Avangrid, Inc. - Quarter Report: 2023 March (Form 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, 2023


☐			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 25, 2023, the registrant had 386,640,918 shares of common stock, par value $0.01, outstanding.

Avangrid, Inc.

REPORT ON FORM 10-Q

For the Quarter Ended March 31, 2023

INDEX


GLOSSARY OF TERMS AND ABBREVIATIONS		3
PART I. FINANCIAL INFORMATION		4
Item 1.	Financial Statements	4
Item 2.	Management’s Discussion and Analysis of Financial Condition and Results of Operations	48
Item 3.	Quantitative and Qualitative Disclosures about Market Risk	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	67
SIGNATURES		68

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
PBR						Performance-Based Regulation
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, 2022, filed with the Securities and Exchange Commission on March 1, 2023.
HLBV						Hypothetical Liquidation at Book Value
HSR						Hart-Scott-Rodino Antitrust Improvements Act of 1976
IRA						Inflation Reduction Act
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

PART I. FINANCIAL INFORMATION

Item 1. Financial Statements

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Income

(unaudited)


	Three Months Ended March 31,
		2023		2022
(Millions, except for number of shares and per share data)
Operating Revenues		$	2,466	$	2,133
Operating Expenses
Purchased power, natural gas and fuel used		977		741
Operations and maintenance		761		651
Depreciation and amortization		280		261
Taxes other than income taxes		183		178
Total Operating Expenses		2,201		1,831
Operating Income		265		302
Other Income and (Expense)
Other income		25		11
Earnings from equity method investments		2		253
Interest expense, net of capitalization		(95)		(71)
Income Before Income Tax		197		495
Income tax (benefit) expense		(18)		68
Net Income		215		427
Net loss attributable to noncontrolling interests		30		18
Net Income Attributable to Avangrid, Inc.		$	245	$	445
Earnings Per Common Share, Basic		$	0.63	$	1.15
Earnings Per Common Share, Diluted		$	0.63	$	1.15
Weighted-average Number of Common Shares Outstanding:
Basic		386,744,996		386,698,132
Diluted		387,077,213		387,114,285

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

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Comprehensive Income

(unaudited)


	Three Months Ended March 31,
		2023		2022
(Millions)
Net Income		$	215	$	427
Other Comprehensive Income (Loss)
Gain for defined benefit plans, net of income taxes of $0 and $3, respectively		—		8
Amortization of pension cost, net of income taxes of $0 and $0, respectively		—		1
Unrealized (loss) gain from equity method investment, net of income taxes of $0 and $5, respectively		(1)		15
Unrealized loss during the period on derivatives qualifying as cash flow hedges, net of income tax of $(1) and $(15), respectively		(2)		(39)
Reclassification to net income of loss on cash flow hedges, net of income taxes $18 and $4, respectively		52		11
Other Comprehensive Income (Loss)		49		(4)
Comprehensive Income		264		423
Net loss attributable to noncontrolling interests		30		18
Comprehensive Income Attributable to Avangrid, Inc.		$	294	$	441

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

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)


	March 31,		December 31,
As of	2023		2022
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	72	$	69
Accounts receivable and unbilled revenues, net	1,669		1,737
Accounts receivable from affiliates	2		5
Notes receivable from affiliates	3		3
Derivative assets	65		60
Fuel and gas in storage	185		268
Materials and supplies	249		235
Prepayments and other current assets	406		386
Regulatory assets	489		447
Total Current Assets	3,140		3,210
Total Property, Plant and Equipment ($2,698 and $2,707 related to VIEs, respectively)	31,249		30,994
Operating lease right-of-use assets	199		159
Equity method investments	440		437
Other investments	43		49
Regulatory assets	2,473		2,321
Other Assets
Goodwill	3,119		3,119
Intangible assets	278		281
Derivative assets	104		140
Other	413		413
Total Other Assets	3,914		3,953
Total Assets	$	41,458	$	41,123

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

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Balance Sheets

(unaudited)


	March 31,		December 31,
As of	2023		2022
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	413	$	412
Notes payable	1,291		566
Notes payable to affiliates	2		2
Interest accrued	93		66
Accounts payable and accrued liabilities	1,562		2,007
Accounts payable to affiliates	16		39
Dividends payable	170		170
Taxes accrued	78		61
Operating lease liabilities	12		13
Derivative liabilities	98		133
Other current liabilities	483		593
Regulatory liabilities	352		354
Total Current Liabilities	4,570		4,416
Regulatory liabilities	2,884		2,915
Other Non-current Liabilities
Deferred income taxes	2,270		2,234
Deferred income	1,048		1,062
Pension and other postretirement	484		491
Operating lease liabilities	201		161
Derivative liabilities	135		164
Asset retirement obligations	277		273
Environmental remediation costs	277		279
Other	559		563
Total Other Non-current Liabilities	5,251		5,227
Non-current debt	8,235		8,215
Non-current debt to affiliate	8		8
Total Non-current Liabilities	16,378		16,365
Total Liabilities	20,948		20,781
Commitments and Contingencies
Equity
Stockholders’ Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,747,089 and 387,734,757 shares issued; 386,640,918 and 386,628,586 shares outstanding, respectively	3		3
Additional paid in capital	17,697		17,694
Treasury stock	(47)		(47)
Retained earnings	1,985		1,910
Accumulated other comprehensive loss	(131)		(180)
Total Stockholders’ Equity	19,507		19,380
Non-controlling interests	1,003		962
Total Equity	20,510		20,342
Total Liabilities and Equity	$	41,458	$	41,123

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

Avangrid, Inc. and Subsidiaries

Condensed Consolidated Statements of Cash Flows

(unaudited)


	Three Months Ended March 31,
	2023		2022
(Millions)
Cash Flow from Operating Activities:
Net income	$	215	$	427
Adjustments to reconcile net income to net cash provided by operating activities:
Depreciation and amortization	280		261
Regulatory assets/liabilities amortization and carrying cost	(32)		2
Pension cost	(3)		8
Earnings from equity method investments	(2)		(253)
Distributions of earnings received from equity method investments	6		5
Unrealized loss on marked-to-market derivative contracts	4		3
Deferred taxes	(1)		51
Other non-cash items	(5)		—
Changes in operating assets and liabilities:
Current assets	82		(183)
Noncurrent assets	(96)		(127)
Current liabilities	(242)		196
Noncurrent liabilities	(2)		(2)
Net Cash Provided by Operating Activities	204		388
Cash Flow from Investing Activities:
Capital expenditures	(836)		(811)
Contributions in aid of construction	19		30
Proceeds from sale of assets	6		3
Proceeds from notes receivable from affiliates	1		—
Distributions received from equity method investments	2		2
Other investments and equity method investments, net	(11)		(172)
Net Cash Used in Investing Activities	(819)		(948)
Cash Flow from Financing Activities:
Non-current debt issuances	—		149
Repayments of non-current debt	(4)		(89)
Receipts (Repayments) of other short-term debt, net	722		(161)
Repayments of financing leases	(1)		(6)

Issuance of common stock	—		(1)
Distributions to noncontrolling interests	(3)		(1)
Contributions from noncontrolling interests	74		13
Dividends paid	(170)		(170)
Net Cash Provided by (Used in) Financing Activities	618		(266)
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash	3		(826)
Cash, Cash Equivalents and Restricted Cash, Beginning of Period	72		1,477
Cash, Cash Equivalents and Restricted Cash, End of Period	$	75	$	651
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	56	$	55
Cash (refunded) paid for income taxes	$	(1)	$	5

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

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, 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
As of December 31, 2022	386,628,586	$	3	$	17,694	$	(47)	$	1,910	$	(180)	$	19,380	$	962	$	20,342

Net income (loss)	—	—		—		—		245		—		245		(30)		215
Other comprehensive income, net of tax of $17	—	—		—		—		—		49		49		—		49
Comprehensive income																264
Dividends declared, $0.44/share	—	—		—		—		(170)		—		(170)		—		(170)

Issuance of common stock	12,332	—		—		—		—		—		—		—		—

Stock-based compensation	—	—		3		—		—		—		3		—		3
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(3)		(3)
Contributions from noncontrolling interests	—	—		—		—				—		—		74		74
As of March 31, 2023	386,640,918	$	3	$	17,697	$	(47)	$	1,985	$	(131)	$	19,507	$	1,003	$	20,510

(*) Par value of share amounts is $0.01

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

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 14.7% 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 was 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 (HSR)), 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, 2021, 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's subsidiary, Public Service Company of New Mexico (PNM), AVANGRID and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNM 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. On June 14, 2022, the NMPRC filed its Answer Brief. On June 13, 2022, New Energy Economy, an intervener in the Merger proceeding, filed its Answer Brief. AVANGRID's Reply Brief was filed on August 5, 2022. On March 8, 2023, AVANGRID, PNM and the NMPRC filed a motion to dismiss the appeal and remand the proceeding back to the NMPRC for further proceedings. The motion states that, once granted, AVANGRID and PNM intend to file a motion for rehearing and/or reconsideration at the NMPRC. One party opposed the motion and certain other parties have sought clarification regarding the process that the NMPRC would implement on remand.

On February 24, 2022, the FCC granted an extension to its approval to transfer operating licenses in connection with the Merger, which was further extended on August 9, 2022 and again on February 16, 2023. On May 20, 2022, the NRC issued an order extending the effectiveness of its approval until May 25, 2023, and again on March 14, 2023 until May 25, 2024. Furthermore, a new HSR filing was submitted and the waiting period expired at 11:50 pm on March 10, 2023, providing HSR clearance for another year. On September 21, 2022, New Energy Economy filed a motion to show cause with the NMPRC alleging that AVANGRID and PNM have engaged in a misleading joint advertising and sponsorship strategy and requesting an investigation. AVANGRID and PNM filed a reply to the motion to show cause on October 11, 2022. On December 14, 2022, the NMPRC issued an order denying the motion.

