExpenseThe effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2022, was 13.7%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production, the effect of the excess deferred tax amortization resulting from the Tax Act and the equity component of allowance for funds used during construction, partially offset by the tax on gain from the offshore joint venture restructuring transaction (see Note 19 for further details on the transaction), which is reflected in total in the first quarter as a discrete adjustment.The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2021, was 4.2%, 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.

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Stock-Based Compensation Expense

3 Months Ended

Mar. 31, 2022

Share-based Payment Arrangement [Abstract]

Stock-Based Compensation Expense

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).

Performance Stock Units

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 March 2022, 46,737 shares of common stock were issued to settle the third and final installment payment under this plan.

During March 2022, 17,501 additional PSUs were granted to certain officers and employees of AVANGRID. The PSUs will vest upon achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and will be payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.22 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date.

Restricted Stock Units

In January 2022, 17,500 RSUs were granted to an officer of AVANGRID with immediate vesting. The fair value on the grant date was determined based on a price of $48.16 per share. The RSU grant was settled, net of applicable taxes, by issuing 9,390 shares of common stock.

Phantom Share Units

In March 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards 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 March 2022, $2 million was paid to settle the third and final installment under this plan.

In February 2022, 9,000 Phantom Shares were granted to certain AVANGRID executives and employees. These awards vest in three equal installments in 2022 - 2024 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.

As of March 31, 2022 and December 31, 2021, the total liability was $0 and $2 million, respectively, which is included in other current and non-current liabilities.

The total stock-based compensation expense, which is included in "Operations and maintenance" in our condensed consolidated statements of income, for the three months ended March 31, 2022 and 2021, was $5 million and $4 million, respectively.

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Variable Interest Entities

3 Months Ended

Mar. 31, 2022

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

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.

The assets and liabilities of the VIEs totaled approximately $2,006 million and $91 million, respectively, at March 31, 2022. As of December 31, 2021, the assets and liabilities of VIEs totaled approximately $2,039 million and $119 million, respectively. At March 31, 2022 and December 31, 2021, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.

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.

At March 31, 2022, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus VII and Aeolus VIII are our consolidated VIEs.

Our El Cabo, Patriot, Aeolus VII and Aeolus VIII 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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Equity Method Investments

3 Months Ended

Mar. 31, 2022

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investments

Equity Method Investments

Renewables holds a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners (CIP). Prior to a restructuring transaction that took place on January 10, 2022, Vineyard Wind held acquired easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. The first easement area acquired was Lease Area 501 which contains 166,886 acres located southeast of Martha's Vineyard. Lease Area 501 was subsequently divided in 2021 creating Lease Area 534. In 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm (Vineyard Wind 1) and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. The Vineyard Wind 1 project will be located on Lease Area 501.

In December 2019, the Park City Wind project was selected and approved to provide 804 MW of offshore wind in Connecticut. In December 2021, the Commonwealth Wind project was selected to provide 1,232 MW of offshore wind primarily through contracts with the electric distribution companies in Massachusetts, subject to final regulatory approvals. Both projects are located in Lease Area 534.

Vineyard Wind acquired a second offshore easement contract from BOEM (Lease Area 522). Renewables initially contributed $100 million to Vineyard Wind to acquire the easement contract, which was proportionally more than CIP's contribution. Pursuant to a joint bidding agreement between Renewables and CIP, CIP had the option to reimburse Renewables an amount, plus interest, to restore its 50% interest in the easement contract. In December 2020, CIP exercised this option and reimbursed Renewables $33 million, plus interest.

On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Among other items, the Vineyard Wind 1 project was transferred into a separate joint venture with Vineyard Wind 1 Pledgor LLC as the top holding company, which Renewables holds a 50% voting interest. Concurrently, Renewables entered into a credit agreement with certain banks to provide future term loans and letters of credit up to a maximum of approximately $1.2 billion to finance a portion of its share of the cost of Vineyard Wind 1 at the maturity of the Vineyard Wind 1 project construction loan. Any term loans mature by October 15, 2031, subject to certain extension provisions. Renewables also entered into an Equity Contribution Agreement in which Renewables agreed to, among other things, make certain equity contributions to fund certain costs of developing and constructing the Vineyard Wind 1 project in accordance with the credit agreement. In addition, we issued a guaranty up to $827 million for Renewables' equity contributions under the Equity Contribution Agreement. As part of the Vineyard Wind 1 financial close, $152 million of Renewables prior contributions for the Vineyard Wind 1 project were returned.

On September 15, 2021, Renewables entered into a restructuring agreement with CIP with respect to Vineyard Wind. The restructuring closed on January 10, 2022 and effectively dissolved Vineyard Wind. As part of the restructuring, Renewables acquired full ownership of Park City Wind LLC containing Lease Area 534, including the Park City Wind project and Commonwealth Wind project in Lease Area 534, and CIP acquired OCS-A 0522 LLC containing Lease Area 522. Immediately following Vineyard Wind's dissolution of interests in Park City Wind LLC and OCS-A 0522 LLC, Vineyard Wind solely provides construction and management services to Vineyard Wind 1, which are outsourced to third party service providers, and no longer owns the rights to any lease areas, and therefore no longer has substantive operations. As part of the restructuring and effective dissolution, Renewables received a liquidating distribution and made an incremental payment of approximately $168 million to CIP. Consequently, Renewables recognized a pretax gain of $246 million and an after tax gain of $181 million, driven by the increase in the market value of its acquired interest in the leases and related development activities over its carrying value. The gain is classified in Earnings from equity method investments in the condensed consolidated statement of income.

Vineyard Wind 1 Pledgor LLC is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. As of March 31, 2022 and December 31, 2021, the carrying amount of Renewables' investments in Vineyard Wind LLC and Vineyard Wind 1 Pledgor LLC was $15 million and $141 million, respectively.

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Subsequent Event

3 Months Ended

Mar. 31, 2022

Subsequent Events [Abstract]

Subsequent Event

Subsequent Event

On April 6, 2022, NYSEG issued $67 million aggregate principal amount of Pollution Control Bonds maturing in 2028. The bonds bear a 4.00% fixed coupon and were priced at 104.15% to yield 3.3%.

On April 29, 2022, we closed on a TEF agreement, receiving $14 million from a tax equity investor related to the Lund Hill solar farm that reached partial mechanical completion on the same date. A further investment from our investor is expected shortly after the project’s commercial operations in the amount of $58 million, expected in August. Lund Hill will be owned by Solis Power I, LLC.

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Significant Accounting Policies and New Accounting Pronouncements (Policies)

3 Months Ended

Mar. 31, 2022

Accounting Policies [Abstract]

Adoption of New Accounting Pronouncements and Accounting Pronouncements Issued but Not Yet Adopted

Adoption of New Accounting Pronouncements

(a) Facilitation of the effects of reference rate reform on financial reporting, and subsequent scope clarification

In March 2020, the FASB issued amendments and created ASC 848 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.

In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments are effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.

We expect our adoption of reference rate reform and the subsequent scope clarification will not materially affect our consolidated results of operations, financial position and cash flows.

(b) Disclosures by business entities about government assistance

In November 2021, the FASB issued amendments that apply to business entities (all entities except specified not-for-profit entities and employee benefit plans) that account for a transaction with a government by applying a grant or contribution accounting model by analogy to other accounting guidance (such as a grant model within International Accounting Standards 20 Accounting for Government Grants and Disclosure of Government Assistance, or ASC Subtopic 958-605, Not-For-Profit Entities—Revenue Recognition). Government assistance can include tax credits (excluding transactions within the scope of Topic 740, Income Taxes), cash grants, grants of other assets, and project grants. Often, government assistance is provided to an entity for a particular purpose, and the entity promises to take specific actions. Transactions with a government, as used in ASC 832, Government Assistance, include assistance administered by domestic, foreign, local (city, town, county, municipal), regional (state, provincial, territorial), and national (federal) governments and entities related to those governments. The amendments require annual disclosures in notes to financial statements about transactions with a government as follows: (1) information about the nature of the transactions and the related accounting policy used to account for the transactions, (2) the line items on the balance sheet and income statement affected by the transactions, and the amounts applicable to each financial statement line item, and (3) significant terms and conditions of the transactions, including commitments and contingencies. For entities within scope the amendments are effective for annual periods beginning after December 15, 2021, with early application permitted. The amendments are to be applied either (1) prospectively to transactions within the scope of the amendments that are reflected in financial statements at the date of initial application and new transactions that are entered into after the date of initial application or (2) retrospectively to those transactions. Our adoption of the amendments on January 1, 2022 did not materially affect our disclosures.

(c) Fair Value Hedging – Portfolio Layer Method

In March 2022, the FASB issued amendments to ASC 815 to provide additional guidance on hedge accounting. The update expands the current last-layer method that permits only one hedged layer to allow multiple hedged layers of a single closed portfolio. To reflect that expansion, the last-of-layer method is renamed the portfolio layer method. It also specifies that eligible hedging instruments in a single-layer hedge may include spot-starting or forward-starting constant notional or amortizing

notional swaps. It also provides additional guidance on the accounting for and disclosure of hedge basis adjustments that are applicable to the portfolio layer method.

The amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. Early adoption is permitted on any date on or after the issuance date. We have elected to early apply the amendments effective April 1, 2022. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows.

Accounting Pronouncements Issued but Not Yet Adopted

The following are new accounting pronouncements not yet adopted, including those issued since December 31, 2021, that we have evaluated or are evaluating to determine their effect on our condensed consolidated financial statements.

(a) Troubled Debt Restructurings and Vintage Disclosures

In March 2022, the FASB issued amendments to ASC 326 to provide guidance for troubled debt restructurings (TDRs) and vintage disclosures. For TDRs, the update requires entities to measure and record lifetime expected credit losses on an asset that is within scope of Topic 326. The prior guidance in Topic 310 of designating a loan as a TDR was considered unnecessarily complex. For vintage disclosures, the amendments require an entity to disclose current-period gross write-offs by year of origination for financing receivables and net investments in leases within the scope of Subtopic 326-20.

The amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively, except as provided in the next sentence. For the transition method related to the recognition of TDRs, an entity has the option to apply a modified retrospective transition method, resulting in a cumulative-effect adjustment to retained earnings in the period of adoption. Early adoption is permitted.

We expect our adoption will not materially affect our consolidated results of operations, financial position and cash flows.

Revenue recognition

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. The applicable tariffs are based on the cost of providing service. The utilities’ approved base rates are designed to recover their allowable operating costs, including energy costs, finance costs, and the costs of equity, the last of which reflect our capital ratio and a reasonable return on equity. We traditionally invoice our customers by applying approved base rates to usage. 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 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.

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 or a percentage 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 2022 upon commercial operation. Contract assets totaled $9 million at both March 31, 2022 and December 31, 2021, 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 $8 million and $16 million at March 31, 2022 and December 31, 2021, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $8 million and $4 million as revenue during the three months ended March 31, 2022 and 2021, respectively.

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Revenue (Tables)

3 Months Ended

Mar. 31, 2022

Revenue from Contract with Customer [Abstract]

Schedule of Revenues Disaggregated by Major Source for Reportable Segments

Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2022 and 2021 are as follows:

	Three Months Ended March 31, 2022
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	1,170	$	—	$	—	$	1,170
Regulated operations – natural gas	721		—		—		721
Nonregulated operations – wind	—		220		—		220
Nonregulated operations – solar	—		7		—		7
Nonregulated operations – thermal	—		13		—		13
Other(a)	22		16		—		38
Revenue from contracts with customers	1,913		256		—		2,169
Leasing revenue	3		—		—		3
Derivative losses	—		(63)		—		(63)
Alternative revenue programs	12		—		—		12
Other revenue	7		5		—		12
Total operating revenues	$	1,935	$	198	$	—	$	2,133

	Three Months Ended March 31, 2021
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	942	$	—	$	—	$	942
Regulated operations – natural gas	564		—		—		564
Nonregulated operations – wind	—		371		—		371
Nonregulated operations – solar	—		4		—		4
Nonregulated operations – thermal	—		12		—		12
Other(a)	10		32		—		42
Revenue from contracts with customers	1,516		419		—		1,935
Leasing revenue	2		—		—		2
Derivative losses	—		(31)		—		(31)
Alternative revenue programs	47		—		—		47
Other revenue	8		5		—		13
Total operating revenues	$	1,573	$	393	$	—	$	1,966

(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.

Schedule of Aggregate Transaction Price Allocations

As of March 31, 2022, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of March 31, 2022	2023		2024		2025		2026		2027		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	1	$	1	$	—	$	—	$	—	$	—	$	2
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	18		14		12		10		7		60		121
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	27		17		6		4		1		1		56
Total operating revenues	$	46	$	32	$	18	$	14	$	8	$	61	$	179

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Regulatory Assets and Liabilities (Tables)

3 Months Ended

Mar. 31, 2022

Regulated Operations [Abstract]

Schedule of Delivery Rate Increases

The below table provides a summary of the approved 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	4.6	%	$	46	5.9	%	$	36	4.2	%
NYSEG Gas	$	—	—	%	$	2	0.8	%	$	3	1.6	%
RG&E Electric	$	17	3.8	%	$	14	3.2	%	$	16	3.3	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2	1.3	%

Schedule of Current and Non-Current Regulatory Assets

Regulatory assets as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Pension and other post-retirement benefits cost deferrals	$	322	$	545
Pension and other post-retirement benefits	96		95
Storm costs	502		448
Rate adjustment mechanism	61		68
Revenue decoupling mechanism	59		68
Transmission revenue reconciliation mechanism	13		15
Contracts for differences	69		73
Hardship programs	25		24
Plant decommissioning	2		2
Deferred purchased gas	10		52
Deferred transmission expense	8		13
Environmental remediation costs	251		256
Debt premium	70		71
Unamortized losses on reacquired debt	22		23
Unfunded future income taxes	444		424
Federal tax depreciation normalization adjustment	141		142
Asset retirement obligation	20		20
Deferred meter replacement costs	49		46
COVID-19 cost recovery	19		21
Other	281		241
Total regulatory assets	2,464		2,647
Less: current portion	377		400
Total non-current regulatory assets	$	2,087	$	2,247

Schedule of Current and Non-Current Regulatory Liabilities

Regulatory liabilities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Energy efficiency portfolio standard	$	43	$	45
Gas supply charge and deferred natural gas cost	35		7
Pension and other post-retirement benefits cost deferrals	71		73
Carrying costs on deferred income tax bonus depreciation	20		23
Carrying costs on deferred income tax - Mixed Services 263(a)	6		7
2017 Tax Act	1,310		1,327
Rate Change Levelization	100		99
Revenue decoupling mechanism	20		13
Accrued removal obligations	1,201		1,192
Asset sale gain account	—		2
Economic development	26		26
Positive benefit adjustment	21		22
Theoretical reserve flow thru impact	6		6
Deferred property tax	19		22
Net plant reconciliation	15		16
Debt rate reconciliation	46		49
Rate refund – FERC ROE proceeding	35		35
Transmission congestion contracts	25		23
Merger-related rate credits	11		12
Accumulated deferred investment tax credits	23		24
Asset retirement obligation	18		18
Earning sharing provisions	15		13
Middletown/Norwalk local transmission network service collections	17		17
Low income programs	28		25
Non-firm margin sharing credits	17		15
New York 2018 winter storm settlement	5		5
Hedge gains	98		19
Other	279		194
Total regulatory liabilities	3,510		3,329
Less: current portion	499		307
Total non-current regulatory liabilities	$	3,011	$	3,022

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Fair Value of Financial Instruments and Fair Value Measurements (Tables)

3 Months Ended

Mar. 31, 2022

Fair Value Disclosures [Abstract]

Schedule of Fair Value Measurements

The financial instruments measured at fair value as of March 31, 2022 and December 31, 2021, respectively, consisted of:

As of March 31, 2022	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	36	$	17	$	—	$	—	$	53
Derivative assets
Derivative financial instruments - power	$	89	$	49	$	104	$	(79)	$	163
Derivative financial instruments - gas	13		65		4		(67)		15
Contracts for differences	—		—		2		—		2
Total	$	102	$	114	$	112	$	(146)	$	182
Derivative liabilities
Derivative financial instruments - power	$	(5)	$	(206)	$	(163)	$	243	$	(131)
Derivative financial instruments - gas	—		(38)		(2)		35		(5)
Contracts for differences	—		—		(71)		—		(71)
Derivative financial instruments – Other	—		(62)		—		—		(62)
Total	$	(5)	$	(306)	$	(236)	$	278	$	(269)

As of December 31, 2021	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	45	$	15	$	—	$	—	$	60
Derivative assets
Derivative financial instruments - power	$	31	$	39	$	85	$	(78)	$	77
Derivative financial instruments - gas	4		34		9		(32)		15
Contracts for differences	—		—		2		—		2
Total	$	35	$	73	$	96	$	(110)	$	94
Derivative liabilities
Derivative financial instruments - power	$	(16)	$	(137)	$	(90)	$	176	$	(67)
Derivative financial instruments - gas	(1)		(22)		—		18		(5)
Contracts for differences	—		—		(75)		—		(75)
Derivative financial instruments - Other	—		(77)		—		—		(77)
Total	$	(17)	$	(236)	$	(165)	$	194	$	(224)

Fair Value, Financial instrument Based on Level 3 Reconciliation

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2022 and 2021, respectively, is as follows:

	Three Months Ended March 31,
(Millions)	2022		2021
Fair Value Beginning of Period,	$	(69)	$	13
Gains recognized in operating revenues	38		11
(Losses) recognized in operating revenues	(40)		(4)
Total gains recognized in operating revenues	(2)		7
Gains recognized in OCI	2		1
(Losses) recognized in OCI	(63)		(17)
Total gains (losses) recognized in OCI	(61)		(16)
Net change recognized in regulatory assets and liabilities	4		1
Purchases	(1)		—
Settlements	5		(4)
Fair Value as of March 31,	$	(124)	$	1
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)	$	7

Additional quantitative information about Level 3 fair value measurements of the CfDs is as follows:

