10-K

UNITED STATES

SECURITIES AND EXCHANGE COMMISSION

Washington, D.C. 20549

Form 10-K

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

For the fiscal year ended December 31, 2021

Or

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

For the transition period from           to           

Commission File No. 001-37660

Avangrid, Inc.

(Exact name of registrant as specified in its charter)

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

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(s)	Name of exchange on which registered
Common Stock, par value $0.01 per share	AGR	New York Stock Exchange

Securities registered pursuant to Section 12(g) of the Act: None

Indicate by check mark if the registrant is a well-known seasoned issuer, as defined in Rule 405 of the Securities Act.     Yes  ☒    No  ☐ 

Indicate by check mark if the registrant is not required to file reports pursuant to Section 13 or 15(d) of the Act.     Yes  ☐    No  ☒

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

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

Indicate by check mark whether the registrant is a large accelerated filer, an accelerated filer, a non-accelerated filer, a smaller reporting company, or 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 has filed a report on and attestation to its management’s assessment of the effectiveness of its internal control over financial reporting under Section 404(b) of the Sarbanes-Oxley Act (15 U.S.C. 7262(b)) by the registered public accounting firm that prepared or issued its audit report.  ☒

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

The aggregate market value of the Avangrid, Inc.’s voting stock held by non-affiliates, computed by reference to the price at which the common equity was last sold as of the last business day of Avangrid, Inc.’s most recently completed second fiscal quarter (June 30, 2021) was $3,684 million based on a closing sales price of $51.43 per share.

Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 386,577,494 shares of common stock, par value $0.01, were outstanding as of February 22, 2022.

DOCUMENTS INCORPORATED BY REFERENCE

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved.

Designated portions of the Proxy Statement relating to the 2022 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.

TABLE OF CONTENTS

GLOSSARY OF TERMS AND ABBREVIATIONS	1
CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS	5
PART I	6
Item 1. Business	6
Item 1A. Risk Factors	24
Item 1B. Unresolved Staff Comments.	38
Item 2. Properties.	38
Item 3. Legal Proceedings.	39
Item 4. Mine Safety Disclosures.	39
Information About our Executive Officers	39
PART II	42
Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.	42
Item 6. Reserved	43
Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations	43
Item 7A. Quantitative and Qualitative Disclosures About Market Risk	78
Item 8. Financial Statements and Supplementary Data	81
Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.	170
Item 9A. Controls and Procedures.	171
Item 9B. Other information.	171
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections	171
PART III	172
Item 10. Directors, Executive Officers and Corporate Governance.	172
Item 11. Executive Compensation.	172
Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.	172
Item 13. Certain Relationships and Related Transactions, and Director Independence.	172
Item 14. Principal Accountant Fees and Services.	172
Part IV	173
Item 15. Exhibits and Financial Statement Schedules.	173
Item 16. Form 10-K Summary	179
SIGNATURES	180

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GLOSSARY OF TERMS AND ABBREVIATIONS

Unless the context indicates otherwise, references in this Annual Report on Form 10-K to “AVANGRID,” the “Company,” “we,” “our,” and “us” refer to Avangrid, Inc. and its consolidated subsidiaries.

2016 Joint Proposal	Joint proposal of NYSEG and RG&E and certain other signatory parties approved by the NYPSC on June 15, 2016, for a three-year rate plan for electric and gas service commencing May 1, 2016.
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.
AMI	Automated Metering Infrastructure
AOCI	Accumulated other comprehensive income
ARHI	Avangrid Renewables Holdings, Inc.
ARP	Alternative Revenue Programs
ASC	Accounting Standards Codification
Asnat	Asnat Realty, LLC
Army Corps	U.S. Army Corps of Engineers
ARO	Asset retirement obligation
AVANGRID	Avangrid, Inc.
Bcf	One billion cubic feet
BGC	The Berkshire Gas Company
BGEPA	Bald and Golden Eagle Protection Act
BLM	U.S. Bureau of Land Management
BOEM	U.S. Bureau of Ocean Energy Management
CfDs	Contracts for Differences
CFTC	Commodity Futures Trading Commission
CFIUS	Committee on Foreign Investment in the United States
CL&P	The Connecticut Light and Power Company
CLCPA	Climate Leadership and Community Protection Act
CMP	Central Maine Power Company
CNG	Connecticut Natural Gas Corporation
CPCN	Certificate of Public Convenience and Necessity
CSC	Connecticut Siting Council
DCF	Discounted cash flow
DEEP	Connecticut Department of Energy and Environmental Protection
DE&I	Diversity, Equity and Inclusion
DIMP	Distribution Integrity Management Program
DER	Distributed energy resources
Dodd-Frank Act	Dodd-Frank Wall Street Reform and Consumer Protection Act
DOE	Department of Energy
DOER	Massachusetts Department of Energy Resources
DOJ	Department of Justice
DPA	Deferred Payment Arrangements
DPU	Massachusetts Department of Public Utilities
DSIP	Distributed System Implementation Plan
DTh	Dekatherm
EAM	Earnings adjustment mechanism
EDC	Massachusetts electric distribution companies
English Station	Former generation site on the Mill River in New Haven, Connecticut
EPA	Environmental Protection Agency

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EPAct 2005	Energy Policy Act of 2005
ERCOT	Electric Reliability Council of Texas
ESA	Endangered Species Act
ESC	Energy Smart Community
ESM	Earnings sharing mechanism
Evergreen Power	Evergreen Power, LLC
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.
FPA	Federal Power Act
Gas	Enstor Gas, LLC
GE	General Electric
GenConn	GenConn Energy LLC
GenConn Devon	GenConn’s peaking generating plant in Devon, Connecticut
GenConn Middletown	GenConn’s peaking generating plant in Middletown, Connecticut
HLBV	Hypothetical Liquidation at Book Value
HQUS	H.Q. Energy Services (U.S) Inc.
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
IRS	Internal Revenue Service
ISO	Independent system operator
ISO-NE	ISO New England, Inc.
ITC	Investment Tax Credit
Klamath Plant	The Klamath gas-fired cogeneration facility located in the city of Klamath, Oregon
kV	Kilovolts
kWh	Kilowatt-hour
LDC	Local distribution company
LIBOR	London Interbank Offer Rate
LNG	Liquefied natural gas
LUPC	Maine Land Use Planning Commission
MBTA	Migratory Bird Treaty Act
MDEP	Maine Department of Environmental Protection
MEPCO	Maine Electric Power Corporation
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.
MGP	Manufactured gas plants
MHI	Mitsubishi Heavy Industries
MISO	Midcontinent Independent System Operator
MNG	Maine Natural Gas Corporation
MPRP	Maine Power Reliability Program