In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the First 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 acknowledged in the First Amendment that the required regulatory approval from the NMPRC had not been obtained and that the parties reasonably determined that such outstanding approval would not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the First Amendment. Subsequently, on April 12, 2023, AVANGRID, PNMR and Merger Sub entered into a Second Amendment to the Merger Agreement (the Second Amendment), pursuant to which AVANGRID, PNMR and Merger Sub each agreed to further extend the “End Date” for consummation of the Merger until July 20, 2023. The parties acknowledged in the Second Amendment that the required regulatory approval from the NMPRC had not been obtained and that the parties reasonably determined that such outstanding approval would not be obtained by April 20, 2023. As amended by the Second Amendment, the Merger Agreement may be terminated by each of AVANGRID and PNMR under certain circumstances, including if the Merger is not consummated by July 20, 2023. During the pendency of the appeal described above, 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 any other re-applications or requests for extensions of such approvals that may be required.

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 July 20, 2023. 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, up to a maximum aggregate amount of approximately $4,300 million, 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, 2022.

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, 2023, are not necessarily indicative of the results for the entire fiscal year ending December 31, 2023.

Note 3. Significant Accounting Policies and New Accounting Pronouncements

The new accounting pronouncements we have adopted as of January 1, 2023, 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, 2022, 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) Disclosure of Supplier Finance Program Obligations

In September 2022, the FASB issued new disclosure requirements for supplier finance programs. These requirements include key terms of the program, the amount of obligations that remain unpaid at the end of an accounting period, a description of where those obligations are presented in the balance sheet and a roll forward of those obligations during the annual period. We adopted the new disclosure requirements pursuant to this guidance on January 1, 2023.

Accounting Pronouncements Issued but Not Yet Adopted

There are no new accounting pronouncements not yet adopted, including those issued since December 31, 2022, that will materially affect our condensed consolidated financial statements.

Note 4. Revenue

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

The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about 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. Networks entities calculate revenue earned but not yet billed based on the number of days not billed in the month, the estimated amount of energy delivered during those days and the estimated average price per customer class for that month. Differences between actual and estimated unbilled revenue are immaterial.

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. We record revenue for all of such sales based upon the regulatory-approved tariff and the volume delivered or transmitted, which corresponds to the amount that we have a right to invoice. There are no material initial incremental costs of obtaining a contract in any of the arrangements. Networks does not adjust the promised consideration for the effects of a significant financing component if it expects, at contract inception, that the time between the delivery of promised goods or service and customer payment will be one year or less. For its New York and Connecticut utilities, Networks assesses its DPAs at each balance sheet date for the existence of significant financing components, but has had no material adjustments as a result.

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. The Networks entities recognize and record only the initial recognition of “originating” ARP revenues (when the regulatory-specified conditions for recognition have been met). When they subsequently include those amounts in the price of utility service billed to customers, they record such amounts as a recovery of the associated regulatory asset or liability. When they owe amounts to customers in connection with ARPs, they evaluate those amounts on a quarterly basis and include them in the price of utility service billed to customers and do not reduce ARP revenues.

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. There are no material initial incremental costs of obtaining a contract or significant financing elements in any of the arrangements.

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.

Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration.

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 November 2023 upon commercial operation. Contract assets totaled $9 million at both March 31, 2023 and December 31, 2022, 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 $16 million and $33 million at March 31, 2023 and December 31, 2022, respectively, and are presented in "Other current liabilities" on our condensed consolidated balance sheets. We recognized $17 million and $8 million as revenue during the three months ended March 31, 2023 and 2022, respectively.

Revenues disaggregated by major source for our reportable segments for the three months ended March 31, 2023 and 2022 are as follows:


	Three Months Ended March 31, 2023
		Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity		$	1,308	$	—	$	—	$	1,308
Regulated operations – natural gas		722		—		—		722
Nonregulated operations – wind		—		216		—		216
Nonregulated operations – solar		—		4		—		4
Nonregulated operations – thermal		—		55		—		55
Other(a)		(3)		(13)		—		(16)
Revenue from contracts with customers		2,027		262		—		2,289
Leasing revenue		2		—		—		2
Derivative gains		—		122		—		122
Alternative revenue programs		37		—		—		37
Other revenue		10		6		—		16
Total operating revenues		$	2,076	$	390	$	—	$	2,466


	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

(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, 2023 and December 31, 2022, accounts receivable balances related to contracts with customers were approximately $1,603 million and $1,622 million, respectively, including unbilled revenues of $410 million and $541 million, which are included in “Accounts receivable and unbilled revenues, net” on our condensed consolidated balance sheets.

As of March 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:


As of March 31, 2023	2024		2025		2026		2027		2028		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	1	$	—	$	—	$	—	$	—	$	—	$	1
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	85		12		10		7		5		60		179
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	53		23		5		3		1		2		87
Total operating revenues	$	139	$	35	$	15	$	10	$	6	$	62	$	267

As of March 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) for the remainder of 2023 was $109 million.

We do not disclose information about remaining performance obligations for contracts for which we recognize revenue in the amount to which we have the right to invoice (e.g., usage-based pricing terms).

Note 5. Regulatory Assets and Liabilities

Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize as regulatory assets incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific 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, 2023, the total net amount of these items is approximately $1,012 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. In an order dated February 7, 2023, the MPUC closed this investigation after consolidating its records with CMP’s pending rate case.

In accordance with Chapter 120 of MPUC Rules, on May 26, 2022, CMP filed a nonbinding notice of intent to file a distribution rate case on or after sixty days from the issuance of the letter. In the notice, CMP signaled its intent to propose a three-year rate plan, which includes a multi-year capital investment plan to fund investments needed to improve reliability and

resiliency, as well as to continue to improve the customer experience and cost-effectively advance clean energy transformation. CMP’s notice estimated a revenue change in the range of $45 to $50 million in the first year of the rate plan followed by increases in the range of $25 to $30 million in the second year and $20 to $25 million in the third year. We cannot predict the outcome of this matter.

On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. In its filing, CMP has set the three rate years as May 10, 2023 to May 9, 2024 (“Rate Year 1”); May 10, 2024 to May 9, 2025 (“Rate Year 2”); and May 10, 2025 to May 9, 2026 (“Rate Year 3”). The requested Rate Year revenue requirement increases for the rate years are $48 million, $28 million and $23 million, respectively. The revenue requirement adjustments are based on a test year ending December 31, 2021. The requested revenue changes for each rate year of the proposal are subject to four adjustment mechanisms: (1) a yearly review of plant additions with potential downward reconciliation in the event of an underspend, (2) a capital adjustment mechanism for certain incremental pole replacements, broadband work, electric vehicle work, energy storage projects, and metering system upgrades, (3) a symmetrical inflation reconciliation adjustment, and (4) reconciliation of the benefits associated with the tax basis repair deduction. Other parties filed direct testimony in this proceeding on December 2, 2022 and CMP filed rebuttal testimony on February 7, 2023. Settlement discussions are on-going and technical conferences are scheduled for mid-May 2023. New rates are expected to take effect on or around August 2023. We cannot predict the outcome of this matter.

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. Rate years two and three commence on May 1, 2021 and 2022, respectively:


	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	%

On May 26, 2022, NYSEG and RG&E filed for a new rate plan with the NYPSC. The rate filings are based on test year 2021 financial results adjusted to the rate year May 1, 2023 – April 30, 2024. Since these rate filings were submitted on May 26, 2022, the effective date of new rates, assuming an approximately 11-month approval period, will be May 1, 2023. NYSEG and RG&E filed for a one-year rate plan but expressed interest in exploring a multi-year plan during the pendency of the case (as is the custom in New York). On August 12, 2022, NYSEG and RG&E filed an update to its rate plan filing called for in the litigation schedule. In their filings, the following revenue changes were requested:


Requested Revenue Change
	May 26, 2022		August 12, 2022		Difference
Utility	(Millions)		(Millions)		(Millions)
NYSEG Electric	$	274	$	274	$	—
NYSEG Gas	$	43	$	30	$	(13)
RG&E Electric	$	94	$	93	$	(1)
RG&E Gas	$	38	$	32	$	(6)

On September 16, 2022, the NYPSC suspended new tariffs and rates through April 21, 2023. On October 19, 2022, consistent with the Administrative Law Judge’s’ July 1, 2022 Ruling on Schedule and Party Status, NYSEG and RG&E voluntarily agreed to 60-day extension of maximum suspension period through June 20, 2023, subject to a make-whole provision. On December

21, 2022, NYSEG and RG&E voluntarily agreed to further 60-day extension of maximum suspension period to postpone through August 19, 2023, subject to a make-whole provision. On February 16, 2023, NYSEG and RG&E voluntarily agreed to a further 30-day extension of the suspension period through September 18, 2023, subject to a make-whole provision. On April 11, 2023, the NYSEG and RG&E requested a further 30-day suspension through October 18, 2023, subject to a make-whole provision. During this time, the parties have conducted multi-party rate case settlement negotiations. We cannot predict the outcome of this proceeding.

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.

On September 9, 2022, UI filed a distribution revenue requirement case. UI’s filing proposes a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing is based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (“UI Rate Year 1”), September 1, 2024 (“UI Rate Year 2”), and September 1, 2025 (“UI Rate Year 3”). UI is requesting that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $102 million in UI Rate Year 1, an incremental approximately $17 million in UI Rate Year 2, and an incremental approximately $17 million in UI Rate Year 3, compared to total revenues that would otherwise be recovered under UI’s current rate schedules. UI’s Rate Plan also includes several measures to moderate the impact of the proposed rate update for all customers, including, without limitation a rate levelization proposal to spread the proposed total rate increase over the three rate years, which would result in a change in revenue in UI Rate Year 1 of approximately $54 million. Other parties filed direct testimony on December 13, 2022 and UI filed its rebuttal testimony on January 6, 2023. Rate case hearings started on February 16, 2023 and concluded on March 22, 2023 with initial briefs due April 27, 2023. Litigation of the case is expected to take approximately one year with new rates expected to go into effect on or around September 2023. We cannot predict the outcome of this matter.

In 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 for a three-year rate plan with annual rate increases. 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.

On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval. The Settlement Agreement followed BGC’s December 14, 2021 filing of a Notice of Intent to File Rate Schedules. Following that filing, BGC and the AGO negotiated the Settlement Agreement in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allows for agreed-upon adjustments to BGC’s revenue requirement as well as various step increases BGC shall be entitled to on January 1, 2023 and January 1, 2024. The Settlement Agreement provides that it shall be void unless approved in its entirety by the DPU by November 1, 2022. It provides for the opportunity to increase BGC’s revenue requirement by as much as $5.6 million over current rates (reflective of a 9.70% ROE and a 54.00% equity ratio as well as other stepped adjustments) through January 1, 2024. The Settlement Agreement was approved in its entirety by the DPU on October 27, 2022, and new rates went into effect January 1, 2023.