	Range at
Unobservable Input	March 31, 2022
Risk of non-performance	0.56% - 0.67%
Discount rate	2.42% - 2.45%
Forward pricing ($ per KW-month)	$2.00 - $4.63

Fair Value, Assets and Liabilities Level 3 Measurement, Valuation Techniques

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 March 31, 2022
Index	Avg.		Max.		Min.
NYMEX ($/MMBtu)	$	3.58	$	6.52	$	2.27
AECO ($/MMBtu)	$	2.69	$	5.69	$	1.53
Ameren ($/MWh)	$	38.09	$	93.59	$	18.01
COB ($/MWh)	$	50.49	$	231.90	$	9.15
ComEd ($/MWh)	$	34.53	$	86.32	$	14.98
ERCOT N hub ($/MWh)	$	39.26	$	140.00	$	13.66
ERCOT S hub ($/MWh)	$	37.80	$	140.00	$	13.88
Indiana hub ($/MWh)	$	40.20	$	93.81	$	20.74
Mid C ($/MWh)	$	47.52	$	229.90	$	5.15
Minn hub ($/MWh)	$	34.61	$	90.99	$	15.23
NoIL hub ($/MWh)	$	34.30	$	84.00	$	14.64
PJM W hub ($/MWh)	$	39.84	$	113.93	$	17.78

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Derivative Instruments and Hedging (Tables)

3 Months Ended

Mar. 31, 2022

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Schedule of Derivatives Instruments Statements of Financial Performance and Financial Position, Location in Condensed Consolidated Balance Sheet and Amounts

The tables below present Networks' derivative positions as of March 31, 2022 and December 31, 2021, respectively, including those subject to master netting agreements and the location of the net derivative positions on our condensed consolidated balance sheets:

As of March 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	98	$	7	$	—	$	4
Derivative liabilities	—		(4)		(15)		(61)
	98		3		(15)		(57)
Designated as hedging instruments
Derivative assets	1		—		—		—
Derivative liabilities	—		—		—		—
	1		—		—		—
Total derivatives before offset of cash collateral	99		3		(15)		(57)
Cash collateral receivable	—		—		—		1
Total derivatives as presented in the balance sheet	$	99	$	3	$	(15)	$	(56)

As of December 31, 2021	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	29	$	7	$	12	$	4
Derivative liabilities	(12)		(4)		(27)		(64)
	17		3		(15)		(60)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		—
	—		—		(1)		—
Total derivatives before offset of cash collateral	17		3		(16)		(60)
Cash collateral receivable	—		—		—		—
Total derivatives as presented in the balance sheet	$	17	$	3	$	(16)	$	(60)

The tables below present Renewables' derivative positions as of March 31, 2022 and December 31, 2021, respectively, including those subject to master netting agreements and the location of the net derivative position on our condensed consolidated balance sheets:

As of March 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	53	$	65	$	89	$	12
Derivative liabilities	(17)		(21)		(115)		(12)
	36		44		(26)		—
Designated as hedging instruments
Derivative assets	—		—		2		2
Derivative liabilities	—		—		(141)		(105)
	—		—		(139)		(103)
Total derivatives before offset of cash collateral	36		44		(165)		(103)
Cash collateral (payable) receivable	—		—		69		62
Total derivatives as presented in the balance sheet	$	36	$	44	$	(96)	$	(41)

As of December 31, 2021	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	29	$	70	$	52	$	9
Derivative liabilities	(11)		(14)		(65)		(11)
	18		56		(13)		(2)
Designated as hedging instruments
Derivative assets	—		—		5		6
Derivative liabilities	—		—		(67)		(142)
	—		—		(62)		(136)
Total derivatives before offset of cash collateral	18		56		(75)		(138)
Cash collateral payable	—		—		27		57
Total derivatives as presented in the balance sheet	$	18	$	56	$	(48)	$	(81)

Schedule of Notional Volumes of Outstanding Derivative Positions

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,	December 31,
As of	2022	2021
(Millions)
Wholesale electricity purchase contracts (MWh)	5.3	5.7
Natural gas purchase contracts (Dth)	8.4	9.4
Fleet fuel purchase contracts (Gallons)	1.4	2.0

The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,	December 31,
As of	2022	2021
(MWh/Dth in millions)
Wholesale electricity purchase contracts	4	4
Wholesale electricity sales contracts	9	10
Natural gas and other fuel purchase contracts	13	20
Financial power contracts	8	9
Basis swaps – purchases	25	30
Basis swaps – sales	1	—

Schedule of Unrealized Gains and Losses from Fair Value Adjustments

The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of March 31, 2022 and December 31, 2021 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2022 and 2021 are as follows:

(Millions)	Loss or Gain Recognized in Regulatory Assets/Liabilities				Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As of						Three Months Ended March 31,
March 31, 2022	Electricity		Natural Gas		2022	Electricity		Natural Gas
Regulatory assets	$	1	$	—	Purchased power, natural gas and fuel used	$	(45)	$	(9)
Regulatory liabilities	$	(85)	$	(13)
December 31, 2021					2021
Regulatory assets	$	—	$	—	Purchased power, natural gas and fuel used	$	2	$	(1)
Regulatory liabilities	$	(16)	$	(3)

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the three months ended March 31, 2022 and 2021, respectively, were as follows:

	Three Months Ended March 31,
	2022		2021
(Millions)
Derivative assets	$	—	$	—
Derivative liabilities	$	4	$	1

Schedule of Cash Flow Hedges Included in Accumulated Other Comprehensive Income (Loss)

The effect of derivatives in cash flow hedging relationships on Other Comprehensive Income (OCI) and income for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	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)
2022
Interest rate contracts	$	—	Interest expense	$	1	$	71
Commodity contracts	2		Purchased power, natural gas and fuel used	(1)		741
Foreign currency exchange contracts	—			—
Total	$	2		$	—
2021
Interest rate contracts	$	—	Interest expense	$	1	$	73
Commodity contracts	1		Purchased power, natural gas and fuel used	—		501
Foreign currency exchange contracts	(4)			—
Total	$	(3)		$	1

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

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of (Gain) Reclassified from Accumulated OCI into Income	(Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2022
Commodity contracts	$	(112)	Operating revenues	$	11	$	2,133
2021
Commodity contracts	$	(28)	Operating revenues	$	(3)	$	1,966

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

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	(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)
2022
Interest rate contracts	$	—	Interest expense	$	2	$	71
2021
Interest rate contracts	$	—	Interest expense	$	2	$	73

(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 which end in 2025 and 2029.

Schedule of Fair Value Hedging Instruments

The effects on our consolidated financial statements as of and for the three months ended March 31, 2022 and 2021 are as follows:

	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
(Millions)	As of March 31, 2022			Three Months Ended March 31, 2022
Current Liabilities	$	(4)	Interest Expense	$	(2)	$	71
Non-current liabilities	$	(57)
	Cumulative effect on hedged debt
Current debt	$	4
Non-current debt	$	57

	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
(Millions)	As of December 31, 2021			Three Months Ended March 31, 2021
Current Assets	$	—	Interest Expense	$	—	$	73
Non-current liabilities	$	(19)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	19

Schedule of Fair Value, Net Derivative Contracts

The fair values of derivative contracts associated with Renewables' activities as of March 31, 2022 and December 31, 2021, respectively, consisted of:

	March 31,		December 31,
As of	2022		2021
(Millions)
Wholesale electricity purchase contracts	$	85	$	36
Wholesale electricity sales contracts	(162)		(77)
Natural gas and other fuel purchase contracts	—		6
Financial power contracts	22		35
Total	$	(55)	$	—

Effect of Derivatives Associated with Renewables and Gas Activities

The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2022, consisted of:

	Three Months Ended March 31, 2022
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	9	$	3
Wholesale electricity sales contracts	(1)		(40)
Financial power contracts	(2)		(21)
Financial and natural gas contracts	(1)		(25)
Total gain (loss) included in operating revenues	$	5	$	(83)	$	2,133
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	37
Financial power contracts	—		1
Financial and natural gas contracts	—		37
Total gain included in purchased power, natural gas and fuel used	$	—	$	75	$	741
Total Gain (Loss)	$	5	$	(8)

The effects of trading and non-trading derivatives associated with Renewables' activities for the three months ended March 31, 2021, consisted of:

	Three Months Ended March 31, 2021
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	7	$	—
Wholesale electricity sales contracts	—		(17)
Financial power contracts	(5)		(16)
Financial and natural gas contracts	—		(4)
Total gain (loss) included in operating revenues	$	2	$	(37)	$	1,966
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	10
Financial power contracts	—		1
Financial and natural gas contracts	—		4
Total loss included in purchased power, natural gas and fuel used	$	—	$	15	$	501
Total Gain (Loss)	$	2	$	(22)

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Post-retirement and Similar Obligations (Tables)

3 Months Ended

Mar. 31, 2022

Retirement Benefits [Abstract]

Components of Net Periodic Pension and Postretirement Benefits

The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2022 and 2021, respectively, consisted of:

	Three Months Ended March 31,
	2022		2021
(Millions)
Service cost	$	8	$	10
Interest cost	24		22
Expected return on plan assets	(45)		(50)
Amortization of:
Prior service costs	1		—
Actuarial loss	18		35
Curtailments and settlements	2		—
Net Periodic Benefit Cost	$	8	$	17

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2022 and 2021, respectively, consisted of: 

	Three Months Ended March 31,
	2022		2021
(Millions)
Service cost	$	1	$	1
Interest cost	3		2
Expected return on plan assets	(2)		(2)
Amortization of:
Prior service costs	—		(2)
Actuarial loss	(1)		1
Net Periodic Benefit Cost	$	1	$	—

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Equity (Tables)

3 Months Ended

Mar. 31, 2022

Equity [Abstract]

Schedule of Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss for the three months ended March 31, 2022 and 2021, respectively, consisted of:

	As of December 31,		Three Months Ended March 31,		As of March 31,		As of December 31,		Three Months Ended March 31,		As of March 31,
	2021		2022		2022		2020		2021		2021
(Millions)
Change in revaluation of defined benefit plans	$	(10)	$	—	$	(10)	$	(12)	$	—	$	(12)
(Loss) gain on nonqualified pension plans, net of income tax expense of $3 for 2022	(28)		9		(19)		(20)		—		(20)
Unrealized (loss) gain from equity method investment, net of income tax expense of $5 for 2022 (a)	(9)		15		6		—		—		—
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(15) for 2022 and $(5) for 2021	(194)		(39)		(233)		(35)		(27)		(62)
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $4 for 2022 and $(1) for 2021 (b)	(32)		11		(21)		(44)		1		(43)
Loss on derivatives qualifying as cash flow hedges	(226)		(28)		(254)		(79)		(26)		(105)
Accumulated Other Comprehensive Loss	$	(273)	$	(4)	$	(277)	$	(111)	$	(26)	$	(137)

(a)    Foreign currency and interest rate contracts.

(b)    Reclassification is reflected in the operating expenses and interest expense, net of capitalization line items in our consolidated statements of income.

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Earnings Per Share (Tables)

3 Months Ended

Mar. 31, 2022

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The calculations of basic and diluted earnings per share attributable to AVANGRID, for the three months ended March 31, 2022 and 2021, respectively, consisted of:

	Three Months Ended March 31,
	2022		2021
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	445	$	334
Denominator:
Weighted average number of shares outstanding - basic	386,698,132		309,495,250
Weighted average number of shares outstanding - diluted	387,114,285		309,736,266
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	1.15	$	1.08
Earnings Per Common Share, Diluted	$	1.15	$	1.08

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Segment Information (Tables)

3 Months Ended

Mar. 31, 2022

Segment Reporting [Abstract]

Schedule of Segment Information

Segment information as of and for the three months ended March 31, 2022, consisted of:

Three Months Ended March 31, 2022	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,935	$	198	$	—	$	2,133
Depreciation and amortization	161		100		—		261
Operating income	319		(18)		1		302
Earnings from equity method investments	3		250		—		253
Interest expense, net of capitalization	50		3		18		71
Income tax expense (benefit)	31		41		(4)		68
Adjusted net income	254		211		(15)		450
Capital expenditures	355		454		2		811
As of March 31, 2022
Property, plant and equipment	18,882		10,825		12		29,719
Equity method investments	149		285		—		434
Total assets	$	26,329	$	12,747	$	465	$	39,541

(a) Includes Corporate and intersegment eliminations.

Segment information for the three months ended March 31, 2021 and as of December 31, 2021, consisted of:

Three Months Ended March 31, 2021	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	1,573	$	393	$	—	$	1,966
Depreciation and amortization	156		91		—		247
Operating income	313		92		1		406
Earnings (losses) from equity method investments	2		(1)		—		1
Interest expense, net of capitalization	53		—		20		73
Income tax expense (benefit)	42		(9)		(19)		14
Adjusted net income	229		123		2		354
Capital expenditures	531		92		—		623
As of December 31, 2021
Property, plant and equipment	18,737		10,118		11		28,866
Equity method investments	148		412		—		560
Total assets	$	26,126	$	12,578	$	800	$	39,504

(a) Includes Corporate and intersegment eliminations.

Schedule of Reconciliation of Adjusted Net Income to Net Income

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2022 and 2021, respectively, is as follows:

	Three Months Ended March 31,
	2022		2021
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	450	$	354
Adjustments:
Mark-to-market earnings - Renewables (1)	(3)		(20)
Impact of COVID-19 (2)	(2)		(6)
Income tax impact of adjustments	2		7
Net Income Attributable to Avangrid, Inc.	$	445	$	334

(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)     Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions.

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Related Party Transactions (Tables)

3 Months Ended

Mar. 31, 2022

Related Party Transactions [Abstract]

Schedule of Related Party Transactions

Related party transactions for the three months ended March 31, 2022 and 2021, respectively, consisted of:

Three Months Ended March 31,	2022				2021
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(12)	$	—	$	(13)
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(3)	$	—	$	(2)
Vineyard Wind	$	2	$	—	$	4	$	—
Iberdrola Solutions	$	—	$	—	$	7	$	(38)
Other	$	—	$	(1)	$	1	$	(1)

Related party balances as of March 31, 2022 and December 31, 2021, respectively, consisted of:

As of	March 31, 2022				December 31, 2021
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	2	$	(10)	$	3	$	(43)
Iberdrola Financiación, S.A.	$	—	$	(2)	$	—	$	(9)
Vineyard Wind	$	2	$	(8)	$	8	$	(8)
Iberdrola Solutions	$	—	$	(2)	$	—	$	(2)
Other	$	—	$	(3)	$	—	$	(1)

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Other Financial Statement Items (Tables)

3 Months Ended

Mar. 31, 2022

Balance Sheet Related Disclosures [Abstract]

Schedule of Accounts, Notes, Loans and Financing Receivable

Accounts receivable and unbilled revenues, net as of March 31, 2022 and December 31, 2021 consisted of:

As of	March 31, 2022		December 31, 2021
(Millions)
Trade receivables and unbilled revenues	$	1,629	$	1,420
Allowance for credit losses	(153)		(151)
Accounts receivable and unbilled revenues, net	$	1,476	$	1,269

The change in the allowance for credit losses for the three months ended March 31, 2022 and 2021 consisted of:

	Three Months Ended March 31,
(Millions)	2022		2021
As of Beginning of Period,	$	151	$	108
Current period provision	20		39
Write-off as uncollectible	(18)		(12)
As of March 31,	$	153	$	135

Schedule of Accumulated Depreciation and Amortization

The accumulated depreciation and amortization as of March 31, 2022 and December 31, 2021, respectively, were as follows:

	March 31,		December 31,
As of	2022		2021
(Millions)
Property, plant and equipment
Accumulated depreciation	$	10,830	$	10,589
Intangible assets
Accumulated amortization	$	321	$	317

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Background and Nature Of Operations (Details) $ / shares in Units, $ in Millions	May 18, 2021 USD ($) placement $ / shares shares	Apr. 15, 2021	Oct. 20, 2020 USD ($) $ / shares	Mar. 31, 2022 $ / shares	Dec. 31, 2021 $ / shares	Mar. 31, 2021 $ / shares	Dec. 31, 2020 $ / shares
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares	77,821,012
Sale of stock number of placements | placement	2
Common stock, par value (in dollars per share) | $ / shares	$ 0.01			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	$ 3,000
NM Green Holdings, Inc.
Nature Of Business [Line Items]
Merger agreement, share price (in dollars per share) | $ / shares			$ 50.30
Merger agreement term, ownership percentage benchmark (no more than)			15.00%
Merger agreement, termination rights term, extension period			3 months
Merger agreement, termination rights term, termination fees			$ 130
Merger agreement, termination rights term, termination fees as remedy			184
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			$ 10
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger
Nature Of Business [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%
Hyde Member LLC And Subsidiary Of Qatar Investment Authority
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
Iberdrola S.A.
Nature Of Business [Line Items]
Sale of stock, number of shares issued (in shares) | shares	63,424,125
Avangrid | Iberdrola S.A.
Nature Of Business [Line Items]
Parent company, ownership percentage				81.60%
Avangrid | Various Shareholders
Nature Of Business [Line Items]
Ownership percentage by noncontrolling owners				18.40%

XML

Revenue - Narrative (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Disaggregation of Revenue [Line Items]
Contract assets	$ 9		$ 9
TCC contract liabilities	8		16
Revenue recognized	8	$ 4
Accounts receivable related to contracts with customers	1,433		1,220
Unbilled contracts receivable	402		$ 405
Revenue, remaining performance obligation, amount	$ 179
Transmission congestion contracts | Min.
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	6 months
Transmission congestion contracts | Max.
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	2 years
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term	15 years