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MPUC	Maine Public Utility Commission
MtM	Mark-to-market
MW	Megawatts
MWh	Megawatt-hours
NAV	Net asset value
NECEC	New England Clean Energy Connect
NEPA	National Environmental Policy Act
NERC	North American Electric Reliability Corporation
NETOs	New England Transmission Owners
Networks	Avangrid Networks, Inc.
New York TransCo	New York TransCo, LLC.
NGA	Natural Gas Act of 1938
NMPRC	New Mexico Public Regulation Commission
NOL	Net operating loss
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
NYISO	New York Independent System Operator, Inc.
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
OATT	Open Access Transmission Tariff
OCI	Other comprehensive income
OSHA	Occupational Safety and Health Act, as amended
PA	Connecticut Public Act
PCB	Polychlorinated Biphenyls
PJM	PJM Interconnection, L.L.C.
PNMR	PNM Resources, Inc.
PPA	Power purchase agreement
PTC	Production tax credit
PUCT	Public Utility Commission of Texas
PUHCA 2005	Public Utility Holding Company Act of 2005
PURA	Connecticut Public Utilities Regulatory Authority
RAM	Rate Adjustment Mechanism
RCRA	Resource Conservation and Recovery Act
RDM	Revenue decoupling mechanism
REC	Renewable Energy Certificate
Renewables	Avangrid Renewables, LLC
REV	Reforming the Energy Vision
RFP	Request for Proposals
RG&E	Rochester Gas and Electric Corporation
ROE	Return on equity
ROU	Right-of-use
RPS	Renewable Portfolio Standards
RTO	Regional transmission organization
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

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SOX	Sarbanes-Oxley Act
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
TSA	Transmission Service Agreement
UI	The United Illuminating Company
UIL	UIL Holdings Corporation
U.S. GAAP	Generally accepted accounting principles for financial reporting in the United States.
VaR	Value-at-risk
VIEs	Variable interest entities
VW	Vineyard Wind LLC and its subsidiaries
WECC	Western Electricity Coordinating Council

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CAUTIONARY STATEMENT REGARDING FORWARD-LOOKING STATEMENTS

This Annual Report on Form 10-K 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 including regulatory approvals 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 that could cause actual results to differ materially from those indicated by such 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;

•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;

•the impact of any change to applicable laws and regulations, including those subject to referendums 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 below), the anticipated timing and terms of the proposed Merger, our ability to realize the anticipated benefits of the proposed Merger and our ability to manage the risks of the proposed Merger;

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

•the implementation of changes in accounting standards;

•adverse publicity or other reputational harm; and

•other presently unknown unforeseen factors.

Additional risks and uncertainties are set forth under Part I, Item 1A, “Risk Factors” in this Annual Report on Form 10-K. 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 Securities and Exchange Commission, or SEC, and we encourage you to consult such disclosures.

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PART I

Item 1. Business

Overview

AVANGRID aspires to be the leading sustainable energy company in the United States. A commitment to sustainability is firmly entrenched in the values and principles that guide AVANGRID, with environmental, social, governance and financial sustainability key priorities driving our business strategy.

AVANGRID has approximately $40 billion in assets and operations in 24 states concentrated in our two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving approximately 3.3 million customers in New York and New England. Avangrid Renewables owns and operates 8.8 gigawatts of electricity capacity, primarily through wind and solar power, with a presence in 22 states across the United States. AVANGRID supports the achievement of the Sustainable Development Goals approved by the member states of the United Nations, was named among the World’s Most Ethical companies in 2022 for the fourth consecutive year by the Ethisphere Institute and is listed by Forbes and JUST Capital as one of the 2021 JUST 100, an annual ranking of the most just U.S. public companies. AVANGRID employs approximately 7,300 people. Iberdrola S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.6% of the outstanding shares of AVANGRID common stock. 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. The following chart depicts our current organizational structure.

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 December 31, 2021. The interstate transmission and wholesale sale of electricity by these regulated utilities is regulated by the Federal Energy Regulatory Commission, or FERC, under the Federal Power Act, or FPA, including with respect to transmission rates. Further, Networks’ electric and gas distribution utilities in New York, Maine, Connecticut and Massachusetts are subject to regulation by the New York State Public Service Commission, or NYPSC; the Maine Public Utilities Commission, or MPUC; the Connecticut Public Utilities Regulatory Authority, or PURA; and the Massachusetts Department of Public Utilities, or DPU, respectively. Networks strives to be a leader in safety, reliability and quality of service to its utility customers.

Through Renewables, we have a combined wind, solar and thermal installed capacity of 8,813 megawatts, or MW, as of December 31, 2021, including Renewables’ share of joint projects, of which 7,945 MW was installed wind capacity. Renewables targets to contract or hedge 85% to 95% of its capacity under long-term power purchase agreements, or PPAs, and hedges to limit market volatility. As of December 31, 2021, approximately 72% of the capacity was contracted with PPAs, for an average period of approximately 9 years, and an additional 18% of production was hedged. AVANGRID is one of the three largest wind operators in the United States based on installed capacity as of December 31, 2021 and strives to lead the

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transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables installed capacity includes 66 wind farms and four solar facilities in 21 states across the United States.

Proposed Merger with PNMR

On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation, or PNMR, and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID, or Merger Sub, entered into an Agreement and Plan of Merger, or Merger Agreement, pursuant to which Merger Sub is expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID, or the Merger. Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to, and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash, or Merger Consideration, or approximately $4.3 billion in aggregate consideration. In connection with the Merger, Iberdrola has provided the Iberdrola Funding Commitment Letter, pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration. On April 15, 2021, AVANGRID entered into a side letter agreement with Iberdrola, which sets forth certain terms and conditions relating to the Funding Commitment Letter, or 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 London Interbank Offer Rate, or 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, AVANGRID 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. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement, or the Amendment, pursuant to which AVANGRID, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger Agreement may be terminated by each of AVANGRID and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by AVANGRID and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals. In addition, the Closing of the Merger is subject to certain conditions including entry into agreements providing for, and to making filings required to, exit from all ownership interests in the Four Corners Power Plant and certain other customary closing conditions. For additional information, see Note 1 to our consolidated financial statements contained in this Annual Report on Form 10-K.

Further information regarding the amount of revenues from external customers, including revenues by products and services, a measure of profit or loss and total assets for each segment for each of the last three fiscal years is provided in Note 24 to our consolidated financial statements contained in this Annual Report on Form 10-K.

See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report for further details.

History

We were incorporated in 1997 as a New York corporation and named Energy East Corporation. In 2008, Iberdrola acquired Energy East Corporation and we changed our name to Iberdrola USA, Inc. In 2013, we completed an internal corporate reorganization to create a unified corporate presence for the Iberdrola brand in the United States, bringing all of its

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U.S. energy companies under Iberdrola USA, Inc. The internal reorganization resulted in the concentration of our principal businesses in two major subsidiaries: Networks, which holds all of our regulated utilities; and Renewables, which holds our renewable and thermal generation businesses.

On December 16, 2015, we completed the acquisition of UIL Holdings Corporation, or UIL, and changed our name to Avangrid, Inc. Immediately following the completion of the acquisition, former UIL shareowners owned 18.5% of the outstanding shares of common stock of AVANGRID, and Iberdrola owned the remaining shares.

Networks

Overview

Networks, a Maine corporation, holds our regulated utility businesses, including electric distribution, transmission and generation 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;

•SCG, which serves natural gas customers in Connecticut;

•CNG, which serves natural gas customers in Connecticut;

•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.