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.

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 approximately $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. Oral arguments were held on October 11, 2022, and on October 17, 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI filed a notice of appeal to Connecticut's Appellate court on November 7, 2022. We cannot predict the outcome of this proceeding.

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, 2023 and December 31, 2022, respectively, consisted of:


	March 31,		December 31,
As of	2023		2022
(Millions)
Pension and other post-retirement benefits cost deferrals	$	363	$	365
Pension and other post-retirement benefits	70		93
Storm costs	766		671
Rate adjustment mechanism	55		41
Revenue decoupling mechanism	66		52
Transmission revenue reconciliation mechanism	7		11
Contracts for differences	52		56
Hardship programs	31		33
Plant decommissioning	1		1
Deferred purchased gas	9		56

Environmental remediation costs	247		248
Debt premium	62		64
Unamortized losses on reacquired debt	20		19
Unfunded future income taxes	504		492
Federal tax depreciation normalization adjustment	135		137
Asset retirement obligation	20		20
Deferred meter replacement costs	57		55
COVID-19 cost recovery and late payment surcharge	14		17
Low income arrears forgiveness	68		31
Excess generation service charge	77		24
System Expansion	16		21
Non-bypassable charge	46		14
Hedges losses	50		13
Other	226		234
Total regulatory assets	2,962		2,768
Less: current portion	489		447
Total non-current regulatory assets	$	2,473	$	2,321

“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.

“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 46 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 and late payment surcharge" represents: a) 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, and b) deferred lost late payment revenue in the state of New York based on the order issued by the NYPSC on June 17, 2022, approving deferral and surcharge/sur-credit mechanism to recover/return deferred balances starting July 1, 2022.

“Low-income arrears forgiveness” represents deferred bill credits in the state of New York based on the order issued by the NYPSC on June 16, 2022, approving deferral of bill credits for low-income customers and recovery of regulatory asset from all customers over five years for RG&E and three years for NYSEG. Surcharge will start August 1, 2022.

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

“System expansion” represents expenses not covered by system expansion rates related to expanding the natural gas system and converting customers to natural gas.

“Non-bypassable charges” represent non-bypassable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.

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

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

Regulatory liabilities as of March 31, 2023 and December 31, 2022, respectively, consisted of:


	March 31,		December 31,
As of	2023		2022
(Millions)
Energy efficiency portfolio standard	$	25	$	30
Gas supply charge and deferred natural gas cost	28		15
Pension and other post-retirement benefits cost deferrals	112		117
Carrying costs on deferred income tax bonus depreciation	5		9
Carrying costs on deferred income tax - Mixed Services 263(a)	2		3
2017 Tax Act	1,218		1,232
Rate Change Levelization	13		25
Revenue decoupling mechanism	8		13
Accrued removal obligations	1,167		1,178

Economic development	17		20
Positive benefit adjustment	14		16
Theoretical reserve flow thru impact	3		3
Deferred property tax	17		17
Net plant reconciliation	9		11
Debt rate reconciliation	27		32
Rate refund – FERC ROE proceeding	36		36
Transmission congestion contracts	32		31
Merger-related rate credits	9		10
Accumulated deferred investment tax credits	22		22
Asset retirement obligation	17		18
Earning sharing provisions	8		13
Middletown/Norwalk local transmission network service collections	16		17
Low income programs	19		18
Non-firm margin sharing credits	24		27
New York 2018 winter storm settlement	1		1

Non by-passable charges	63		76
Transmission revenue reconciliation mechanism	73		75
Other	251		204
Total regulatory liabilities	3,236		3,269
Less: current portion	352		354
Total non-current regulatory liabilities	$	2,884	$	2,915

“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, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions.

“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.

“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, 2023 and 2022, $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.

“Non-firm margin sharing credits” represents the portion of interruptible and off-system sales revenue set aside to fund gas expansion projects.

“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.

“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. Our Rabbi Trusts, which cover certain deferred compensation plans and non-qualified pension plan obligations, consists of equity and other investments. The Rabbi Trusts primarily invest in equity securities, fixed income and money market funds. Certain Rabbi Trusts also invest in trust or company owned life insurance policies. 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 modeled volumes on unit-contingent contracts, extrapolated power curves through May 2032 and scheduling assumptions on California power exports to cover Nevada physical power sales. 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) the Secured Overnight Financing Rate (SOFR), forward interest rate curves or other relevant benchmark. 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, 2023 and December 31, 2022, respectively and is included in "Other Assets" on our condensed consolidated balance sheets.

The financial instruments measured at fair value as of March 31, 2023 and December 31, 2022, respectively, consisted of:


As of March 31, 2023	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	29	$	13	$	—	$	—	$	42
Derivative assets
Derivative financial instruments - power	$	15	$	58	$	134	$	(137)	$	70
Derivative financial instruments - gas	—		26		4		(22)		8
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		90		—		—		90
Total	$	15	$	174	$	139	$	(159)	$	169
Derivative liabilities
Derivative financial instruments - power	$	(55)	$	(245)	$	(72)	$	288	$	(84)
Derivative financial instruments - gas	(10)		(20)		—		29		(1)
Contracts for differences	—		—		(53)		—		(53)
Derivative financial instruments – Other	—		(95)		—		—		(95)
Total	$	(65)	$	(360)	$	(125)	$	317	$	(233)


As of December 31, 2022	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity investments with readily determinable fair values	$	35	$	13	$	—	$	—	$	48
Derivative assets
Derivative financial instruments - power	$	37	$	55	$	165	$	(177)	$	80
Derivative financial instruments - gas	1		47		—		(45)		3
Contracts for differences	—		—		1		—		1
Derivative financial instruments – Other	—		116		—		—		116
Total	$	38	$	218	$	166	$	(222)	$	200
Derivative liabilities
Derivative financial instruments - power	$	(46)	$	(350)	$	(93)	$	364	$	(125)
Derivative financial instruments - gas	(4)		(26)		—		30		—
Contracts for differences	—		—		(57)		—		(57)
Derivative financial instruments - Other	—		(115)		—		—		(115)
Total	$	(50)	$	(491)	$	(150)	$	394	$	(297)

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the three months ended March 31, 2023 and 2022, respectively, is as follows:


	Three Months Ended March 31,
(Millions)		2023		2022
Fair Value Beginning of Period,		$	16	$	(69)
Gains recognized in operating revenues		—		38
(Losses) recognized in operating revenues		(3)		(40)
Total losses recognized in operating revenues		(3)		(2)
Gains recognized in OCI		11		2
(Losses) recognized in OCI		(3)		(63)
Total gains (losses) recognized in OCI		8		(61)
Net change recognized in regulatory assets and liabilities		4		4
Purchases		9		(1)
Settlements		(20)		5

Fair Value as of March 31,		$	14	$	(124)
Losses for the period included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date		$	(3)	$	(2)

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, 2023
Index	Avg.		Max.		Min.
NYMEX ($/MMBtu)	$	4.53	$	9.86	$	1.99
AECO ($/MMBtu)	$	3.20	$	10.80	$	1.23
Ameren ($/MWh)	$	54.23	$	225.62	$	22.08
COB ($/MWh)	$	80.39	$	400.10	$	10.85
ComEd ($/MWh)	$	49.88	$	222.49	$	18.78
ERCOT S hub ($/MWh)	$	49.97	$	320.63	$	16.85
Mid C ($/MWh)	$	77.60	$	400.10	$	7.85
AEP-DAYTON hub ($/MWh)	$	55.26	$	229.75	$	24.44
PJM W hub ($/MWh)	$	58.12	$	227.60	$	24.76

Our Level 3 valuations primarily consist of Hydro PPAs utilized for balancing services for the Northwest wind fleet, power swaps with delivery periods extending through May 2032 hedging Midwest and Texas wind farms and physical power sales agreements in Nevada.

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 primary 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 hydro PPAs are long capacity/energy positions in the Northwest that provide balancing services with increases in power prices resulting in unrealized gains and decreases in power prices resulting in unrealized losses. The gas swaps are economic hedges of fuel purchases for a combined cycle gas plant, with increases in gas prices resulting in unrealized gains and decreases 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 and the modeled volumes on unit-contingent agreements. 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 prices and estimated volumes. 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, 2023
Risk of non-performance						0.76%
Discount rate						3.60% - 3.81%
Forward pricing ($ per KW-month)						$2.00 - $3.80

Fair Value of Debt

As of March 31, 2023 and December 31, 2022, debt consisted of first mortgage bonds, unsecured pollution control notes and other various non-current debt securities. The estimated fair value of debt was $8,168 million and $7,991 million as of March 31, 2023 and December 31, 2022, 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, 2023 and December 31, 2022, 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, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	13	$	4	$	12	$	3
Derivative liabilities	(12)		(3)		(71)		(47)
	1		1		(59)		(44)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	1		1		(59)		(44)
Cash collateral receivable	—		—		41		8
Total derivatives as presented in the balance sheet	$	1	$	1	$	(18)	$	(36)


As of December 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	30	$	8	$	30	$	7
Derivative liabilities	(30)		(7)		(58)		(50)
	—		1		(28)		(43)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		—		—
	—		—		—		—
Total derivatives before offset of cash collateral	—		1		(28)		(43)
Cash collateral receivable	—		—		11		2
Total derivatives as presented in the balance sheet	$	—	$	1	$	(17)	$	(41)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of March 31, 2023 and December 31, 2022, respectively, consisted of:


	March 31,	December 31,
As of	2023	2022
(Millions)
Wholesale electricity purchase contracts (MWh)	5.6	5.7
Natural gas purchase contracts (Dth)	7.9	9.6

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, 2023 and December 31, 2022 and amounts reclassified from regulatory assets and liabilities into income for the three months ended March 31, 2023 and 2022 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, 2023	Electricity		Natural Gas		2023		Electricity		Natural Gas
Regulatory assets	$	40	$	10	Purchased power, natural gas and fuel used		$	49	$	6

December 31, 2022					2022
Regulatory assets	$	9	$	4	Purchased power, natural gas and fuel used		$	(45)	$	(9)

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, 2023, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $52 million, a gross derivative liability of $53 million ($52 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, 2022, UI had recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $56 million, a gross derivative liability of $57 million ($55 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, 2023 and 2022, respectively, were as follows:


	Three Months Ended March 31,
		2023		2022
(Millions)

Derivative liabilities		$	4	$	4

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, 2023 and 2022, respectively, consisted of:


Three Months Ended March 31,	Gain (Loss) Recognized in OCI on Derivatives (a)		Location of Loss (Gain) Reclassified from Accumulated OCI into Income	Loss (Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2023
Interest rate contracts	$	—	Interest expense	$	1	$	95
Commodity contracts	—		Purchased power, natural gas and fuel used	—		977

Total	$	—		$	1
2022
Interest rate contracts	$	—	Interest expense	$	1	$	71
Commodity contracts	2		Purchased power, natural gas and fuel used	(1)		741

Total	$	2		$	—

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

The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $42 million and $43 million as of March 31, 2023 and December 31, 2022, respectively. For both the three months ended March 31, 2023 and 2022, 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 2023.