XML

Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 2,169	$ 1,935
Leasing revenue	3	2
Derivative losses	(63)	(31)
Alternative revenue programs	12	47
Other revenue	12	13
Total operating revenues	2,133	1,966
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,170	942
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	721	564
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	220	371
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	7	4
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	13	12
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	38	42
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Leasing revenue	0	0
Derivative losses	0	0
Alternative revenue programs	0	0
Other revenue	0	0
Total operating revenues	0	0
Other | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,913	1,516
Leasing revenue	3	2
Derivative losses	0	0
Alternative revenue programs	12	47
Other revenue	7	8
Total operating revenues	1,935	1,573
Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,170	942
Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	721	564
Networks | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Networks | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	22	10
Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers	256	419
Leasing revenue	0	0
Derivative losses	(63)	(31)
Alternative revenue programs	0	0
Other revenue	5	5
Total operating revenues	198	393
Renewables | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Renewables | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0
Renewables | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	220	371
Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	7	4
Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	13	12
Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 16	$ 32

XML

Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Mar. 31, 2022 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 179
Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	2
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	121
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	56
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-04-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 46
Remaining performance obligation, period	9 months
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 46
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 18
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 27
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 32
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 17
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 18
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 6
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 10
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 4
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 8
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 7
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 61
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 60
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2028-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period

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Regulatory Assets and Liabilities - Additional Information (Details)										1 Months Ended	3 Months Ended		12 Months Ended
	Jul. 14, 2021 USD ($)	Jun. 23, 2021 USD ($)	May 06, 2021 USD ($)	Apr. 15, 2021	Nov. 19, 2020	Feb. 19, 2020 USD ($)	Jan. 01, 2019	Jan. 01, 2018	Jan. 01, 2017	Sep. 30, 2021	Mar. 31, 2022 USD ($)	Mar. 31, 2021 USD ($)	Dec. 31, 2021	Dec. 31, 2020	Jun. 30, 2021 USD ($) hour
Regulatory Assets And Liabilities [Line Items]
Unrecorded regulatory assets											$ 867,000,000
Energy legislation settlement agreement, contribution amount		$ 5,000,000
Energy legislation settlement agreement, customers rate credits provided		50,000,000
Energy legislation settlement agreement, customers rate credits collected in rate adjustment mechanism		$ 52,000,000
Energy legislation settlement agreement, customers rate credits provided, period		22 months
Energy legislation, customer compensation and reimbursement provisions, power outage hours benchmark (more than) | hour															96
Energy legislation, customer compensation and reimbursement provisions, customer payment per day															$ 25
Energy legislation, customer compensation and reimbursement provisions, food and medicine reimbursement															$ 250
Civil penalty amount	$ 1,000,000		$ 2,000,000
Unfunded future income tax expense collection period											46 years
UIL Holdings
Regulatory Assets And Liabilities [Line Items]
Business combination merger related rate credits											$ 1,000,000	$ 1,000,000
Energy efficiency portfolio standard
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
Carrying costs on deferred income tax bonus depreciation
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
Rate Change Levelization
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													5 years
Positive benefit adjustment
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
Theoretical reserve flow thru impact | Max.
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													5 years
Theoretical reserve flow thru impact | Min.
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
Deferred property tax
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													5 years
Net plant reconciliation
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													5 years
Transmission congestion contracts
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													5 years
New York 2018 winter storm settlement
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
Central Maine Power
Regulatory Assets And Liabilities [Line Items]
Distribution revenue requirement						$ 17,000,000
Annual distribution tariff increase percentage						7.00%
Distribution tariff rate increased based on ROE						9.25%
Distribution tariff rate increased based on equity capital						50.00%
ROE reduction						1.00%
Proposed distribution tariff rate decrease based on return on equity						8.25%
Service quality measures for a period										18 months
Deferred income tax recovery period											32 years 6 months
NYSEG and RG&E
Regulatory Assets And Liabilities [Line Items]
Return on equity					8.80%
Equity ratio for earnings sharing					48.00%
Equity ratio					50.00%
NYSEG and RG&E | Economic development
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
United Illuminating Company (UI)
Regulatory Assets And Liabilities [Line Items]
ROE reduction				(1500.00%)
United Illuminating Company (UI) | PURA
Regulatory Assets And Liabilities [Line Items]
Return on equity									9.10%
Equity ratio									50.00%
New distribution rate schedule, period									3 years
Public utilities regulatory authority distribution rate									50.00%
SCG | PURA
Regulatory Assets And Liabilities [Line Items]
Return on equity								9.25%
Equity ratio								52.00%
Connecticut Natural Gas Corporation (CNG) | PURA
Regulatory Assets And Liabilities [Line Items]
Return on equity							9.30%
Equity ratio, year one							54.00%
Equity ratio, year two							54.50%
Equity ratio, year three							55.00%
BGC | Massachusetts Department of Public Utilities (DPU)
Regulatory Assets And Liabilities [Line Items]
Equity ratio														54.00%
Public utilities regulatory authority distribution rate														9.70%
NYSEG | Asset sale gain account
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													3 years
RG&E | Asset sale gain account
Regulatory Assets And Liabilities [Line Items]
Regulatory liability, amortization period													2 years

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Regulatory Assets and Liabilities - Rate Increases and Delivery Rate Percentages (Details) $ in Millions	Jun. 22, 2020 USD ($)
NYSEG Electric | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 34
Delivery Rate Increase	4.60%
NYSEG Electric | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 46
Delivery Rate Increase	5.90%
NYSEG Electric | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 36
Delivery Rate Increase	4.20%
NYSEG Gas | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0.00%
NYSEG Gas | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 2
Delivery Rate Increase	0.80%
NYSEG Gas | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 3
Delivery Rate Increase	1.60%
RG&E Electric | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 17
Delivery Rate Increase	3.80%
RG&E Electric | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 14
Delivery Rate Increase	3.20%
RG&E Electric | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 16
Delivery Rate Increase	3.30%
RG&E Gas | Electric and Gas Service Rate Plan Year One
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0.00%
RG&E Gas | Electric and Gas Service Rate Plan Year Two
Regulatory Liabilities [Line Items]
Rate Increase	$ 0
Delivery Rate Increase	0.00%
RG&E Gas | Electric and Gas Service Rate Plan Year Three
Regulatory Liabilities [Line Items]
Rate Increase	$ 2
Delivery Rate Increase	1.30%

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Regulatory Assets and Liabilities - Regulatory Assets (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,464	$ 2,647
Less: current portion	377	400
Total non-current regulatory assets	2,087	2,247
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	322	545
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	96	95
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	502	448
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	61	68
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	59	68
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	13	15
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	69	73
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	25	24
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	2	2
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	10	52
Deferred transmission expense
Regulatory Assets [Line Items]
Total regulatory assets	8	13
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	251	256
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	70	71
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	22	23
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	444	424
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	141	142
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	20
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	49	46
COVID-19 cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	19	21
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 281	$ 241

XML

Regulatory Assets and Liabilities - Regulatory Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,510	$ 3,329
Less: current portion	499	307
Total non-current regulatory liabilities	3,011	3,022
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	43	45
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	35	7
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	71	73
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20	23
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	6	7
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,310	1,327
Rate Change Levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	100	99
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	20	13
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,201	1,192
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	0	2
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	26	26
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	21	22
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	6	6
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	19	22
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	16
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	46	49
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	35	35
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	25	23
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	11	12
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	24
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	18
Earning sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	13
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	17
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	28	25
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	15
Hedge gains
Regulatory Liabilities [Line Items]
Total regulatory liabilities	98	19
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	5	5
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 279	$ 194

XML

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Restricted cash	$ 403	$ 374
Fair value of debt	8,495	9,155
Restricted Cash
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Restricted cash	$ 3	$ 3
NYSEG and RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of electric load obligations hedged	70.00%
Percentage of natural gas load obligations hedged	55.00%

XML

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	$ 53	$ 60
Netting adjustment	(146)	(110)
Derivative assets	182	94
Netting adjustment	278	194
Derivative liabilities	(269)	(224)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(79)	(78)
Derivative assets	163	77
Netting adjustment	243	176
Derivative liabilities	(131)	(67)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(67)	(32)
Derivative assets	15	15
Netting adjustment	35	18
Derivative liabilities	(5)	(5)
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	2	2
Netting adjustment	0	0
Derivative liabilities	(71)	(75)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative liabilities	(62)	(77)
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	36	45
Derivative assets, before netting	102	35
Derivative liabilities, before netting	(5)	(17)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	89	31
Derivative liabilities, before netting	(5)	(16)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	13	4
Derivative liabilities, before netting	0	(1)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 1 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, before netting	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	17	15
Derivative assets, before netting	114	73
Derivative liabilities, before netting	(306)	(236)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	49	39
Derivative liabilities, before netting	(206)	(137)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	65	34
Derivative liabilities, before netting	(38)	(22)
Level 2 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 2 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, before netting	(62)	(77)
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity investments with readily determinable fair values	0	0
Derivative assets, before netting	112	96
Derivative liabilities, before netting	(236)	(165)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	104	85
Derivative liabilities, before netting	(163)	(90)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	4	9
Derivative liabilities, before netting	(2)	0
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	2	2
Derivative liabilities, before netting	(71)	(75)
Level 3 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative liabilities, before netting	$ 0	$ 0