The demand for electric power and natural gas is affected by seasonal differences in the weather. Demand for electricity in each of the states in which Networks operates tends to increase during the summer months to meet cooling load or in winter months for heating load while demand for natural gas tends to increase during the winter to meet heating load.

The following table sets forth certain information relating to the rate base, number of customers and the amount of electricity or natural gas provided by each of Networks’ regulated utilities as of and for the year ended December 31, 2021:

Utility	Rate Base(1) (in billions)		Electricity Customers	Electricity Delivered (in MWh)	Natural Gas Customers	Natural Gas Delivered (in DTh)
NYSEG	$	3.5	907,336	15,406,000	270,204	53,381,000
RG&E	$	2.5	385,925	6,985,000	319,737	56,165,000
CMP	$	2.5	646,818	9,297,000	—	—
MNG	$	0.1	—	—	5,616	2,283,000
UI	$	1.9	342,928	4,943,000	—	—
SCG	$	0.6	—	—	208,024	35,700,000
CNG	$	0.5	—	—	184,880	36,259,000
BGC	$	0.1	—	—	40,741	10,117,000
Total	$	11.7	2,283,007	36,631,000	1,029,202	193,905,000

(1)“Rate base” means the net assets upon which a utility can receive a specified return, based on the carrying value of such assets. The rate base is set by the relevant regulatory authority and typically represents the value of specified property, such as plants, facilities and other investments of the utility. These rate base values have been calculated using the best estimates as of December 31, 2021.

During the last five years, Networks has invested $8.3 billion enhancing its delivery network with greater capacity and improved reliability, environmental security and sustainability, efficiency and automation. Networks continuously improves its grid to accommodate new requirements for advanced metering, demand response and enhanced outage management, while improving its flexibility for the integration and management of distributed energy resources, or DER.

New York

In 2021, the nine hydroelectric plants owned by NYSEG and RG&E generated approximately 132,200 megawatt-hours, or MWh of clean hydropower, which is enough energy to power approximately 18,000 homes across New York State,

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assuming an average electricity consumption of 600 kilowatt-hours, or kWh, per month per customer. See “—Properties—Networks” for more information regarding Networks’ electric generation plants. 

Networks also holds an approximate 20% ownership interest in the regulated New York TransCo, LLC, or New York TransCo. Through New York TransCo, Networks has formed a partnership with affiliates of Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc, and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York.

Maine

CMP owns 78% of the Maine Electric Power Corporation, or MEPCO, a single-asset 182-mile 345kV electric transmission line from the Maine/New Brunswick border to Wiscasset, Maine.

In 2018, the New England Clean Energy Connect, or NECEC, transmission project, a joint bid proposed by CMP and Hydro-Québec, was selected by the Massachusetts electric utilities and the Massachusetts Department of Energy Resources, or DOER, in the Commonwealth of Massachusetts’s 83D clean energy Request for Proposal. The proposed 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 $1.2 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. As of December 31, 2021, we have capitalized approximately $546 million on the NECEC project. For further discussion of the NECEC project, see “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report.

Connecticut

UI is a party to a joint venture with Clearway Energy, Inc., which is an affiliate of Global Infrastructure Partners, pursuant to which UI holds 50% of the membership interests in GCE Holding LLC, whose wholly-owned subsidiary, GenConn Energy LLC, or GenConn, operates peaking generation plants in Devon, Connecticut, or GenConn Devon, and Middletown, Connecticut, or GenConn Middletown.

Rate Base

The below rate base values were calculated using the best estimates as of December 31, 2021, 2020 and 2019. The rate base of Networks’ regulated utilities, excluding utilities accounted for under the equity method, for the years indicated below were as follows:

Rate base	2021		2020		2019
	(in millions)
NYSEG Electric	$	2,776	$	2,408	$	2,250
NYSEG Gas	715		703		610
RG&E Electric	1,911		1,566		1,453
RG&E Gas	553		492		516
Subtotal New York	5,955		5,169		4,829
CMP Dist	1,014		982		933
CMP Trans	1,493		1,448		1,469
MNG	87		77		76
Subtotal Maine	2,594		2,507		2,478
UI Dist	1,240		1,170		1,112
UI Trans	699		662		672
SCG	602		588		587
CNG	515		524		538
Subtotal Connecticut	3,056		2,944		2,909
BGC	128		124		136
Total	$	11,733	$	10,744	$	10,352

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Renewables

The Renewables business, based in Portland, Oregon and Boston, Massachusetts, is engaged primarily in the design, development, construction, management and operation of generation plants that produce electricity using renewable resources and, with more than 70 renewable energy projects, is one of the leaders in renewable energy production in the United States based on installed capacity. Renewables’ primary business is onshore wind energy generation, which represented approximately 95% of Renewables’ combined installed capacity as of December 31, 2021. For the year ended December 31, 2021, Renewables produced approximately 18,977,000 MWh of energy through wind power generation. Renewables had a pipeline of approximately 22,500 MW (approximately 17,500 MW - onshore and approximately 5,000 MW - offshore) of future renewable energy projects in various stages of development as of December 31, 2021.

A significant part of Renewables' strategic business is offshore wind. Renewables holds a 50% ownership interest in Vineyard Wind, LLC (Vineyard Wind) and an indirect ownership interest in Vineyard Wind 1 LLC (Vineyard Wind 1), each a joint venture with affiliates of Copenhagen Infrastructure Partners, or CIP, a fund management company based in Denmark. Vineyard Wind and Vineyard Wind 1 hold an interest in offshore lease areas off the coast of Massachusetts, the first of which is 166,886 acres (Lease Area 501, which was subsequently divided to create Lease Area 534) and the second lease area (Lease Area 522), acquired in 2018, is 132,370 acres located over 16 nautical miles off the coast of Massachusetts.

Renewables also has rights to a federal offshore wind lease area located more than 27 miles off the coast of North Carolina, which has the potential to generate up to 2,500 MW of renewable energy for Virginia and North Carolina. The lease area was acquired through a competitive federal auction in 2017 and is 122,405 acres.

Vineyard Wind 1 LLC is developing and has started onshore construction of the Vineyard Wind I project, an 800 MW utility-scale offshore wind project located 15 miles off the coast of Massachusetts on Lease Area 501 held by Vineyard Wind 1. The Vineyard Wind 1 project is expected to generate clean energy for over 400,000 households and businesses in Massachusetts and reduce carbon emissions by over 1.6 million tons per year. The project has 20-year PPAs with the electric distribution companies in Massachusetts with an average price of $88.77/MWh, which represents a price for 50% of the project that starts at $65/MWh and escalates 2.5% annually, and a price for the other 50% of the project that starts at $74/MWh and escalates 2.5% annually. Vineyard Wind LLC is also developing the Park City Wind project, an 804 MW project located on Lease Area 534, that will deliver clean, reliable energy to the residents of Connecticut through contracts with the electric distribution companies in Connecticut. The project has 20-year PPAs with the electric distribution companies in Connecticut, including UI, with an average price of $79.83/MWh, which is based on a starting price of $62.50 that escalates at 2.5% annually. With respect to the Park City Wind project, Vineyard Wind has agreed to have good faith negotiations to adjust the price if the project benefits from any improvements to the profitability of the project for having access to investments tax credits, or ITCs, in excess of 18%. Both projects are expected to be commissioned in 2024 to 2026, subject to permitting and contract negotiation.