(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, 2023 and December 31, 2022, respectively, consisted of:


	March 31,	December 31,
As of	2023	2022
(MWh/Dth in millions)
Wholesale electricity purchase contracts	2	2
Wholesale electricity sales contracts	7	7
Natural gas and other fuel purchase contracts	20	15
Financial power contracts	6	6
Basis swaps – purchases	26	22
Basis swaps – sales	2	—

The fair values of derivative contracts associated with Renewables' activities as of March 31, 2023 and December 31, 2022, respectively, consisted of:


	March 31,		December 31,
As of	2023		2022
(Millions)
Wholesale electricity purchase contracts	$	110	$	149
Wholesale electricity sales contracts	(134)		(200)
Natural gas and other fuel purchase contracts	8		2
Financial power contracts	9		8


Total	$	(7)	$	(41)

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, 2023 and December 31, 2022, the fair value of the interest rate swap was $90 million and $116 million, respectively, as a non-current asset. 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, 2023 and December 31, 2022, 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, 2023	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	106	$	49	$	53	$	5
Derivative liabilities	(42)		(36)		(77)		(6)
	64		13		(24)		(1)
Designated as hedging instruments
Derivative assets	—		90		4		4
Derivative liabilities	—		—		(102)		(74)
	—		90		(98)		(70)
Total derivatives before offset of cash collateral	64		103		(122)		(71)
Cash collateral receivable	—		—		70		39
Total derivatives as presented in the balance sheet	$	64	$	103	$	(52)	$	(32)


As of December 31, 2022	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	121	$	63	$	79	$	4
Derivative liabilities	(61)		(40)		(103)		(7)
	60		23		(24)		(3)
Designated as hedging instruments
Derivative assets	—		116		—		1
Derivative liabilities	—		—		(168)		(89)
	—		116		(168)		(88)
Total derivatives before offset of cash collateral	60		139		(192)		(91)
Cash collateral receivable	—		—		105		54
Total derivatives as presented in the balance sheet	$	60	$	139	$	(87)	$	(37)

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, 2023 and 2022, consisted of:


	Three Months Ended March 31, 2023
		Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts		$	(4)	$	1
Wholesale electricity sales contracts		7		24
Financial power contracts		2		15
Financial and natural gas contracts		—		10
Total gain included in operating revenues		$	5	$	50	$	2,466

Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts		$	—	$	(35)

Financial power contracts		—		—
Financial and natural gas contracts		—		(21)
Total loss included in purchased power, natural gas and fuel used		$	—	$	(56)	$	977

Total Gain (Loss)		$	5	$	(6)


	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)

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, 2023 and 2022, 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)
2023
Interest rate contracts	$	90	Interest Expense	$	—	$	95
Commodity contracts	23		Operating revenues	66		$	2,466
Total	$	113		$	66
2022
Interest rate contracts	$	(56)	Interest Expense	$	—	$	71
Commodity contracts	(112)		Operating revenues	11		$	2,133
Total	$	(168)		$	11

(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 $99 million of losses included in accumulated OCI at March 31, 2023, 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, 2023 and 2022.

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, 2023 and December 31, 2022, the net loss in accumulated OCI related to previously settled interest rate contracts was $36 million and $38 million, respectively. For both the three months ended March 31, 2023 and 2022, 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 2023.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the three months ended March 31, 2023 and 2022, 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)
2023
Interest rate contracts	$	—	Interest expense	$	2	$	95

2022
Interest rate contracts	$	—	Interest expense	$	2	$	71

(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, 2023 and 2022 are as follows:


	Fair value of hedge		Location of Loss Recognized in Income Statement	Loss Recognized in Income Statement		Year to date total per Income Statement
(Millions)	As of March 31, 2023			Three Months Ended March 31, 2023
Current Liabilities	$	(28)	Interest Expense	$	7	$	95
Non-current liabilities	$	(67)

	Cumulative effect on hedged debt
Current debt	$	28
Non-current debt	$	67


	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, 2022			Three Months Ended March 31, 2022
Current Liabilities	$	(29)	Interest Expense	$	(2)	$	71
Non-current liabilities	$	(86)

	Cumulative effect on hedged debt
Current debt	$	29
Non-current debt	$	86

(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, 2023, UI would have had to post an aggregate of approximately $40 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, 2023 and December 31, 2022, the amount of cash collateral under master netting arrangements that have not been offset against net derivative positions was $96 million and $97 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, 2023 was $50 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 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 $28 million and $8 million, respectively, as of March 31, 2023, which has not changed since December 31, 2022, 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, the 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, or RPM, in addition to the DCF model and CAPM under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. 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. On August 9, 2022, the D.C. Circuit Court vacated the FERC’s orders and remanded the matter back to the FERC. The D.C. Circuit Court held that the FERC failed to offer a reasoned explanation for its decision to reintroduce the RPM after initially, and forcefully, rejecting it and that because the FERC adopted that significant portion of its model in an arbitrary and capricious fashion, the new ROE produced by that model cannot stand. We cannot predict the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for the NETO’s 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. 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. On June 23, 2022, the administrative law judge issued additional findings and analysis to FERC with respect to the other party in the matter. These did not address any of the Renewables’ claims. The entire case has now been fully remanded to FERC. We cannot predict the outcome of this proceeding.

Customer Service Invoice Dispute

On May 4, 2021, a buyer under a virtual PPA with a subsidiary of Renewables provided notice that the buyer disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations. The buyer has requested an adjustment to the invoices that would increase the amount payable by approximately $29 million. Renewables has responded in writing stating that the invoice was properly calculated in accordance with the provisions of the PPA. The parties participated in a mediation in March 2023. We cannot predict the outcome of this matter.

Guarantee Commitments to Third Parties

As of March 31, 2023, we had approximately $693 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. 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, 2023, 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-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; four sites are included in Maine’s Uncontrolled Sites Program; zero 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-four 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 seven of the twenty-four sites. We have paid remediation costs related to the remaining seventeen 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, 2023, 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; thirty-nine sites are included in the New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order of Consent; two sites with individual NYSDEC Orders of Consent; one site under a Brownfield Cleanup Program and three sites are included in Maine Department of Environmental Protection programs (one each in the Voluntary Response Action Program, Brownfield Cleanup Program and Uncontrolled Sites Program). The remaining sites are not included in a formal program. 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, 2023, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $154 million to $255 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, 2023, 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, 2023 and December 31, 2022, the liability associated with our MGP sites in Connecticut was $112 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, 2023 and December 31, 2022, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $282 million and $289 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 2092.

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, 2023, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $9 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

On April 8, 2013, DEEP issued an administrative order addressed to UI, 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, 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. On April 18, 2023, DEEP issued a letter to UI requiring a response within 30 days that provides alternative remediation proposals to remediate certain environmental conditions and provides an accounting of costs incurred in connection compliance with the Consent Order.

As of March 31, 2023 and December 31, 2022, the amount reserved related to English Station was $20 million and $19 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, 2023. We do not expect to make any additional contributions in 2023.

The components of net periodic benefit cost for pension benefits for the three months ended March 31, 2023 and 2022, respectively, consisted of:


	Three Months Ended March 31,
		2023		2022
(Millions)
Service cost		$	2	$	8
Interest cost		30		24
Expected return on plan assets		(36)		(45)
Amortization of:
Prior service costs		—		1
Actuarial loss		1		18
Curtailments and settlements		—		2
Net Periodic Benefit Cost		$	(3)	$	8

The components of net periodic benefit cost for postretirement benefits for the three months ended March 31, 2023 and 2022, respectively, consisted of:


	Three Months Ended March 31,
		2023		2022
(Millions)
Service cost		$	—	$	1
Interest cost		3		3
Expected return on plan assets		(1)		(2)
Amortization of:
Prior service costs		—		—
Actuarial loss		(3)		(1)
Net Periodic Benefit Cost		$	(1)	$	1

Note 11. Equity

As of both March 31, 2023 and December 31, 2022, we had 108,188 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the three months ended March 31, 2023 and 2022, we issued 12,332 and 56,127 shares of common stock, respectively, each having a par value of $0.01, and released 0 shares of common stock held in trust.

We maintain a repurchase agreement with J.P. Morgan Securities, LLC. (JPM), pursuant to which JPM will, from time to time, acquire, on behalf of AVANGRID, shares of common stock of AVANGRID. The purpose of the stock repurchase program is to allow AVANGRID to maintain Iberdrola's relative ownership percentage of approximately 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. As of March 31, 2023, 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, 2023.