XML

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair Value Beginning of Period,	$ (69)	$ 13
Gains recognized in operating revenues	38	11
(Losses) recognized in operating revenues	(40)	(4)
Total gains recognized in operating revenues	(2)	7
Gains recognized in OCI	2	1
(Losses) recognized in OCI	(63)	(17)
Total gains (losses) recognized in OCI	(61)	(16)
Net change recognized in regulatory assets and liabilities	4	1
Purchases	(1)	0
Settlements	5	(4)
Fair Value as of March 31,	(124)	1
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)	$ 7

XML

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price	Mar. 31, 2022 $ / MWh $ / MMBTU $ / kilowatt-MonthOfEnergy
Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / kilowatt-MonthOfEnergy	4.63
Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / kilowatt-MonthOfEnergy	2.00
CME SWAPS MARKETS (NYMEX) | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	3.58
CME SWAPS MARKETS (NYMEX) | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	6.52
CME SWAPS MARKETS (NYMEX) | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	2.27
AECO | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	2.69
AECO | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	5.69
AECO | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input | $ / MMBTU	1.53
Ameren | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	38.09
Ameren | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	93.59
Ameren | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	18.01
COB | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	50.49
COB | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	231.90
COB | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	9.15
ComEd | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	34.53
ComEd | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	86.32
ComEd | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	14.98
ERCOT N hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	39.26
ERCOT N hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	140.00
ERCOT N hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	13.66
ERCOT S Hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	37.80
ERCOT S Hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	140.00
ERCOT S Hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	13.88
Indiana Hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	40.20
Indiana Hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	93.81
Indiana Hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	20.74
Mid C | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	47.52
Mid C | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	229.90
Mid C | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	5.15
Minn Hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	34.61
Minn Hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	90.99
Minn Hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	15.23
Noil Hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	34.30
Noil Hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	84.00
Noil Hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	14.64
PJM W hub | Avg.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	39.84
PJM W hub | Max.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	113.93
PJM W hub | Min.
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	17.78

XML

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details)	Mar. 31, 2022 $ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0056
Min. | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0242
Min. | Measurement Input, Commodity Forward Price
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	2.00
Max. | Risk of non-performance
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0067
Max. | Discount rate
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	0.0245
Max. | Measurement Input, Commodity Forward Price
Fair Value Assets And Liabilities Measured On Recurring And Nonrecurring Basis Valuation Techniques [Line Items]
Derivative measurement input	4.63

XML

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Condensed Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 182	$ 94
Derivative Liability	(269)	(224)
Cash collateral (payable) receivable, Asset	(82)	(67)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	99	17
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	99	17
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	98	29
Derivative liabilities	0	(12)
Derivative Asset	98	17
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	1	0
Derivative liabilities	0	0
Derivative Asset	1	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	3	3
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	3	3
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	7	7
Derivative liabilities	(4)	(4)
Derivative Asset	3	3
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(15)	(16)
Cash collateral (payable) receivable, Liability	0	0
Total derivatives as presented in the balance sheet, Liability	(15)	(16)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	12
Derivative liabilities	(15)	(27)
Derivative Liability	(15)	(15)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	(1)
Derivative Liability	0	(1)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(57)	(60)
Cash collateral (payable) receivable, Liability	1	0
Total derivatives as presented in the balance sheet, Liability	(56)	(60)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	4
Derivative liabilities	(61)	(64)
Derivative Liability	(57)	(60)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Liability	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	36	18
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	36	18
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	53	29
Derivative liabilities	(17)	(11)
Derivative Asset	36	18
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Asset	44	56
Cash collateral (payable) receivable, Asset	0	0
Total derivatives as presented in the balance sheet, Asset	44	56
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	65	70
Derivative liabilities	(21)	(14)
Derivative Asset	44	56
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(165)	(75)
Cash collateral (payable) receivable, Liability	69	27
Total derivatives as presented in the balance sheet, Liability	(96)	(48)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	89	52
Derivative liabilities	(115)	(65)
Derivative Liability	(26)	(13)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	5
Derivative liabilities	(141)	(67)
Derivative Liability	(139)	(62)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, Liability	(103)	(138)
Cash collateral (payable) receivable, Liability	62	57
Total derivatives as presented in the balance sheet, Liability	(41)	(81)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	12	9
Derivative liabilities	(12)	(11)
Derivative Liability	0	(2)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	2	6
Derivative liabilities	(105)	(142)
Derivative Liability	$ (103)	$ (136)

XML

Derivative Instruments and Hedging - Net Notional Volume (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	3 Months Ended	12 Months Ended
	Mar. 31, 2022 USD ($) MWh MMBTU gal	Dec. 31, 2021 USD ($) MWh MMBTU gal
Networks | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	5.3	5.7
Networks | Natural Gas Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	8.4	9.4
Networks | Fleet Fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount | gal	1.4	2.0
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value | $	$ (55)	$ 0
Renewables | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	4.0	4.0
Derivative assets (liabilities), fair value | $	$ 85	$ 36
Renewables | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MWh	9.0	10.0
Derivative assets (liabilities), fair value | $	$ (162)	$ (77)
Renewables | Natural Gas and Other fuel Contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	13.0	20.0
Derivative assets (liabilities), fair value | $	$ 0	$ 6
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	8.0	9.0
Derivative assets (liabilities), fair value | $	$ 22	$ 35
Renewables | Basis swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	25.0	30.0
Renewables | Basis swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, nonmonetary notional amount, energy measure | MMBTU	1.0	0.0

XML

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Derivative Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 0	$ 0
Derivative Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	4	1
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	1		$ 0
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(45)	2
Electricity | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	(85)		(16)
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0		0
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(9)	$ (1)
Natural Gas | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ (13)		$ (3)

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Derivative Instruments and Hedging - Additional Information (Details) $ in Millions	3 Months Ended
	Mar. 31, 2022 USD ($) instrument	Mar. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)	Sep. 15, 2021 USD ($)	Jul. 15, 2021 USD ($)	May 27, 2021 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 2,464		$ 2,647
Regulatory liabilities	3,510		3,329
Derivative liabilities	154		160
Derivative liability	269		224
Aggregate fair value of additional collateral	20
Cash collateral pledged	82		67
Collateral already posted	$ 1
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of derivative instruments | instrument	2
Derivative liability	$ 71		75
Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	$ 0
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(2)
Cash Flow Hedging | Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Expected amortization of discontinued cash flow hedges in 2022	7
Cash Flow Hedging | Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	46		48
Fair Value Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability					$ 750
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	2	(3)
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(1)	$ (1)
Expected amortization of discontinued cash flow hedges in 2022	3
Unrealized gains on hedge derivatives reported in OCI	(2)
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months	1
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	$ 46		47
Networks | Cash Flow Hedging | Fuel Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum period of time of cash flow hedges	12 months
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Unrealized gains (losses) on hedge derivatives to be reclassified within next 12 months	$ (137)
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative notional amount				$ 956		$ 935
Derivative liabilities	$ 2		58
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	20.00%
Gross derivative asset	$ 2		2
Regulatory assets	69		73
Gross amounts of recognized liabilities	71		75
Regulatory liabilities	$ 0		0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	80.00%
Gross derivative asset	$ 0		0
Gross amounts of recognized liabilities	$ 68		$ 72

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Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Interest Expense	$ 71	$ 73
Purchased power, natural gas and fuel used	741	501
Revenues	2,133	1,966
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	2	(3)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax	0	1
Revenues	1,935	1,573
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	198	393
Interest Rate Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	0	0
Interest Rate Contract | Interest Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax	2	2
Interest Rate Contract | Networks | Interest Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	0	0
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax	1	1
Commodity Contract | Networks | Operating Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	2	1
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax	(1)	0
Commodity Contract | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	(112)	(28)
Commodity Contract | Renewables | Operating revenues
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax	11	(3)
Foreign Exchange Contract | Networks | Operating Expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Loss) Gain Recognized in OCI on Derivatives	0	(4)
Other Comprehensive Income (Loss), Cash Flow Hedge, Gain (Loss), Reclassification, before Tax	$ 0	$ 0

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Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (55)	$ 0
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	22	35
Long | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	85	36
Long | Natural Gas and Other fuel Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	0	6
Short | Wholesale Electricity Contract
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (162)	$ (77)

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Derivative Instruments and Hedging - Effect of Trading and Non-trading Derivatives (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	$ 2,133	$ 1,966
Utilities operating expense, purchased power	741	501
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Revenues	198	393
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	5	2
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(8)	(22)
Renewables | Operating revenues | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	5	2
Renewables | Operating revenues | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	9	7
Renewables | Operating revenues | Trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(1)	0
Renewables | Operating revenues | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(2)	(5)
Renewables | Operating revenues | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(1)	0
Renewables | Operating revenues | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(83)	(37)
Revenues	2,133	1,966
Renewables | Operating revenues | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	3	0
Renewables | Operating revenues | Non-trading | Wholesale Electricity Contract | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(40)	(17)
Renewables | Operating revenues | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(21)	(16)
Renewables | Operating revenues | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	(25)	(4)
Renewables | Operating Expense | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0
Renewables | Operating Expense | Trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0
Renewables | Operating Expense | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0
Renewables | Operating Expense | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	0	0
Renewables | Operating Expense | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	75	15
Utilities operating expense, purchased power	741	501
Renewables | Operating Expense | Non-trading | Wholesale Electricity Contract | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	37	10
Renewables | Operating Expense | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	1	1
Renewables | Operating Expense | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, gain (loss) on derivative, net	$ 37	$ 4