In December 2021 Vineyard Wind’s Commonwealth Wind project, which will also be located on Lease Area 534 was selected as part of Massachusetts’ third offshore wind competitive procurement process. The 1,232 MW project will deliver clean energy to the residents of Massachusetts primarily through contracts with the electric distribution companies in the state. The Commonwealth project is expected to be commissioned in 2027, subject to permitting, contract negotiation and finalization of the power purchase agreements.

On September 15, 2021, Renewables entered into an agreement with CIP to restructure Vineyard Wind, which closed on January 10, 2022. Following the restructuring agreement closing, Vineyard Wind 1 remains a 50-50 joint venture, Renewables has full ownership of the project company containing Lease Area 534, including the Park City Wind and Commonwealth Wind projects along with any remaining non-contracted area in Lease Area 534, and CIP has full ownership of the project company containing Lease Area 522. The consideration exchanged resulted in Renewables making a payment of approximately $168 million to CIP. Refer to Note 22 to our consolidated financial statements contained in this Annual Report on Form 10-K.

Typically, Renewables enters into long-term lease agreements with property owners who lease their property and other sites for onshore renewable energy projects, and with federal agencies for offshore renewables energy projects. Electricity generated at a wind project is then transmitted to customers through long-term agreements with purchasers. There are a limited number of turbine suppliers in the market. Renewables’ largest turbine suppliers, Siemens-Gamesa and GE Wind, in the aggregate supplied turbines that accounted for 70% of Renewables’ installed wind capacity as of December 31, 2021. Iberdrola had an 8.1% ownership interest in Siemens-Gamesa until it was sold in February 2020.

To monetize the tax benefits resulting from production tax credits, or PTCs, and accelerated tax depreciation available to qualifying wind energy projects, Renewables has entered into “tax equity” financing structures with third party investors for a portion of its wind farms. Renewables holds operating wind farms under these structures through limited liability companies jointly owned by one or more third party investors. These investors generally provide an up-front investment and, in some

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cases, payments over time for their membership interests in the financing structures. In return, the investors receive specified cash distribution allocations and substantially all of the tax benefits generated by the wind farms, until such benefits achieve a negotiated return on their investment. Upon attainment of this target return, the sharing of the cash flows and tax benefits flip, with Renewables receiving substantially all of these amounts thereafter. We also have an option to repurchase the investor’s interest within a certain timeframe after the target return is met. Renewables maintains operational and management control over the wind farm businesses, subject to investor approval of certain major decisions. See “—Properties—Renewables” for more information regarding Renewables’ wind power generation properties.

Additionally, as part of the Renewables portfolio, Renewables operates two thermal generation facilities, with 636 MW of combined capacity as of December 31, 2021. Renewables worked closely with the City of Klamath Falls, Oregon to develop the Klamath Plant, which has a current capacity of 536 MW. The Klamath Plant operates by creating two useful forms of energy, electricity and process steam, from a single fuel source of natural gas. In addition, Renewables operates a highly flexible 100 MW Klamath Peaking Plant adjacent to the Klamath Plant, providing customers of Renewables additional capability to meet their peak summer and winter power needs.

In addition to its wind assets, Renewables operates four solar photovoltaic facilities with an installed capacity of 130 MW. The solar photovoltaic facilities produced over 242,000 MWh of renewable energy for the year ended December 31, 2021. Solar accounted for 1.3% of the total renewable energy generation from Renewables in 2021.

Renewables is pursuing the continued development of a large pipeline of wind and solar energy projects in various regions across the United States. Each site features a range of different atmospheric characteristics that ultimately drive the selection of technology for the proposed project. As part of Renewables’ resource assessment investigation, critical atmospheric parameters such as mean wind speed, extreme wind speed, turbulence intensity, mean air density, and solar energy availability are characterized to represent long-term conditions. The summary wind and solar characteristics are then combined with a terrain analysis, or orography, and weather pattern analysis to assess siting and placement risks in order to mitigate any future operations and maintenance concerns that may arise due to improper siting or placement.

Renewables maintains close relationships with key turbine suppliers, including Siemens-Gamesa, GE, Vestas and others in order to identify the turbine technology that safely delivers the lowest cost of energy for each candidate project in its portfolio. See “—Properties—Renewables” for more information regarding Renewables’ turbine technology.

Renewables focuses on ensuring solar projects deliver the lowest cost of energy safely. This requires detailed information on cost, long term performance and reliability of project components including solar panels, trackers and inverters – particularly as technology continues to advance. Renewables relies upon a wide network of experienced solar industry consultants to provide expert advice on project development, performance specifications, manufacturing quality assurance and equipment selection. These consultants range from Tetra Tech Inc. for environmental permitting support, to companies such as DNV GL, Clean Energy Associates, and PI Berlin to advise on energy estimation, equipment performance expectations, and equipment quality audits.

The Renewables meteorology team supports the commercial development of wind and solar energy projects in Renewables’ pipeline by performing a wide variety of detailed investigations and analyses to characterize the expected wind and solar energy production from a proposed wind farm or solar plant in its pre-construction phase of development. These investigations include measuring the wind or solar resource with several well-equipped meteorological masts and using energy modeling software packages that characterize the gross energy and relevant losses. For wind projects, state of the art laser-based and acoustic-based remote sensing equipment and computational fluid dynamics modeling software are used. The Renewables fleet of measurement masts consists of approximately 100 wind meteorological towers and 12 solar meteorological stations that are currently in operation. Additionally, a total of six light detecting and ranging and six sonic detecting and ranging remote sensing devices are deployed or available for deployment at sites across the United States to support wind project development. These remote sensing devices allow hub-height wind speed measurement from a ground-based sensor that can be rapidly deployed and moved as the project matures or changes in nature. The resulting pre-construction energy production estimates that utilize these measurements have been shown to be accurate in a multi-year internal study that compares results to actual, operational data at wind plants in a benchmarking analysis. This study provides a critical feedback loop that is used to define methodology requirements for future pre-construction energy production estimates to ensure confidence in project investment. Renewables’ commitment to obtaining robust atmospheric measurement is driven by a company culture that values business case confidence and understands the role that accurate meteorological data plays in the pursuit of this goal.

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Regulatory Environment and Principal Markets

Federal Energy Regulatory Commission

Among other things, the FERC regulates the transmission and wholesale sales of electricity in interstate commerce and the transmission and sale of natural gas for resale in interstate commerce. Certain aspects of Networks’ businesses and Renewables’ competitive generation businesses are subject to regulation by the FERC.