Accumulated Other Comprehensive Loss

Accumulated Other Comprehensive Loss for the three months ended March 31, 2023 and 2022, 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,
	2022		2023		2023		2021		2022		2022
(Millions)
Gain for defined benefit plans, net of income tax expense of $0 for 2023 and $3 for 2022			$	—					$	8
Amortization of pension cost, net of income tax expense of $0 for 2023 and $0 for 2022			—						1
Net (loss) gain on pension plans	(20)		—		(20)		(38)		9		(29)
Unrealized (loss) gain from equity method investment, net of income tax expense of $0 for 2023 and $5 for 2022 (a)	13		(1)		12		(9)		15		6
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax benefit of $(1) for 2023 and $(15) for 2022	(195)		(2)		(197)		(194)		(39)		(233)
Reclassification to net income of losses on cash flow hedges, net of income tax expense (benefit) of $18 for 2023 and $4 for 2022 (b)	22		52		74		(32)		11		(21)
Loss (gain) on derivatives qualifying as cash flow hedges	(173)		50		(123)		(226)		(28)		(254)
Accumulated Other Comprehensive Loss	$	(180)	$	49	$	(131)	$	(273)	$	(4)	$	(277)

(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, 2023 and 2022, 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, 2023 and 2022, respectively, consisted of:


	Three Months Ended March 31,
		2023		2022
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID		$	245	$	445
Denominator:
Weighted average number of shares outstanding - basic		386,744,996		386,698,132
Weighted average number of shares outstanding - diluted		387,077,213		387,114,285
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic		$	0.63	$	1.15
Earnings Per Common Share, Diluted		$	0.63	$	1.15

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, 2023, consisted of:


Three Months Ended March 31, 2023	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	2,076	$	390	$	—	$	2,466

Depreciation and amortization	174		105		1		280
Operating income (loss)	277		(10)		(2)		265
Earnings (losses) from equity method investments	4		(2)		—		2
Interest expense, net of capitalization	70		6		19		95
Income tax expense (benefit)	44		(34)		(28)		(18)
Adjusted net income	195		51		1		248
Capital expenditures	609		227		—		836
As of March 31, 2023
Property, plant and equipment	20,291		10,942		16		31,249
Equity method investments	181		259		—		440
Total assets	$	28,591	$	13,164	$	(297)	$	41,458

(a) Includes Corporate and intersegment eliminations.

Segment information for the three months ended March 31, 2022 and as of December 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 (loss)	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 (loss)	254		211		(15)		450
Capital expenditures	355		454		2		811
As of December 31, 2022
Property, plant and equipment	20,027		10,950		17		30,994
Equity method investments	171		266		—		437
Total assets	$	28,069	$	13,553	$	(499)	$	41,123

(a) Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the three months ended March 31, 2023 and 2022, respectively, is as follows:


	Three Months Ended March 31,
		2023		2022
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.		$	248	$	450
Adjustments:
Mark-to-market earnings - Renewables (1)		(4)		(3)

Impact of COVID-19 (2)		—		(2)

Income tax impact of adjustments		1		2
Net Income Attributable to Avangrid, Inc.		$	245	$	445

(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.

Related party transactions for the three months ended March 31, 2023 and 2022, respectively, consisted of:


Three Months Ended March 31,	2023				2022
(Millions)	Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(11)	$	—	$	(12)
Iberdrola Renovables Energía, S.L.	$	—	$	(2)	$	—	$	(2)
Iberdrola Financiación, S.A.	$	—	$	(4)	$	—	$	(3)
Vineyard Wind	$	2	$	—	$	2	$	—

Other	$	—	$	—	$	—	$	(1)

Related party balances as of March 31, 2023 and December 31, 2022, respectively, consisted of:


As of	March 31, 2023				December 31, 2022
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	—	$	(11)	$	1	$	(29)
Iberdrola Financiación, S.A.	$	—	$	(2)	$	—	$	(9)
Vineyard Wind	$	2	$	(8)	$	3	$	(8)
Iberdrola Solutions	$	—	$	(2)	$	—	$	(2)
Other	$	3	$	(3)	$	4	$	(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, 2023 and December 31, 2022.

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, 2023 and December 31, 2022, 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, 2023 and December 31, 2022, there was no outstanding amount under this credit facility.

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

Note 15. Other Financial Statement Items

Accounts receivable and unbilled revenue, net

Accounts receivable and unbilled revenues, net as of March 31, 2023 and December 31, 2022 consisted of:


As of	March 31, 2023		December 31, 2022
(Millions)
Trade receivables and unbilled revenues	$	1,817	$	1,892
Allowance for credit losses	(148)		(155)
Accounts receivable and unbilled revenues, net	$	1,669	$	1,737

The change in the allowance for credit losses for the three months ended March 31, 2023 and 2022 consisted of:


	Three Months Ended March 31,
(Millions)		2023		2022
As of Beginning of Period,		$	155	$	151
Current period provision		17		20
Write-off as uncollectible		(24)		(18)
As of March 31,		$	148	$	153

The Deferred Payment Arrangements (DPA) receivable balance was $102 million at both March 31, 2023 and December 31, 2022. The allowance for credit losses for DPAs at March 31, 2023 and December 31, 2022 was $40 million and $42 million respectively. Furthermore, the change in the allowance for credit losses associated with the DPAs for the three months ended March 31, 2023 and 2022, was $(2) million and $3 million, respectively.

Prepayments and other current assets

Included in prepayments and other current assets are $194 million and $136 million of prepaid other taxes as of March 31, 2023 and December 31, 2022, respectively.

Property, plant and equipment and intangible assets

The accumulated depreciation and amortization as of March 31, 2023 and December 31, 2022, respectively, were as follows:


	March 31,		December 31,
As of	2023		2022
(Millions)
Property, plant and equipment
Accumulated depreciation	$	11,789	$	11,542
Intangible assets
Accumulated amortization	$	335	$	331

As of March 31, 2023 and 2022, accrued liabilities for property, plant and equipment additions were $239 million and $122 million, respectively.

Debt

Commercial Paper

As of March 31, 2023 and December 31, 2022, there was $1,090 million and $397 million of commercial paper outstanding, respectively. As of March 31, 2023 and December 31, 2022, the weighted-average interest rate on commercial paper was 5.33% and 4.66%, respectively.

AVANGRID Credit facility

As of March 31, 2023 and December 31, 2022, there was $200 million and $0 of short-term borrowings outstanding under the AVANGRID credit facility, respectively. As of March 31, 2023 the weighted-average interest rate on short-term borrowings under the AVANGRID credit facility was 6.05%

Supplier Financing Arrangements

We operate a supplier financing arrangement. We arranged for the extension of payment terms with some suppliers (limited to 360 days or less), 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, 2023 and December 31, 2022, the amount of notes payable under supplier financing arrangements was $4 million and $171 million, respectively. As of March 31, 2023 and December 31, 2022, the weighted average interest rate on the balance was 6.12% and 5.48%, respectively.

Other current liabilities

Included in other current liabilities are $268 million and $271 million of advances received as of March 31, 2023 and December 31, 2022, respectively.

Note 16. Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2023, was (9.1)%, 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.

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 was reflected in total in the first quarter as a discrete adjustment.

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 March 2023, a total number of 677,752 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and are payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025.

On April 12, 2023, 487,000 PSUs were granted to certain executives of AVANGRID with achievement measured based on certain performance and market-based metrics for the 2023 to 2025 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2026, 2027 and 2028.

Restricted Stock Units

In March 2021, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in full in one installment in March 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting date. The fair value on the grant date was determined based on a price of $48.83 per share. The RSU grant was settled in March 2023, net of applicable taxes, by issuing 3,642 shares of common stock.

In June 2022, 25,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in two equal installments in 2023 and 2024, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting dates. The fair value on the grant date was determined based on a price of $47.64 per share. The 1st installment of this RSU grant was settled in January 2023, net of applicable taxes, by issuing 8,690 shares of common stock.

Phantom Share Units

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. In February 2023, $0.1 million was paid to settle the second installment under this plan.

In February 2023, 81,000 Phantom Shares were granted to certain AVANGRID executives and employees. These awards vest in three equal installments in 2024 - 2026 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, 2023 and December 31, 2022, the total liability was $1 million and $0, 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, 2023 and 2022, was $4 million and $5 million, respectively.

Note 18. Variable Interest Entities

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

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

On 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. In March 2023 we received additional investment from our investor in the amount of $61 million. Lund Hill is owned by Solis Solar Power I, LLC (Solis I).

The assets and liabilities of the VIEs totaled approximately $2,806 million and $388 million, respectively, at March 31, 2023. As of December 31, 2022, the assets and liabilities of VIEs totaled approximately $2,853 million and $424 million, respectively. At March 31, 2023 and December 31, 2022, 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, 2023, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus Wind Power VII, LLC (Aeolus VII), Aeolus VIII, and Solis I are our consolidated VIEs.

Our El Cabo, Patriot, Aeolus VII, Aeolus VIII, and Solis I 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% indirect ownership interest in Vineyard Wind 1, LLC (Vineyard Wind 1), a joint venture with Copenhagen Infrastructure Partners (CIP). Prior to a restructuring transaction that took place on January 10, 2022 (Restructuring Transaction), Renewables held a 50% ownership interest in Vineyard Wind, LLC (Vineyard Wind) which held rights to two easements from the U.S. Bureau of Ocean Energy Management (BOEM) for the development of offshore wind generation, Lease Area 501 which contained 166,886 acres and Lease Area 522 which contained 132,370 acres, both located southeast of Martha’s Vineyard. Lease Area 501 was subsequently subdivided in 2021, creating Lease Area 534. 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, Vineyard Wind 1. Following the Restructuring Transaction, Vineyard Wind 1 remained a 50-50 joint venture and kept the rights to develop Lease Area 501, and Vineyard Wind was effectively dissolved where Renewables received rights to the Lease Area 534 and CIP received rights to Lease Area 522 as liquidating distributions. In contemplation of the liquidating distributions, Renewables also made an incremental payment of approximately $168 million to CIP. Consequently in 2022, 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 for the three months ended March 31, 2022.

Concurrently with the closing on the construction financing for the Vineyard Wind 1 project, 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 in 2021.

Vineyard Wind 1 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, 2023 and December 31, 2022, the carrying amount of Renewables' investments in Vineyard Wind LLC and Vineyard Wind 1 Pledgor LLC was $7 million and $9 million, respectively.

Note 20. Subsequent Event

On April 12, 2023, 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 3, 2023 to shareholders of record at the close of business on June 1, 2023.

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, 2022 and 2021, and for the three years ended December 31, 2022, included in our Annual Report on Form 10-K for the year ended December 31, 2022, filed with the Securities and Exchange Commission, or the SEC, on February 22, 2023, 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 $41 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 9.2 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 2023 for the fifth consecutive year by the Ethisphere Institute and recognized by Just Capital as one of the 2023 Just 100, an annual ranking of the most just U.S. public companies for the third time. AVANGRID employs approximately 7,600 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 14.7% 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, 2023.

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.