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Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Derivative Instruments and Hedging Activities Disclosures [Line Items]
(Gain) Recognized in Income Statement	$ (2)	$ 0
Year to date total per Income Statement	71	$ 73
Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(4)
Non-current liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged liability, fair value hedge	(57)		$ (19)
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged Liability, Fair Value Hedge, Cumulative Increase (Decrease)	4		0
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged Liability, Fair Value Hedge, Cumulative Increase (Decrease)	$ 57		19
Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged asset, fair value hedge			$ 0

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Contingencies and Commitments (Details) violation in Thousands, $ in Millions										1 Months Ended	3 Months Ended	12 Months Ended
	Nov. 20, 2020 violation	May 21, 2020	May 20, 2020	Nov. 21, 2019 complaint	Jan. 11, 2019 complaint	Mar. 22, 2016	Mar. 03, 2015	Oct. 16, 2014	Sep. 30, 2011	Apr. 30, 2018	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Dec. 31, 2001 plaintiff	Aug. 12, 2021 USD ($)	Jan. 04, 2021 USD ($)	Apr. 12, 2016 USD ($)
Loss Contingencies [Line Items]
Refund period term									15 months
Approved return on equity				9.88%
Regulatory liabilities											$ 3,011	$ 3,022
Number of claims | complaint				2
Requested existing base return on equity base percentage		10.02%	9.88%
Estimated reduction in earnings per year provided effective of supplemental notice of proposed rulemaking											3
Number of plaintiffs | plaintiff													2
Show cause order, period	30 days
Show cause order, number of alleged violations with civil action for injunctive relief | violation	11
Show cause order settlement payment														$ 3
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding											488
Future payments committed															$ 90
NECEC commitment, payment during period												$ 9
Vineyard Wind
Loss Contingencies [Line Items]
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding											4
Max.
Loss Contingencies [Line Items]
Show cause order settlement payment														$ 5
Complaint II
Loss Contingencies [Line Items]
Regulatory liabilities											27
Complaint III
Loss Contingencies [Line Items]
Regulatory liabilities											8
Complaint II and III
Loss Contingencies [Line Items]
Reasonably possible loss, in additional reserve, pre tax											$ 17
California Energy Crisis Litigation
Loss Contingencies [Line Items]
Price of the power purchase agreements																$ 259
Requested renewables delay from preliminary proposed ruling period										2 years
Unfavorable Regulatory Action | Complaint I
Loss Contingencies [Line Items]
Approved return on equity								10.57%
Number of claims | complaint					4
Unfavorable Regulatory Action | Complaint I | Max.
Loss Contingencies [Line Items]
Approved return on equity							11.74%	11.74%
Unfavorable Regulatory Action | Complaint II
Loss Contingencies [Line Items]
Approved return on equity						9.59%
Refund period						15 months
Unfavorable Regulatory Action | Complaint II | Max.
Loss Contingencies [Line Items]
Approved return on equity						10.42%
Unfavorable Regulatory Action | Complaint III
Loss Contingencies [Line Items]
Approved return on equity						10.90%
Refund period						15 months
Unfavorable Regulatory Action | Complaint III | Max.
Loss Contingencies [Line Items]
Approved return on equity						12.19%
Before Amendment
Loss Contingencies [Line Items]
Requested return on equity base percentage									11.14%

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Environmental Liabilities (Details)	3 Months Ended	12 Months Ended	68 Months Ended
	Mar. 31, 2022 USD ($) site	Dec. 31, 2008 site	Mar. 31, 2022 USD ($)	Dec. 31, 2021 USD ($)	Aug. 04, 2016 USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	26
Number of sites with liability recorded	11
Number of sits note expected to incur additional liabilities	15
Number of additional sites with liability recorded	12
Number of sites where gas was manufactured in the past	53
Number of sites for which we have entered into consent orders to investigate and remediate	41
Accrual related to investigation and remediation | $	$ 300,000,000		$ 300,000,000	$ 303,000,000
Accrual related to investigation and remediation, amount recorded to date | $			35,000,000
FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute		16
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 21,000,000		21,000,000	22,000,000	$ 30,000,000
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	16
Number of sites where gas was manufactured in the past	6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	5
Number of sites where gas was manufactured in the past	2
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	6
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 7,000,000		7,000,000
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	9,000,000		9,000,000
Another Ten Sites | Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	14,000,000		14,000,000
Another Ten Sites | Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 22,000,000		22,000,000
New York Voluntary Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past	3
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites for which we have entered into consent orders to investigate and remediate	3
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 113,000,000		113,000,000	$ 113,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	160,000,000		160,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	273,000,000		273,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	0		0
MGP Sites | FirstEnergy
Environmental Exit Cost [Line Items]
Number of sites in dispute		2
NYSEG | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	14,000,000		14,000,000
RG&E | FirstEnergy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 7,000,000		$ 7,000,000

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Post-Retirement and Similar Obligations - Additional Information (Details) - USD ($) $ in Millions	1 Months Ended	3 Months Ended		9 Months Ended
	Mar. 31, 2022	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2022
Defined Benefit Plan Disclosure [Line Items]
Defined benefit, pension contributions		$ 0
Additional contributions for remainder of fiscal year	$ 23	23
Decrease in pension liabilities for plan amendments	$ 200
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Curtailments and settlements		$ (2)	$ 0
Discount rate - net periodic benefit		6.30%
Pension Plan | Forecast
Defined Benefit Plan Disclosure [Line Items]
Discount rate - net periodic benefit				5.90%

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Post-Retirement and Similar Obligations - Periodic Benefit Costs Net (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Pension Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	$ 8	$ 10
Interest cost	24	22
Expected return on plan assets	(45)	(50)
Prior service costs	1	0
Actuarial loss	18	35
Curtailments and settlements	2	0
Net Periodic Benefit Cost	8	17
Other Postretirement Benefit Plan
Defined Benefit Plan Disclosure [Line Items]
Service cost	1	1
Interest cost	3	2
Expected return on plan assets	(2)	(2)
Prior service costs	0	(2)
Actuarial loss	(1)	1
Net Periodic Benefit Cost	$ 1	$ 0

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Equity - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Class of Stock [Line Items]
Treasury stock, shares (in shares)	112,543		112,543
Release of common stock held in trust (in shares)	0	292,594
Treasury shares (in shares)	997,983
Repurchases of common stock	$ 47		$ 47
Avangrid | Iberdrola S.A.
Class of Stock [Line Items]
Percentage of equity owned by parent	81.60%
Convertible Preferred Stock
Class of Stock [Line Items]
Convertible preferred stock, shares outstanding (in shares)	0		0

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Equity - Accumulated Other Comprehensive Gain (Loss) (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	$ 19,961	$ 15,826
Other comprehensive income (loss), net of tax	(4)	(26)
Balance, end of period	20,060	15,992
(Loss) gain on nonqualified pension plans, taxes	3
Unrealized (loss) gain from equity method investment, taxes	5	0
Unrealized loss during period on derivatives qualifying as cash flow hedges, taxes	(15)	(5)
Reclassification to net income of losses on cash flow hedges, tax expense (benefit)	4	(1)
Change in revaluation of defined benefit plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(10)	(12)
Other comprehensive income (loss), net of tax	0	0
Balance, end of period	(10)	(12)
(Loss) gain on nonqualified pension plans
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(28)	(20)
Other comprehensive income (loss), net of tax	9	0
Balance, end of period	(19)	(20)
Unrealized (loss) gain from equity method investment
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(9)	0
Other comprehensive income (loss), net of tax	15	0
Balance, end of period	6	0
Unrealized loss during period on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(194)	(35)
Other comprehensive income (loss), net of tax	(39)	(27)
Balance, end of period	(233)	(62)
Reclassification to net income of losses on cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(32)	(44)
Other comprehensive income (loss), net of tax	11	1
Balance, end of period	(21)	(43)
Loss on derivatives qualifying as cash flow hedges
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(226)	(79)
Other comprehensive income (loss), net of tax	(28)	(26)
Balance, end of period	(254)	(105)
Accumulated Other Comprehensive Loss
AOCI Attributable to Parent, Net of Tax [Roll Forward]
Balance, beginning of period	(273)	(111)
Other comprehensive income (loss), net of tax	(4)	(26)
Balance, end of period	$ (277)	$ (137)

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Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions		3 Months Ended
	Mar. 30, 2022	Mar. 31, 2022	Mar. 31, 2021
Numerator:
Net income attributable to AVANGRID, basic		$ 445	$ 334
Net income attributable to AVANGRID, diluted		$ 445	$ 334
Denominator:
Weighted average number of shares outstanding - basic (in shares)		386,698,132	309,495,250
Weighted average number of shares outstanding - diluted (in shares)		387,114,285	309,736,266
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)		$ 1.15	$ 1.08
Earnings Per Common Share, Diluted (in dollars per share)		1.15	1.08
Dividends declared (in dollars per share)	$ 0.44	$ 0.44	$ 0.44