Pursuant to the FPA, electric utilities must maintain tariffs and rate schedules on file with the FERC, which govern the rates, terms and conditions for the provision of the FERC-jurisdictional wholesale power and transmission services. Unless otherwise exempt, any person that owns or operates facilities used for the wholesale sale or transmission of power in interstate commerce is a public utility subject to the FERC’s jurisdiction. The FERC regulates, among other things, the disposition of certain utility property, the issuance of securities by public utilities, the rates, the terms and conditions for the transmission or wholesale sale of power in interstate commerce, interlocking officer and director positions, and the uniform system of accounts and reporting requirements for public utilities.

With respect to Networks’ regulated electric utilities in Maine, New York and Connecticut, the FERC governs the return on equity, or ROE, on all transmission assets in Maine and Connecticut and certain New York TransCo assets in New York. The FERC also oversees the rates, terms and conditions of the transmission of electric energy in interstate commerce, interconnection service in interstate commerce (which applies to independent power generators, for example) and the rates, terms and conditions of wholesale sales of electric energy in interstate commerce. This includes cost-based rates, market-based rates and the operations of regional capacity and electric energy markets in New England administered by an independent entity, ISO New England, Inc., or ISO-NE, and in New York, administered by the New York Independent System Operator, Inc., or NYISO. The FERC approves CMP's, UI's and New York TransCo's regulated electric utilities transmission revenue requirements. Wholesale electric transmission revenues are recovered through formula rates that are approved by the FERC. CMP’s, MEPCO’s and UI’s electric transmission revenues are recovered from New England customers through charges that recover costs of transmission and other transmission-related services provided by all regional transmission owners. NYSEG’s and RG&E’s electric transmission revenues are recovered from New York customers through charges that recover the costs of transmission and other transmission-related services provided by all transmission owners in New York. Several of our affiliates have been granted authority to engage in sales at market-based rates and blanket authority to issue securities and have also been granted certain waivers of the FERC reporting and accounting regulations available to non-traditional public utilities; however, we cannot be assured that such authorizations or waivers will not be revoked for these affiliates or will be granted in the future to other affiliates.

Pursuant to a series of orders involving the ROE for regionally planned New England electric transmission projects, the FERC established a base-level transmission ROE of 11.14%, as well as providing a 50-basis point ROE adder on Pool Transmission Facilities for participation in the regional transmission organization, or RTO, for New England and a 100-basis point ROE incentive for projects included in the ISO-NE Regional System Plan that were completed and on line as of December 31, 2008. Certain other transmission projects received authorization for incentives up to 125 basis points.

Since 2011, several parties have filed four separate complaints with the FERC against ISO-NE and several New England transmission owners, or NETOs, including UI, CMP and MEPCO, claiming that the current approved base ROE of 11.14% was not just and reasonable, seeking a reduction of the base ROE and a refund 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). ). For more information on this matter see Note 14 of our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K, which information is incorporated herein by reference.

The FERC has the right to review books and records of “holding companies,” as defined in the Public Utility Holding Company Act of 2005, or PUHCA 2005, that are determined by the FERC to be relevant to the companies’ respective FERC-jurisdictional rates. We are a holding company, as defined in PUHCA 2005.

The FERC has civil penalty authority over violations of any provision of Part II of the FPA, as well as any rule or order issued thereunder. FERC is authorized to assess a maximum civil penalty of $1.3 million per violation for each day that the violation continues. The FPA also provides for the assessment of criminal fines and imprisonment for violations under Part II of the FPA. Pursuant to the Energy Policy Act of 2005, or EPAct 2005, the North American Electric Reliability Corporation, or NERC, has been certified by the FERC as the Electric Reliability Organization for North America responsible for developing and overseeing the enforcement of electric system reliability standards applicable throughout the United States. FERC-approved reliability standards may be enforced by the FERC independently, or, alternatively, by NERC and the regional reliability organizations with frontline responsibility for auditing, investigating and otherwise ensuring compliance with reliability standards, subject to the FERC oversight.

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The gas distribution operations of NYSEG, RG&E, SCG, CNG and BGC are subject to the FERC regulation under the Natural Gas Act of 1938, or NGA, with respect to their gas purchases/sales and contracted transportation/storage capacity. FERC has civil penalty authority under the NGA to impose penalties for certain violations of up to $1.3 million per day for violations. FERC also has the authority to order the disgorgement of profits from transactions deemed to violate the NGA and EPAct 2005.

Market Anti-Manipulation Regulation

The FERC and the Commodity Futures Trading Commission, or CFTC, monitor certain segments of the physical and futures energy commodities market pursuant to the FPA, the Commodity Exchange Act and the Dodd-Frank Wall Street Reform and Consumer Protection Act, or the Dodd-Frank Act, including our businesses’ energy transactions and operations in the United States. With regard to the physical purchases and sales of electricity and natural gas, the gathering storage, transmission and delivery of these energy commodities and any related trading or hedging transactions that some of our operating subsidiaries undertake, our operating subsidiaries are required to observe these anti-market manipulation laws and related regulations enforced by the FERC and CFTC. The FERC holds substantial enforcement authority, including the ability to assess civil penalties of up to $1.3 million per day per violation, to order disgorgement of profits and to recommend criminal penalties. The CFTC is authorized to issue monetary penalties for violations of the Commodity Exchange Act up to a maximum penalty per violation. Generally, penalties may be determined on a per violation basis or up to triple the monetary gain to the respondent, whichever is greater.

State Regulation

Networks’ regulated utilities are subject to regulation by the applicable state public utility commissions, including with regard to their rates, terms and conditions of service, issuance of securities, purchase or sale of utility assets and other accounting and operational matters. NYSEG and RG&E are subject to regulation by the NYPSC; CMP and MNG are subject to regulation by the MPUC; UI, SCG and CNG are subject to regulation by the PURA; and BGC is subject to regulation by the DPU. The NYPSC, MPUC and the Connecticut Siting Council, or CSC, exercise jurisdiction over the siting of electric transmission lines in their respective states, and each of the NYPSC, MPUC, PURA and DPU exercise jurisdiction over the approval of certain mergers or other business combinations involving Networks’ regulated utilities. In addition, each of the utility commissions has the authority to impose penalties on these regulated utilities, which could be substantial, for violating state utility laws and regulations and their orders. 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 will deliver a final Scoping Plan by January 1, 2023.

Networks’ regulated distribution utilities deliver electricity and/or natural gas to all customers in their service territory at rates established under cost of service regulation. Under this regulatory structure, Networks’ regulated distribution utilities file rate cases to recover the cost of providing distribution service to their customers based on its costs and earn a return on their capital investment in utility assets. For more information on our regulated utilities’ most recent rate cases and other regulatory matters see Note 5 of our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K, which information is incorporated herein by reference.

As a result of a restructuring of the utility industry in New York, Maine, Connecticut and Massachusetts, most of Networks’ distribution utilities’ customers have the opportunity to purchase their electricity or natural gas supplies from third-party energy supply vendors. Most customers in New York, however, continue to purchase such supplies through the distribution utilities under regulated energy rates and tariffs. In Maine, CMP customers can also purchase electric supply from competitive providers, but the majority receive baseline standard offer service that is provided through a MPUC procurement process. Networks’ regulated utilities in New York, Connecticut and Massachusetts and MNG purchase electricity or natural gas from unaffiliated wholesale suppliers and recover the actual approved costs of these supplies on a pass-through basis, as well as certain costs associated with industry restructuring, through reconciling rate mechanisms that are periodically adjusted.