Renewables has a combined wind, solar and thermal installed capacity of 9,226 megawatts, or MW, as of March 31, 2023, including Renewables’ share of joint projects, of which 8,061 MW was installed wind capacity. Renewables targets to contract or hedge above 80% of its capacity under long-term PPAs and hedges to limit market volatility. As of March 31, 2023, approximately 74% of the capacity was contracted with PPAs for an average period of approximately 10 years and an additional 12% 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, 2023, and strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables installed capacity includes 67 wind farms and five 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. 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, a number of plaintiffs have filed multiple cases against generators and natural gas suppliers, including certain Renewables entities in Texas, alleging liability for injuries and damages arising from the event under a variety of legal theories. The plaintiffs have amended many of their petitions within the multidistrict litigation, and more than 100 of the cases now name Renewables entities among the defendants. Four of the consolidated cases have been designated as “bellwether” cases and are proceeding to resolve certain common issues of fact and law. In May 2022, the Renewables entities were part of a broader motion to dismiss by all generators in the bellwether cases in which they were named. These motions were argued on October 11, 2022. On January 27, 2023 the Court issued orders granting in part and denying in part the generators’ motion to dismiss. The Court’s order dismissed plaintiffs’ tortious interference and conspiracy claims, but allowed all other claims to proceed. The generators subsequently filed mandamus petitions with the Texas Courts of Appeal, seeking review of the lower court’s decision on the motions. We cannot predict the outcome of these matters.

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 was 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 set 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 New Mexico Public Regulation Commission, or 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. On June 14, 2022, the NMPRC filed its Answer Brief. On June 13, 2022, New Energy Economy, an intervener in the Merger proceeding, filed its Answer Brief. AVANGRID's Reply Brief was filed on August 5, 2022. On March 8, 2023, AVANGRID, PNM and the NMPRC filed a motion to dismiss the appeal and remand the proceeding back to the NMPRC for further proceedings. The motion states that, once granted, AVANGRID and PNM intend to file a motion for rehearing and/or reconsideration at the NMPRC. One party opposed the motion and certain other parties have sought clarification regarding the process that the NMPRC would implement on remand.

On February 24, 2022, the FCC granted an extension to its approval to transfer operating licenses in connection with the Merger, which was further extended on August 9, 2022 and again on February 16, 2023. On May 20, 2022, the NRC issued an order extending the effectiveness of its approval until May 25, 2023, and again on March 14, 2023 until May 25, 2024. On September 21, 2022, New Energy Economy filed a motion to show cause with the NMPRC alleging that AVANGRID and PNM have engaged in a misleading joint advertising and sponsorship strategy and requesting an investigation. AVANGRID and PNM filed a reply to the motion to show cause on October 11, 2022. On December 14, 2022, the NMPRC issued an order denying the motion.

Business Environment

The COVID-19 pandemic has caused global economic disruption and volatility in financial markets and the United States economy. We continue to experience 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. For example, we recently announced that Commonwealth Wind and Park City Wind would seek to re-negotiate the price of the certain Power Purchase Agreements, or PPAs, to help mitigate the impacts of inflation, increased interest rates and supply chain disruptions on the projects. On October 21, 2022, Commonwealth Wind filed a motion with the DPU seeking a one-month suspension in the DPU’s proceeding to review the power purchase agreements between Commonwealth Wind and the Massachusetts electric distribution companies, or EDCs, in order to provide an opportunity for Commonwealth Wind, the EDCs, state and regulatory officials, and other stakeholders to evaluate the current economic challenges facing Commonwealth Wind and assess measures that would return the project to economic viability including, but not limited to, certain amendments to the Power Purchase Agreements, or PPAs. In Connecticut, discussions remain ongoing with the EDCs, state and regulatory officials, and other stakeholders concerning a possible amendment to the PPAs. While we have not yet experienced a materially adverse impact to our business, results of operations or financial condition, 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. We continue to monitor the broader economic impact of this conflict, which may include further sanctions, supply chain instability, and potential retaliatory action by the Russian government. We are taking steps intended to mitigate the potential risks from this continued conflict, including without limitation, communication with suppliers to ensure that the supply chains are free from sanctioned materials, efforts to diversify sourcing and capacity planning to help avoid supply chain disruptions. 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.

We are also 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. In June 2022, President Biden's Administration announced a 24-month tariff exemption on any potential tariff resulting from the anti-circumvention investigation. 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. Despite the 24-month tariff exemption, there is uncertainty around the final resolution by the DOC and related long-term effects to the solar panel supply chain and we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

In March 2022, the United States House of Representatives passed the Coast Guard Authorization Act of 2022 and the National Defense Authorization Act that was passed by the United States House of Representatives in mid-July. If enacted, the bills may only allow foreign vessels to operate on the Outer Continental Shelf if they have a U.S. crew or the crew of the nation of which the vessel is from. If passed, the legislation could affect expected timelines and returns on approved projects. To date, there has been no material impact on Renewables' operations or financial performance as a result of these bills; however, given the uncertainty of resolution of the final legislation and the related effects to our offshore projects, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

There are a limited number of turbine suppliers in the market. Renewables’ largest turbine suppliers, Siemens-Gamesa and GE Wind, are engaged in an intellectual property dispute with respect to certain offshore wind turbines including the wind turbines to be used in the Vineyard Wind 1 project. In July 2022, the federal district court granted Siemens-Gamesa’s request for a permanent injunction barring GE Wind from importing and selling the infringing wind turbines, which carved out the wind turbines for the Vineyard Wind 1 project from such injunction. To date, there has been no material impact on Renewables' operations or turbine procurement; however, we are monitoring this dispute and we cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.

For more information, see the risk factor under the heading “The outbreak of COVID-19 and its impact on business and economic conditions could negatively affect our business, results of operations or financial condition.” in Item 1A. Risk Factors in our Form 10-K for the year ended December 31, 2022.

Summary of Results of Operations

Our operating revenues increased by by $333 million from $2,133 million for the three months ended March 31, 2022 to $2,466 million for the three months ended March 31, 2023.

Networks business revenues increased mainly due to rate increases in New York effective December 1, 2020. Renewables revenues increased mainly due to higher wind and solar generation output and favorable thermal and power trading driven by higher average prices in the period primarily due to cold weather.

Net income attributable to AVANGRID decreased by $200 million from $445 million for the three months ended March 31, 2022 to $245 million for the three months ended March 31, 2023, primarily driven by a $246 million gain recognized in the same period of 2022 from the offshore joint venture restructuring transaction in Renewables.

Adjusted net income (a non-GAAP financial measure) decreased by $201 million from $450 million for the three months ended March 31, 2022 to $248 million for the three months ended March 31, 2023. The decrease is primarily due to a $160 million decrease in Renewables driven by a gain recognized in the same period of 2022 from the offshore joint venture restructuring transaction, a $58 million decrease in Networks driven primarily by higher business costs and uncollectible expenses in the period, offset by $16 million increase in Corporate mainly driven by favorable taxes from applying the annual consolidated estimated tax rate.

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, 2022.

New England Clean Energy Connect

In 2018, the New England Clean Energy Connect, or NECEC, transmission project, proposed in a joint bid by CMP and Hydro-Québec, was selected by the Massachusetts electric distribution utilities (EDCs) and the DOER in the Commonwealth of Massachusetts’s 83D clean energy Request for Proposal. The NECEC transmission project includes a 145-mile transmission line linking the electrical grids in Québec, Canada and New England. The project, which has an estimated cost of approximately $1.4 billion in total, would add 1,200 MW of transmission capacity to supply Maine and the rest of New England with power from reliable hydroelectric generation.

On June 13, 2018, CMP entered into transmission service agreements, or TSAs, with the Massachusetts EDCs, and H.Q. Energy Services (U.S.) Inc., or HQUS, an affiliate of Hydro-Québec, which govern the terms of service and revenue recovery for the NECEC transmission project. Simultaneous with the execution of the TSAs with CMP, the EDCs executed certain PPAs with HQUS for sales of electricity and environmental attributes to the EDCs. On October 19, 2018, FERC issued an order accepting the TSAs for filing as CMP rate schedules effective as of October 20, 2018. On June 25, 2019, the Massachusetts DPU issued an Order approving the NECEC project long term PPAs and the cost recovery by the EDCs of the TSA charges. This Order was subsequently appealed by NextEra Energy Resources. On September 3, 2020, the Massachusetts Supreme Judicial Court denied NextEra Energy Resources’ appeal of the DPU Order.

The NECEC project requires a Certificate of Public Convenience and Necessity, or CPCN, from the MPUC. On May 3, 2019, the MPUC issued an Order granting the CPCN for the NECEC project. This Order was subsequently appealed by NextEra Energy Resources. On March 17, 2020, the Maine Law Court denied NextEra Energy Resources’ appeal of the CPCN.

On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks, pursuant to the terms of a transfer agreement dated November 3, 2020.

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

was appealed by certain intervenors. Through an Order dated July 21, 2022, the Maine Board of Environmental Protection, or MBEP, denied the appeals of the MDEP Order, as well as the appeal of MDEP’s December 4, 2020 Order approving the partial transfer of the permits for the project to NECEC Transmission LLC. In August 2022, the intervenors that had appealed the MDEP Order appealed the MBEP Order. Their appeals are pending before the Maine Superior Court. In addition, certain intervenors appealed MDEP's May 7, 2021 Order approving certain minor revisions. On February 16, 2023 the MBEP denied the appeal and affirmed the referred MDEP Order. In March 2023, the intervenors appealed the MBEP order to the Maine Superior Court, where it remains pending.

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, among other things, 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 Nuclear Generation Station, or Seabrook Station, on February 1, 2023, FERC issued an order granting in part AVANGRID and NECEC Transmission LLC’s complaint against NextEra Energy Resources, LLC and NextEra Energy Seabrook, LLC, or Seabrook, denying in part AVANGRID and NECEC Transmission LLC’s complaint, and dismissing Seabrook’s petition for declaratory order. Among other things, FERC directs Seabrook to replace the breaker at Seabrook Station pursuant to its obligations under Seabrook Station’s large generator interconnection agreement and good utility practice. Furthermore, FERC has determined that Seabrook should not recover opportunity or legal costs in connection with the breaker replacement. In the event that there are additional disputes between the parties in connection with the agreement for implementation of the breaker replacement, FERC notes that the parties may file an unexecuted agreement. NextEra sought reconsideration of FERC’s decision, which was denied in April 2023.