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Segment Information - Additional Information (Details)	3 Months Ended
	Mar. 31, 2022 segment
Segment Reporting Information [Line Items]
Number of reportable segments	2
Networks
Segment Reporting Information [Line Items]
Number of reportable segments	1
Number of operating segments	9

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Segment Information - By Segment (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Dec. 31, 2021
Segment Reporting Information [Line Items]
Revenues	$ 2,133	$ 1,966
Depreciation and amortization	261	247
Operating income	302	406
Earnings from equity method investments	253	1
Interest expense, net of capitalization	71	73
Income tax expense (benefit)	68	14
Adjusted net income	450	354
Capital expenditures	811	623
Property, plant and equipment	29,719		$ 28,866
Equity method investments	434		560
Total assets	39,541		39,504
Corporate And Eliminations
Segment Reporting Information [Line Items]
Revenues	0	0
Depreciation and amortization	0	0
Operating income	1	1
Earnings from equity method investments	0	0
Interest expense, net of capitalization	18	20
Income tax expense (benefit)	(4)	(19)
Adjusted net income	(15)	2
Capital expenditures	2	0
Property, plant and equipment	12		11
Equity method investments	0		0
Total assets	465		800
Networks
Segment Reporting Information [Line Items]
Revenues	1,935	1,573
Networks | Operating Segments
Segment Reporting Information [Line Items]
Revenues	1,935	1,573
Depreciation and amortization	161	156
Operating income	319	313
Earnings from equity method investments	3	2
Interest expense, net of capitalization	50	53
Income tax expense (benefit)	31	42
Adjusted net income	254	229
Capital expenditures	355	531
Property, plant and equipment	18,882		18,737
Equity method investments	149		148
Total assets	26,329		26,126
Renewables
Segment Reporting Information [Line Items]
Revenues	198	393
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Revenues	198	393
Depreciation and amortization	100	91
Operating income	(18)	92
Earnings from equity method investments	250	(1)
Interest expense, net of capitalization	3	0
Income tax expense (benefit)	41	(9)
Adjusted net income	211	123
Capital expenditures	454	$ 92
Property, plant and equipment	10,825		10,118
Equity method investments	285		412
Total assets	$ 12,747		$ 12,578

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Segment Information - Reconciliation of Adjusted Net Income to Net Income (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 450	$ 354
Adjustments:
Mark-to-market earnings - Renewables	(3)	(20)
Impact of COVED -19	(2)	(6)
Income tax impact of adjustments	2	7
Net Income Attributable to Avangrid, Inc.	$ 445	$ 334

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To	$ 0	$ 0
Purchases From	(12)	(13)
Iberdrola Renovables Energía, S.L.
Related Party Transaction [Line Items]
Sales To	0	0
Purchases From	(2)	(2)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Sales To	0	0
Purchases From	(3)	(2)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	2	4
Purchases From	0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Sales To	0	7
Purchases From	0	(38)
Other
Related Party Transaction [Line Items]
Sales To	0	1
Purchases From	$ (1)	$ (1)

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Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	$ 2	$ 3
Owed To	(10)	(43)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(2)	(9)
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	2	8
Owed To	(8)	(8)
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(2)	(2)
Other
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	$ (3)	$ (1)

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Related Party Transactions - Additional Information (Details) - USD ($)	3 Months Ended
	Mar. 31, 2022	Dec. 31, 2021
Iberdrola Solutions
Related Party Transaction [Line Items]
Notes payable	$ 2,000,000	$ 2,000,000
Affiliated Entity
Related Party Transaction [Line Items]
Impairments	0
Iberdrola
Related Party Transaction [Line Items]
Deposit balance	0	0
Iberdrola Financiacion, S.A.U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Credit facility fees percentage	0.105%
Credit facility, amount outstanding	$ 0	$ 0

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Other Financial Statement Items - Accounts Receivable and Unbilled Revenue (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Balance Sheet Related Disclosures [Abstract]
Trade receivables and unbilled revenues	$ 1,629	$ 1,420
Allowance for credit losses	(153)	(151)
Accounts receivable and unbilled revenues, net	$ 1,476	$ 1,269

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Other Financial Statement Items - Allowance For Credit Losses (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 153	$ 135
Current period provision	20	39
Write-off as uncollectible	(18)	(12)
Ending balance	$ 151	$ 108

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Other Financial Statement Items - Additional Information (Details) - USD ($) $ in Millions	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021	Jan. 31, 2022	Dec. 31, 2021	Dec. 31, 2020
Supplemental Balance Sheet Information [Line Items]
Allowance for doubtful accounts, deferred payment arrangement	$ 153	$ 135		$ 151	$ 108
Provision for doubtful accounts, accounts receivable	20	39
Prepaid other taxes	120			95
Advances received	178			204
Supplier Financing Arrangements
Supplemental Balance Sheet Information [Line Items]
Short-term debt	$ 35			$ 161
Weighted-average interest rate	2.08%			0.82%
United Illuminating Company (UI) | 2.25% Unsecured Notes Maturing In 2032 | Unsecured Debt
Supplemental Balance Sheet Information [Line Items]
Principal amount			$ 150
Fixed interest rate			2.25%
Deferred Payment Arrangements
Supplemental Balance Sheet Information [Line Items]
Accounts receivable	$ 112			$ 108
Allowance for doubtful accounts, deferred payment arrangement	71			$ 68
Provision for doubtful accounts, accounts receivable	$ 3	$ 5

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Other Financial Statement Items - Schedule of Accumulated Depreciation and Amortization (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Property, plant and equipment
Accumulated depreciation	$ 10,830	$ 10,589
Intangible assets
Accumulated amortization	$ 321	$ 317

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Income Tax Expense (Details)	3 Months Ended
	Mar. 31, 2022	Mar. 31, 2021
Income Tax Disclosure [Abstract]
Effective income tax rate	13.70%	4.20%

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Stock-Based Compensation Expense (Details) $ / shares in Units, $ in Millions	1 Months Ended					3 Months Ended
	Mar. 31, 2022 USD ($) installment $ / shares shares	Feb. 28, 2022 installment shares	Jan. 31, 2022 $ / shares shares	Mar. 31, 2020 installment shares	Feb. 29, 2020 installment shares	Mar. 31, 2022 USD ($) $ / shares	Mar. 31, 2021 USD ($)	Dec. 31, 2021 USD ($)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Share-based Payment Arrangement, Expense | $						$ 5	$ 4
Performance Shares Units (PSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	17,501				208,268
Number of vesting installments | installment	3				3
Number of shares issued (in shares)	46,737
Grant date fair value (in dollars per share) | $ / shares	$ 36.22					$ 36.22
Restricted Stock Units (RSUs) | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)			17,500
Number of shares issued (in shares)			9,390
Grant date fair value (in dollars per share) | $ / shares			$ 48.16
Phantom Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)		9,000		167,060
Number of vesting installments | installment		3		3
Cash used to settle award | $	$ 2
Share based compensation liability | $	$ 0					$ 0		$ 2

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Variable Interest Entities (Details) - USD ($) $ in Millions	Mar. 31, 2022	Dec. 31, 2021
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)	$ 39,541	$ 39,504
Liabilities of variable interest entities (VIEs)	19,481	19,543
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)	2,006	2,039
Liabilities of variable interest entities (VIEs)	$ 91	$ 119

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Equity Method Investments (Details) $ in Millions		1 Months Ended			12 Months Ended
	Jan. 10, 2022 USD ($)	Dec. 31, 2021 USD ($) MW	Dec. 31, 2020 USD ($)	Dec. 31, 2019 MW	Dec. 31, 2020 USD ($)	Dec. 31, 2018 MW	Mar. 31, 2022 USD ($) a	Sep. 15, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments		$ 560					$ 434
Vineyard Wind Limited Liability Company
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage							50.00%
Area of land (in acres) | a							166,886
Proposed wind farm and electricity transmission project capacity (in MW) | MW		1,232		804		800
Equity method investments		$ 141					$ 15
Vineyard Wind Limited Liability Company | Avangrid Renewables
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%		50.00%
Amount funded to date			$ 33		$ 100
Joint Venture With CIP
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage								50.00%
Amount of guaranty issued								$ 827
Amount contributed to acquire easement contract, returned								152
Joint Venture With CIP | Letter of Credit
Schedule of Equity Method Investments [Line Items]
Line of credit facility, maximum borrowing capacity								1,200
Joint Venture With CIP | Renewables
Schedule of Equity Method Investments [Line Items]
Joint venture restructuring agreement, payment amount								$ 168
Joint venture restructuring agreement, pretax gain recognized	$ 246
Joint venture restructuring agreement, after tax gain recognized	$ 181

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Subsequent Event (Details) - Subsequent Event - USD ($) $ in Millions	Apr. 29, 2022	Apr. 06, 2022
Subsequent Event [Line Items]
TEF agreement, investment amount received from tax equity investor	$ 14
TEF agreement, investment amount expected from tax equity investor	$ 58
NYSEG | Pollution Control Bonds
Subsequent Event [Line Items]
Face amount of debt		$ 67
Fixed interest rate		4.00%
Bonds priced as percentage of principal amount		104.15%
Bonds yield rate		3.30%