State public utility commissions may also have jurisdiction over certain aspects of Renewables’ competitive generation businesses. For example, in New York, certain Renewables’ generation subsidiaries are electric corporations subject to “lightened” regulation by the NYPSC. As such, the NYPSC exercises its jurisdictional authority over certain non-rate aspects of the facilities, including safety, retirements and the issuance of debt secured by recourse to those generation assets located in New York. In Texas, Renewables’ operations within the Electric Reliability Council of Texas, or ERCOT, footprint are not subject to regulation by FERC, as they are deemed to operate solely within the ERCOT market and not in interstate commerce.

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These operations are subject to regulation by the Public Utility Commission of Texas, or PUCT. In California, Renewables’ generation subsidiaries are subject to regulation by the California Public Utilities Commission with regard to certain non-rate aspects of the facilities, including health and safety, outage reporting and other aspects of the facilities’ operations.

RTOs and ISOs

Networks’ regulated electric utilities in New York, Connecticut and Maine, as well as some of Renewables’ generation fleet, operate in or have access to organized energy markets, known as RTOs or independent system operators, or ISOs, particularly NYISO and ISO-NE. Each organized market administers centralized bid-based energy, capacity and ancillary services markets pursuant to tariffs approved by the FERC, or in the case of ERCOT, market rules approved by the PUCT. These tariffs and rules dictate how the energy, capacity and ancillary service markets operate, how market participants bid, clear, are dispatched, make bilateral sales with one another, and how entities with market-based rates are compensated. Certain of these markets set prices, referred to as Locational Marginal Prices that reflect the value of energy, capacity or certain ancillary services, based upon geographic locations, transmission constraints and other factors. Each market is subject to market mitigation measures designed to limit the exercise of market power. Some markets limit the prices of the bidder based upon some level of cost justification. These market structures impact the bidding, operation, dispatch and sale of energy, capacity and ancillary services.

The RTOs and ISOs are also responsible for transmission planning and operations within their respective regions. Each of Networks’ transmission-owning subsidiaries in New York, Connecticut and Maine has transferred operational control over certain of its electric transmission facilities to its respective ISOs, such as ISO-NE and NYISO.

Environmental, Health and Safety

Permitting and Other Regulatory Requirements

Networks. Networks’ distribution utilities in New York, Maine, Connecticut and Massachusetts are subject to numerous federal, state and local laws and regulations in connection with the environmental, health and safety effects of its operations. The distribution utilities of Networks are subject to regulation by the applicable state public utility commission with respect to the siting and approval of electric transmission lines, with the exception of UI, the siting of whose transmission lines is subject to the jurisdiction of the CSC, and with respect to pipeline safety regulations for intrastate gas pipeline operators.

The National Environmental Policy Act, or NEPA, requires that detailed statements of the environmental effect of Networks’ facilities be prepared in connection with the issuance of various federal permits and licenses. Federal agencies are required by NEPA to make an independent environmental evaluation of the facilities as part of their actions during proceedings with respect to these permits and licenses.

Under the federal Toxic Substances Control Act, the Environmental Protection Agency, or EPA, has issued regulations that control the use and disposal of Polychlorinated Biphenyls, or PCBs. PCBs were widely used as insulating fluids in many electric utility transformers and capacitors manufactured before the federal Toxic Substances Control Act prohibited any further manufacture of such PCB equipment. Fluids with a concentration of PCBs higher than 500 parts per million and materials (such as electrical capacitors) that contain such fluids must be disposed of through burning in high temperature incinerators approved by the EPA. For our gas distribution companies, PCBs are sometimes found in the distribution system. Networks tests any distribution piping being removed or repaired for the presence of PCBs and complies with relevant disposal procedures, as needed.

Under the federal Resource Conservation and Recovery Act, or RCRA, the generation, transportation, treatment, storage and disposal of hazardous wastes are subject to regulations adopted by the EPA. All of Networks’ subsidiaries have complied with the notification and application requirements of present regulations, and the procedures by which the subsidiaries handle, store, treat and dispose of hazardous waste products comply with these regulations.

Before the environmental best practices laws and regulations were implemented in the last quarter of the 20th century, utility companies, including Networks’ subsidiaries, often disposed of residues from operations by depositing or burying them on-site or at off-site landfills or other facilities. Typical materials disposed of included coal gasification byproducts, fuel oils, ash and other materials that might contain PCBs or otherwise be hazardous. In recent years it was determined that such disposal practices, under certain circumstances, can cause groundwater contamination.

Renewables. Renewables’ projects are subject to numerous federal, state and local environmental review and permitting requirements. Whether a project is sited onshore or offshore dictates the complexity of the permitting framework.

Many states where Renewables’ projects are located have laws that require state agencies to evaluate the environmental impacts of a proposed project prior to granting state permits or approvals. Generally, state agencies evaluate similar issues as

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federal agencies, including the project’s impact on wildlife, historic or cultural sites, aesthetics, wetlands and water resources, agricultural operations and scenic areas. States may impose different or additional monitoring or mitigation requirements than federal agencies. Additional approvals may be required for specific aspects of a project, such as stream or wetland crossings, impacts to designated significant wildlife habitats, storm water management and highway department authorizations for oversize loads and state road closings during construction. Permitting approvals related to transmission lines may be required in certain cases.

Renewables’ projects also are subject to local environmental and regulatory requirements, including county and municipal land use, zoning, building and transportation requirements. Permitting at the local municipal or county level often consists of obtaining a special use or conditional use permit under a land use ordinance or code, or, in some cases, rezoning is required for a project. Obtaining a permit usually requires that Renewables demonstrate that the project will conform to certain development standards specified under the ordinance so that the project is compatible with existing land uses and protects natural and human environments. Local or state regulatory agencies may require modeling and measurement of permissible sound levels in connection with the permitting and approval of Renewables’ projects. Local or state agencies also may require Renewables to develop decommissioning plans for dismantling the project at the end of its functional life and establish financial assurances for carrying out the decommissioning plan.

In addition to permits required under state and local laws, Renewables’ projects may be subject to permitting and other regulatory requirements under federal law. For example, if an offshore wind project is sited in federal waters (beyond the 3 nautical mile state jurisdictional line), the project will require approval from the Department of Interior’s Bureau of Ocean Energy Management, or BOEM as well as other federal cooperating agencies such as the National Oceanic and Atmospheric Administration’s National Marine Fisheries Service, the U.S. Army Corps of Engineers, or Army Corps, the Federal Aviation Administration, the Department of Defense, the U.S. Environmental Protection Agency and the U.S. Coast Guard. If an onshore project is located near wetlands, a permit may be required from the Army Corps, with respect to the discharge of dredged or fill material into the waters of the United States. The Army Corps may also require the mitigation of any loss of wetland functions and values that accompanies the project’s activities. Renewables may be required to obtain permits under the federal Clean Water Act for water discharges, such as storm water runoff associated with construction activities, and to follow a variety of best management practices to ensure that water quality is protected and impacts are minimized. Renewables’ projects also may be located, or partially located, on lands administered by the U.S. Bureau of Land Management, or BLM. Therefore, Renewables may be required to obtain and maintain BLM right-of-way grants for access to, or operations on, such lands. To obtain and maintain a grant, there must be environmental reviews conducted, a plan of development implemented and a demonstration that there has been compliance with the plan to protect the environment, including measures to protect biological, archeological and cultural resources encountered on the grant.