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 challenge to the Presidential Permit is currently pending before the District Court in Maine. 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”), which per its terms would retroactively apply to the NECEC project. In particular, 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 the Bureau of Parks and Lands (“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, which was ultimately denied. 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. The Business & Consumer Court granted this motion, thereby sending its decision to the Law Court for review. On August 30, 2022, the Law Court ruled that certain Initiative provisions would infringe on NECEC’s constitutionally protected vested rights if NECEC Transmission LLC can demonstrate that it engaged in substantial construction of the NECEC project in good-faith reliance of the authority under the CPCN granted by the MPUC before Maine voters approved the Initiative. The Maine Law Court remanded the matter to the Business & Consumer Court for a trial to determine that question. The trial began on April 10, 2023 and concluded on April 20, 2023, when the jury reached a unanimous decision finding that NECEC had constructed substantial construction in good faith. The Court subsequently entered an Order that NECEC had obtained vested rights to continue work on the project, and that retroactively applying the Initiative to the NECEC project would violate the Maine Constitution.

Following this decision, the company is evaluating the construction schedule for the NECEC project and related commercial operation date, including potential impacts from increased project construction costs, disputes with third party vendors regarding contracts and certain change orders, and a decrease in expected returns. As of March 31, 2023, we have capitalized approximately $612 million for the NECEC project.

On November 23, 2021, the MDEP issued an Order finding that the Initiative constituted a changed circumstance justifying the suspension of the MDEP permits for the NECEC project. 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 order provides that construction can resume if the court issued a preliminary injunction or a final decision on the matter by providing a prior notice of five days to the MDEP.

In connection with the lease granted by BPL over a small area of Maine public lands to house a 0.9-mile section of the NECEC, on November 29, 2022, the Law Court vacated the trial court’s prior decision to reverse BPL’s decision to grant the lease. The Law Court confirmed that BPL acted within its constitutional and statutory authority when granting the lease. Furthermore, the Law Court held that the section of the Initiative that requires 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, as retroactively applied to the lease for the NECEC, violates the Contracts Clauses of the U.S. and Maine Constitutions and, accordingly, that the lease was not voided by the Initiative.

At the municipal level, the project has obtained multiple municipal approvals and will pursue any remaining municipal approvals in accordance with the project schedule.

Maine Government-Run Power Referendum

On September 18, 2020, a request was submitted to the Maine Secretary of State to initiate the process of placing a government-run power referendum on the 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. On October 31, 2022, proponents of government-run power submitted signatures for a Citizen’s Initiative to the Maine Secretary of State. The Secretary of State certified that the proponents submitted more than the required signatures to place the referendum on the ballot in November 2023. Subsequently, the Secretary of State released final ballot language for the November 2023 election. In addition, proponents of the “No Blank Checks” Citizen’s Initiative submitted signatures to the Maine Secretary of State. This referendum would require citizens to approve the debt issued by the State of Maine greater than $1 billion, including debt necessary for a government-controlled entity to seize the assets of an investor-owned utility. A Petition for Review of Final Agency action was filed in Maine Superior Court challenging the Secretary’s signature determination relative to the “No Blank Checks” Citizen’s Initiative and the Maine Superior Court upheld the Secretary’s determination. We cannot predict the outcome of the Citizen’s Initiative.

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 $135 million and $137 million, respectively, for this item at March 31, 2023 and December 31, 2022.

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 of NYSEG and RG&E and certain other New York utilities regarding tax accounting. The NYPSC audit report is expected to be completed during 2023.

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

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 approximately $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 were consolidated. On October 17, 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI filed an appeal to the Connecticut Appellate Court on November 14, 2022. We cannot predict the outcome of this proceeding.

Connecticut Energy Legislation

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.

Proposed Connecticut Performance-Based Regulation

On March 17, 2023, PURA issued a draft decision proposing a regulatory framework for Performance-Based Regulation, or PBR, for electric distribution companies. The Draft Decision establishes the regulatory goals, foundational considerations, and priority outcomes to guide PBR development among other things. The intent of the PBR framework is to drive improvement in utility performance to better serve the public interest. Additional areas of focus include establishing an equitable modern grid framework, and providing a toolkit for regulatory reform. We cannot predict the outcome of this proposed regulation.

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.

New York Climate Leadership and Community Protection Act

In June 2019, the New York State legislature passed a new law titled the Climate Leadership and Community Protection Act, or CLCPA, which could have significant impacts on the operations of electric and gas utilities in New York. A Climate Action Council has been formed consistent with the CLCPA, and that Council will be providing guidance to New York State in reaching aggressive renewable and emission reduction goals delineated in the CLCPA. On December 30, 2021, the Climate Action Council issued a Draft Scoping Plan, which includes numerous draft recommendations designed to ensure a fair transition to achieving New York’s greenhouse gas emission reduction goals and renewable energy goals. The Draft Scoping

Plan is subject to a 120-day public comment period, and the Climate Action Council published the final Scoping Plan on December 16, 2022, which was approved by the Climate Action Council on December 19, 2022.

On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources (Phase 2) pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act. The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.25 billion, including participation with other upstate utilities on certain projects.

Customer Arrearages Reduction Order

On June 16, 2022, the NYPSC issued an order authorizing an arrears reduction program targeting low-income customers to provide COVID-19-related relief through a one-time bill credit to eliminate accrued arrears through May 1, 2022. A portion of the targeted arrearages will be funded via direct contributions from the State of New York, and the remainder to be received via a surcharge to all customers. The surcharge recovery is over five years for RG&E and three years for NYSEG beginning on August 1, 2022.

On January 19, 2023, the NYPSC issued a subsequent order providing bill relief for customers who did not receive a credit as part of the Phase 1 Program approved in 2022 (Low Income Program participants). Qualifying residential and small business customers are eligible to have any past-due balance from bills for service through May 1, 2022, reduced through a one-time bill credit, up to a maximum credit below:

Residential

Total Forecast Residential Credits

Small Business

Total Forecast Small Business Credits

Company

(Millions)

NYSEG

Up to $1,000

16.9

Up to $1,250

1.4

RG&E

Up to $1,500

15.2

Up to $1,500

0.6

Inflation Reduction Act

In August 2022, the Inflation Reduction Act of 2022, or IRA, was signed into law in the United States. The IRA created a new corporate alternative minimum tax, or CAMT, of 15% on adjusted financial statement income and an excise tax of 1% on the value of certain stock repurchases. The IRA also contains a number of additional provisions related to tax incentives for investments in renewable energy production, carbon capture, and other climate actions. The CAMT and other various applicable provisions of the IRA are effective for Avangrid for periods beginning after December 31, 2022.

The Company is expected to be subject to the CAMT starting in the first quarter of 2023 but does not expect it to have a material impact on our earnings, financial condition, or cash flow as the Company can utilize tax attributes to reduce the overall cash tax impact. While the Department of Treasury has issued some guidance, as recently as the first quarter of 2023, additional guidance is expected. We have taken into consideration all available guidance issued to date, which has been factored into our current year tax estimates. Given the comprehensiveness and depth of the legislation and pending guidance, we continue to monitor and evaluate the IRA’s impacts on our business and financial statements.

Partnership with Navajo Tribal Utility Authority

In March 2023, Renewables and Navajo Tribal Utility Authority Generation, Inc., or NTUAG, a wholly-owned subsidiary of Navajo Tribal Utility Authority, or NTUA, signed a Memorandum of Understanding, or MoU, to jointly explore opportunities for developing up to a 1 GW of renewable energy generation, including solar, wind, hydrogen and back-up battery storage, on the reservation of Navajo Nation. Once built, that would constitute enough generation to supply clean energy to hundreds of thousands of homes and businesses, both on the reservation, and in regional markets through export to surrounding states. All projects built through the partnership would be joint ventures, with NTUA maintaining at least 51% majority ownership to retain tribal sovereignty and control.

Connecticut Petition for General Rate Hearing

On April 24, 2023, the Connecticut Attorney General, the Office of Consumer Counsel, the Connecticut Public Utilities Regulatory Authority Office of Education, Outreach, and Enforcement, and the Connecticut Industrial Energy Consumers collectively filed a petition with PURA to conduct a general rate hearing for CNG. In 2018, PURA approved tariffs for CNG effective January 1, 2019 for a three-year rate plan. We cannot predict the outcome of this petition.

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, 2023								March 31, 2022
	Total		Networks		Renewables		Other(1)		Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	2,466	$	2,076	$	390	$	—	$	2,133	$	1,935	$	198	$	—
Operating Expenses
Purchased power, natural gas and fuel used	977		833		144		—		741		756		(15)		—
Operations and maintenance	761		631		130		—		651		539		113		(1)
Depreciation and amortization	280		174		105		1		261		161		100		—
Taxes other than income taxes	183		161		21		1		178		160		18		—
Total Operating Expenses	2,201		1,799		400		2		1,831		1,616		216		(1)
Operating Income	265		277		(10)		(2)		302		319		(18)		1
Other Income (Expense)
Other income (expense)	25		29		2		(6)		11		12		1		(2)
Earnings (losses) from equity method investments	2		4		(2)		—		253		3		250		—
Interest expense, net of capitalization	(95)		(70)		(6)		(19)		(71)		(50)		(3)		(18)
Income (Loss) Before Income Tax	197		240		(16)		(27)		495		284		230		(19)
Income tax expense (benefit)	(18)		44		(34)		(28)		68		31		41		(4)
Net Income (Loss)	215		196		18		1		427		253		189		(15)
Net loss (income) attributable to noncontrolling interests	30		(1)		31		—		18		(1)		19		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	245	$	195	$	49	$	1	$	445	$	252	$	208	$	(15)

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

Comparison of Period to Period Results of Operations

Three Months Ended March 31, 2023 Compared to Three Months Ended March 31, 2022

Operating Revenues

Our operating revenues increased by $333 million from $2,133 million for the three months ended March 31, 2022 to $2,466 million for the three months ended March 31, 2023, as detailed by segment below:

Networks

Operating revenues increased by $141 million from $1,935 million for the three months ended March 31, 2022 to $2,076 million for the three months ended March 31, 2023. Electricity and gas revenues increased by $33 million, primarily due to rate increases in New York effective December 1, 2020 and $14 million favorable impact from transmission in the current period. Electricity and gas revenues changed due to the following items that have offsets within the income statement: an increase of $77 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 $17 million in flow through amortizations (offset in operating expenses).

Renewables

Operating revenues increased by $192 million from $198 million for the three months ended March 31, 2022, to $390 million for the three months ended March 31, 2023. The increase in operating revenues was primarily due to an increase of $11 million driven by 395 GWh higher wind and solar generation output, $77 million in favorable thermal and power trading driven by higher average prices in the period primarily due to cold weather, favorable MtM changes of $131 million on energy derivative transactions entered for economic hedging purposes, offset by a $27 million decrease in merchant prices driven by lower average prices in the current period.

Purchased Power, Natural Gas and Fuel Used

Purchased power, natural gas and fuel used increased by $236 million from $741 million for the three months ended March 31, 2022 to $977 million for the three months ended March 31, 2023, as detailed by segment below:

Networks

Purchased power, natural gas and fuel used increased by $77 million from $756 million for the three months ended March 31, 2022 to $833 million for the three months ended March 31, 2023. The increase is primarily driven by a $77 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 increased by $159 million from $(15) million for the three months ended March 31, 2022 to $144 million for the three months ended March 31, 2023. The increase is primarily due to unfavorable MtM changes on derivatives of $132 million driven by market price changes in the period and an increase of $27 million in power and gas purchases due to higher average prices in the current period driven by colder weather.

Operations and Maintenance

Operations and maintenance expenses increased by $110 million from $651 million for the three months ended March 31, 2022 to $761 million for the three months ended March 31, 2023, as detailed by segment below:

Networks

Operations and maintenance expenses increased by $92 million from $539 million for the three months ended March 31, 2022 to $631 million for the three months ended March 31, 2023. The increase is driven by increased business costs of $15 million, $22 million increase in personnel expenses primarily driven by higher headcount and $38 million increase in uncollectible expenses due to higher bad debt provision in the current period. In addition, there were increases of $17 million in flow-through amortizations (which is offset in revenue).

Renewables

Operations and maintenance expenses increased by $17 million from $113 million for the three months ended March 31, 2022 to $130 million for the three months ended March 31, 2023. The increase is primarily due to a $12 million increase in personnel costs driven primarily by increase in headcount in the period and $5 million increase in other operating costs primarily driven by increase in maintenance services in the current period.

Depreciation and Amortization

Depreciation and amortization for the three months ended March 31, 2023 was $280 million compared to $261 million for the three months ended March 31, 2022, an increase of $19 million. The increase is primarily driven by $18 million from plant additions in Networks and Renewables in the current period.

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

Other income (expense) and equity earnings (losses) decreased by $237 million from $264 million for the three months ended March 31, 2022 to $27 million for the three months ended March 31, 2023. The decrease is primarily due to $251 million of unfavorable equity earnings, driven by a $246 million gain recognized in the same period of 2022 from the offshore joint venture restructuring transaction in Renewables, offset by a $14 million favorable change in the non-service component of pension expense driven by revised actuarial studies in Networks in the period (which is partially offset within revenue).

Interest Expense, Net of Capitalization

Interest expense for the three months ended March 31, 2023 and 2022 was $95 million and $71 million, respectively. The change is primarily due to an increase of $5 million of interest expense at Networks from increased debt and $19 million increase in Other mainly driven by increased outstanding balances on commercial papers and unfavorable changes in fair value hedge in the current period.

Income Tax

The effective tax rate, inclusive of federal and state income tax, for the three months ended March 31, 2023 was (9.1)%, 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. 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 was reflected in total in the first quarter as a discrete adjustment.

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.

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, 2023 and 2022, respectively:


	Three Months Ended March 31, 2023
		Total		Networks		Renewables		Corporate*
	(in millions)
Net Income Attributable to Avangrid, Inc.		$	245	$	195	$	49	$	1
Adjustments:
Mark-to-market earnings – Renewables		4		—		4		—

Income tax impact of adjustments (1)		(1)		—		(1)		—
Adjusted Net Income (2)		$	248	$	195	$	51	$	1

Net (loss) income attributable to noncontrolling interests		(30)		1		(31)		—
Income tax expense (benefit)		(17)		44		(33)		(28)
Depreciation and amortization		280		174		105		1
Interest expense, net of capitalization		95		70		6		19
Other (income) expense		(25)		(29)		(2)		6
(Earnings) losses from equity method investments		(2)		(4)		2		—
Adjusted EBITDA (3)		$	549	$	451	$	98	$	—

Retained PTCs and ITCs		45		—		45		—
PTCs allocated to tax equity investors		39		—		39		—
Adjusted EBITDA with Tax Credits (3)		$	633	$	451	$	182	$	—


	Three Months Ended March 31, 2022
		Total		Networks		Renewables		Corporate*
	(in millions)
Net Income (Loss) 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

(1)Income tax impact of adjustments: 2023 - $(1) million from MtM earnings for the three months ended March 31, 2023; 2022 - $(1) million from MtM earnings and $(1) million from impact of COVID-19 for the three months ended March 31, 2022.

(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.

(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, 2023 Compared to Three Months Ended March 31, 2022

Adjusted net income

Our adjusted net income decreased by $201 million from $450 million for the three months ended March 31, 2022 to $248 million for the three months ended March 31, 2023. The decrease is primarily due to a $160 million decrease in Renewables driven by a gain recognized in the same period of 2022 from the offshore joint venture restructuring transaction, a $58 million decrease in Networks driven primarily by higher business costs and uncollectible expenses in the period, offset by $16 million increase in Corporate mainly driven by favorable taxes from applying the annual consolidated estimated tax rate.

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, 2023 and 2022, respectively:


	Three Months Ended
	March 31,
(Millions)		2023		2022
Networks		$	195	$	252
Renewables		49		208
Corporate (1)		1		(15)
Net Income		$	245	$	445
Adjustments:
Mark-to-market earnings - Renewables (2)		4		3

Impact of COVID-19 (3)		—		2
Income tax impact of adjustments		(1)		(2)
Adjusted Net Income (4)		$	248	$	450


	Three Months Ended
	March 31,
		2023		2022
Networks		$	0.51	$	0.65
Renewables		0.13		0.54
Corporate (1)		—		(0.04)
Net Income		$	0.63	$	1.15
Adjustments:
Mark-to-market earnings - Renewables (2)		0.01		0.01

Impact of COVID-19 (3)		—		0.01
Income tax impact of adjustments		—		—
Adjusted Earnings Per Share (4)		$	0.64	$	1.16

(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 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, 2023.

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, 2023 and December 31, 2022, respectively:


	As of March 31,		As of December 31,
	2023		2022
	(in millions)
Cash and cash equivalents	$	72	$	69
AVANGRID Credit Facility	3,575		3,575
Iberdrola Group Credit Facility	500		500
Less: borrowings	(1,290)		(397)
Total	$	2,857	$	3,747

AVANGRID Commercial Paper Program

AVANGRID has a commercial paper program with a limit of $2 billion that is backstopped by the AVANGRID Credit Facility (described below). As of March 31, 2023 and April 25, 2023, there was $1,090 million and $1,447 million, respectively, 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, 2023 and April 25, 2023, we had $200 million and $0, respectively, of 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, 2023 and April 25, 2023 was $2,285 million and $2,121 million, respectively.

Iberdrola Group Credit Facility

AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually. As of both March 31, 2023 and April 25, 2023, we had no borrowings outstanding under this credit facility.

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 $2.2 billion in capital expenditures through the remainder of 2023. 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 2023. 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, 2023 and 2022, respectively:


	Three Months Ended
	March 31,
	2023		2022
	(in millions)
Net cash provided by operating activities	$	204	$	388
Net cash used in investing activities	(819)		(948)
Net cash provided by (used in) financing activities	618		(266)
Net increase (decrease) in cash, cash equivalents and restricted cash	$	3	$	(826)

Operating Activities

The cash from operating activities for the three months ended March 31, 2023 compared to the three months ended March 31, 2022 decreased by $184 million, primarily attributable to a net decrease in 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, 2023, net cash used in investing activities was $819 million, which was comprised of $836 million of capital expenditures, partially offset by $19 million of contributions in aid of construction.

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.

Financing Activities

For the three months ended March 31, 2023, financing activities provided $618 million in cash reflecting primarily a net increase in non-current debt and current notes payable of $718 million, contribution from non-controlling interests of $74 million, offset by distributions to non-controlling interests of $3 million and dividends of $170 million in the period.

For the three months ended March 31, 2022, financing activities used $266 million in cash r 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.

Off-Balance Sheet Arrangements

There have been no material changes in our off-balance sheet arrangements during the three months ended March 31, 2023 as compared to those reported for the fiscal year ended December 31, 2022 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, 2023 as compared to those reported for the fiscal year ended December 31, 2022 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, 2023, the only notable changes to the significant accounting policies described in our Form 10-K for the fiscal year ended December 31, 2022, 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, 2023.

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, 2023, 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, 2023.

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;

•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, 2023, as compared to those reported for the fiscal year ended December 31, 2022 in our Form 10-K.

Item 4. Controls and Procedures

Evaluation of Disclosure Controls and Procedures

Our management, with the participation of our Chief Executive Officer, or CEO, and our Chief Financial Officer, or CFO, has evaluated the effectiveness of our disclosure controls and procedures (as defined in Rules 13a- 15(e) and 15d- 15(e) under the Securities Exchange Act of 1934, as amended (Exchange Act)), as of the end of the period covered by this Quarterly

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

Changes in Internal Control

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

Limitations on Effectiveness of Controls and Procedures

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

PART II. OTHER INFORMATION

Item 1. Legal Proceedings

Please read “Note 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, 2022.

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

None.

Item 3. Defaults Upon Senior Securities

None.

Item 4. Mine Safety Disclosures

Not applicable.

Item 5. Other Information

None.

Item 6. Exhibits

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


Exhibit Number						Description

10.1						Employment Agreement, dated October 1 2 , 2021, between Avangrid Renewables, LL C and Jose Antonio Miranda Soto.†*

10.2						Amended and Restated Executive Variable Pay Plan.†*

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.

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 26, 2023	By:	/s/ Pedro Azagra Blázquez
		Pedro Azagra Blázquez
		Director and Chief Executive Officer


Date: April 26, 2023	By:	/s/ Patricia C. Cosgel
		Patricia C. Cosgel
		Senior Vice President - Chief Financial Officer