Renewables’ projects may be subject to requirements pursuant to the Endangered Species Act, or ESA, and analogous state laws. For example, federal agencies granting permits for Renewables’ projects consider the impact on endangered and threatened species and their habitat under the ESA, which prohibits and imposes stringent penalties for harming endangered or threatened species and their habitats. Renewables’ projects also need to consider the Migratory Bird Treaty Act, or MBTA, and the Bald and Golden Eagle Protection Act, or BGEPA, which protect migratory birds and bald and golden eagles and are administered by the U.S. Fish and Wildlife Service. Criminal liability can result from violations of the MBTA and the BGEPA. For example, the U.S. Department of Justice, or DOJ, has previously enforced substantial penalties and mitigation measures against two large wind farm operators, pursuant to which those operators pled guilty to criminal violations of the MBTA.

In addition to regulations, voluntary wind turbine siting guidelines for onshore wind projects established by the U.S. Fish and Wildlife Service, or USFWS, set forth siting, monitoring and coordination protocols that are designed to support wind development in the United States while also protecting both birds and bats and their habitats. These guidelines include provisions for specific monitoring and study conditions which need to be met in order for projects to be in adherence with these voluntary guidelines. Most states also have similar laws. Because the operation of wind turbines may result in injury or fatalities to birds and bats, federal and state agencies often recommend or require that Renewables conduct avian and bat risk assessments prior to issuing permits for its projects. They may also require ongoing monitoring or mitigation activities as a condition to approving a project.

Similarly, BOEM has established survey guidelines for renewable energy development, including avian surveys in coordination with the USFWS. BOEM will use the data from the offshore marine surveys to evaluate the impacts of construction, installation and operation of meteorological towers, buoys, export and inter-array cables, wind turbine generators and supporting structures on physical, biological, and socioeconomic resources, as well as the seafloor and sub-seafloor conditions. The information will be used by BOEM, other federal agencies and potentially affected states in the preparation of National Environmental Policy Act documents, for consultations and other regulatory requirements.

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Global Climate Change and Greenhouse Gas Emission Issues

Global climate change and greenhouse gas emission issues continue to receive an increased focus from state governments and the federal government. In November 2010, the EPA published final rules for monitoring and reporting requirements for petroleum and natural gas systems that emit greenhouse gases under the authority of the Clean Air Act beginning in 2011. These regulations apply to facilities that emit greenhouse gases above the threshold level of 25,000 metric tons equivalent per year. SCG and CNG both exceed this threshold and are subject to reporting requirements. The liquefied natural gas, or LNG, facilities owned and/or contracted by SCG and CNG are also subject to the monitoring and reporting requirements under the regulations. Similarly, Networks is subject to reporting requirements under provisions of the greenhouse gases regulations, which regulate electric transmission and distribution equipment that emit sulfur hexafluoride.

We are continuously evaluating the regulatory risks and regulatory uncertainty presented by climate change and greenhouse gas emission. Such concerns could potentially lead to additional rules and regulations as well as requirements imposed through the ratemaking process that impact how we operate our business. We expect that any of Networks' costs for these rules, regulations and requirements would be recovered from customers.

OSHA and Certain Other Federal Safety Laws

We are subject to the requirements of the federal Occupational Safety and Health Act, as amended, or OSHA, and comparable state laws that regulate the protection of the health and safety of employees. In addition, OSHA’s hazard communication standard and standards administered by other federal as well as state agencies, including the Emergency Planning and Community Right to Know Act and the related implementing regulations require that information be maintained about hazardous materials used or produced in operations of our subsidiaries and that this information be provided to employees, state and local government authorities and citizens.

Management, Disposal and Remediation of Hazardous Substances

We own or lease real property and may be subject to federal, state and local requirements regarding the storage, use, transportation and disposal of petroleum products and toxic or hazardous substances, including spill prevention, control and counter-measure requirements. Project properties and materials stored or disposed thereon may be subject to the federal RCRA, the Toxic Substances Control Act, the Comprehensive Environmental Response, Compensation and Liability Act and analogous state laws. If any of our owned or leased properties are contaminated, whether during or prior to our ownership or operation, we could be responsible for the costs of investigation and cleanup and for any related liabilities, including claims for damage to property, persons or natural resources. Such responsibility may arise even if we were not at fault and did not cause the contamination. In addition, waste generated by our operating subsidiaries is at times sent to third party disposal facilities. If such facilities become contaminated, the operating subsidiary and any other persons who arranged for the disposal or treatment of hazardous substances at those sites may be jointly and severally responsible for the costs of investigation and remediation, as well as for any claims of damages to third parties, their property or natural resources.

In August 2016, a partial consent order was issued by the Connecticut Department of Energy and Environmental Protection, or DEEP, related to the investigation and remediation of the English Station site. The consent order 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 is required to remit to the State of Connecticut the difference between such cost and $30 million to be applied to 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. However, UI is obligated to comply with the consent order even if the cost of such compliance exceeds $30 million. The state may discuss options with UI on recovering or funding any cost above $30 million, such as through public funding or recovery from third parties, however it is not bound to agree to or support any means of recovery or funding. UI has initiated its process to investigate and remediate the environmental conditions within the perimeter of the English Station site pursuant to the consent order.

Environmental Management and Goals

In connection with our environmental, social, governance and financial stewardship strategy, we have established a goal to be Scope 1 carbon neutral, as defined by the U.S. Environmental Protection Agency, by 2035. Further, we have defined a set of goals to reduce the environmental impact of our facilities including a 25% reduction in carbon footprint by 2030, 50% more green energy by 2030 and 50% fewer tons of paper used.

See information on infrastructure protection and cyber security measures in "Properties" in Item 1 of this Annual Report on Form 10-K.

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Customers

Networks delivers natural gas and electricity to residential, commercial and institutional customers through its regulated utilities in New York, Maine, Connecticut and Massachusetts. Networks’ customer payment terms are regulated by the state of New York, with respect to NYSEG and RG&E; Maine, with respect to CMP and MNG; Connecticut, with respect to UI, SCG and CNG; and Massachusetts, with respect to BGC, and each of the regulated utilities must provide extended payment arrangements to customers for past due balances. See “—Networks” for more information relating to the customers of Networks.

Renewables sells the majority of its energy output to large investor-owned utilities, public utilities and other credit-worthy entities. Additionally, Renewables generates and provides power, among other services, to federal and state agencies, institutional retail and joint action agencies. Offtakers typically purchase renewable energy from Renewables through long-term PPAs, allowing Renewables to limit its exposure to market volatility. As of December 31, 2021, approximately 72% of the capacity was contracted with PPAs, for an average period of approximately 9 years, and an additional 18% of production was hedged. Renewables also delivers thermal output to wholesale customers in the Western United States.

Competition

Networks’ regulated utilities do not generally face competition from other companies that transmit and distribute electricity and natural gas. However, supply for electricity and natural gas may be negatively impacted by federal and state legislation mandating that certain percentages of power delivered to end users be produced from renewable resources, such as wind, thermal and solar energy, and demand for electricity and natural gas may be negatively impacted by federal and state legislation mandating energy efficiency programs and policy.

Networks faces competition from self-contained micro-grids that integrate renewable energy sources in the areas served by Networks. However, there has been limited development of these micro-grids in Networks’ service areas to date, and Networks expects that growth in distributed generation of renewable energy will continue due to financial incentives being provided by federal and state legislation. In addition, Networks may face competition from government-controlled power initiatives in states where Networks operates in which states, municipalities or other local authorities attempt to use eminent domain to acquire privately-owned utility companies.

Renewables has competitive advantages, including a robust development pipeline, a management team with extensive experience, strong relationships with suppliers and clients, expert regulatory knowledge and brand awareness. However, Renewables faces competition throughout the life cycles of its renewable energy facilities, including during the development phase, in the identification and procurement of suitable sites with high wind resource availability, grid connection capacity and land availability. Renewables also competes with other suppliers in securing long-term renewable energy PPAs with power purchasers and participates in competitive bilateral and organized energy markets with other energy sources for power that is not sold under PPAs. Competitive conditions may be substantially affected by various forms of energy legislation and regulation considered from time to time by federal, state and local legislatures and administrative agencies.

Properties

Networks

The following table sets forth certain information relating to Networks’ electricity generation facilities and their respective locations, type and installed capacity as of December 31, 2021. Unless noted otherwise, Networks owns each of these facilities and all our generating properties are regulated under cost of service regulation.

Operating Company	Facility Location	Facility Type	Installed Capacity (in MW)	Year(s) Commissioned
NYSEG	Newcomb, NY	Diesel Turbine	4.3	1967, 2017
NYSEG	Blue Mountain, NY	Diesel Turbine	2.0	2019
NYSEG	Long Lake, NY	Diesel Turbine	2.0	2019
NYSEG	Eastern New York (6 locations)	Hydroelectric	61.4	1921—1986
RG&E	Rochester, NY (3 locations)	Hydroelectric	57.1	1917—1960

UI is also party to a 50-50 joint venture with certain affiliates of Clearway Energy, Inc. in GCE Holding LLC, whose wholly-owned subsidiary, GenConn, operates two 188 MW peaking generation plants, GenConn Devon and GenConn Middletown, in Connecticut.

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The following table sets forth certain operating data relating to the electricity transmission and distribution activities of each of Networks’ regulated utilities as of December 31, 2021:

Utility	State	Substations	Transmission Lines (in miles)	Overhead Distribution Lines (in pole miles)	Underground Lines (in miles)	Total Distribution (in miles)
NYSEG	New York	430	4,472	32,224	2,960	35,184
RG&E	New York	156	1,084	5,999	2,960	8,959
CMP	Maine	205	2,919	21,954	1,780	23,734
UI	Connecticut	28	138	2,881	715	3,596
Total		819	8,613	63,058	8,415	71,473

The following table sets forth certain operating data relating to the natural gas transmission and distribution activities of each of Networks’ regulated utilities, as of December 31, 2021:

Utility	State	Transmission Pipeline (in miles)	Distribution Pipeline (in miles)
NYSEG	New York	20	8,452
RG&E	New York	103	9,144
MNG	Maine	2	231
SCG	Connecticut	—	2,511
CNG	Connecticut	—	2,215
BGC	Massachusetts	—	770
Total		125	23,323

CNG owns and operates an LNG plant which can store up to 1.2 Bcf of natural gas and can vaporize up to 100,000 Dth per day of LNG to meet peak demand. SCG has contract rights to and operates a similar plant, which is owned by an affiliate that can also store up to 1.2 Bcf of natural gas. SCG’s LNG facilities can vaporize up to 82,000 Dth per day of LNG to meet peak demand. SCG and CNG have also contracted for 20.6 Bcf of storage with a maximum peak day delivery capability of 216,000 Dth per day.

Renewables

The following table sets forth Renewables’ portfolio of wind projects as of December 31, 2021. Unless noted otherwise, Renewables wholly owns each of these facilities.

Location	Wind Project	Turbines	Total Installed Capacity (MW)	Commercial Operation Date	North American Electric Reliability Corporation (NERC) Region
Arizona	Dry Lake I	30 (Suzlon S88, 2.1 MW)	63	2009	WECC
	Poseidon Wind (1)	15.5 (Suzlon, 2.1 MW)	33	2010	WECC
California	Dillon	45 (Mitsubishi, 1 MW)	45	2008	WECC
	Manzana	126 (GE, 1.5 MW)	189	2011	WECC
	Mountain View III	34 (Vestas V47, 0.66 MW)	22	2020	WECC
	Phoenix Wind Power	3 (Vestas, 0.66 MW)	2	1999	WECC
	Shiloh	100 (GE, 1.5 MW)	150	2006	WECC
	Tule	57 (GE, 2.3 MW)	131	2017	WECC
Colorado	Colorado Green	100 (GE, 1.5 SLE RP1.62 MW)	162	2003	WECC
	Twin Buttes	50 (GE, 1.5 MW)	75	2007	WECC
	Twin Buttes II	30 (Gamesa G114, 2.10 MW); 6 (Gamesa G114, 2.0 MW)	75	2017	WECC
Illinois	Providence Heights	36 (Gamesa G87, 2.0 MW)	72	2008	MRO
	Streator Cayuga Ridge South	150 (Gamesa, 2.0MW)	300	2010	MRO
	Otter Creek	38 (Vestas, 3.8 MW); 4 (Vestas, 3.5 MW)	158	2020	MRO
Iowa	Barton	80 (Gamesa, 2.0 MW)	158	2009	MRO
	Flying Cloud	29 (GE, 1.5 MW)	44	2004	MRO

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Location	Wind Project	Turbines	Total Installed Capacity (MW)	Commercial Operation Date	North American Electric Reliability Corporation (NERC) Region
	New Harvest	50 (Gamesa G87, 2.0W)	100	2012	MRO
	Top of Iowa II	40 (Gamesa G87, 2.0 MW)	80	2008	MRO
	Winnebago I	10 (Gamesa G87, 2.0 MW)	20	2008	MRO
Kansas	Elk River	100 (GE, 1.5 MW)	150	2005	MRO
Massachusetts	Hoosac	19 (GE, 1.5 MW)	29	2012	NPCC
Minnesota	Elm Creek	66 (GE, 1.5 MW)	99	2008	MRO
	Elm Creek II	62 (Mitsubishi, 2.4)	149	2010	MRO
	MinnDakota	100 (GE, 1.5 MW)	150	2008	MRO
	Moraine I	34 (GE, 1.5 MW)	51	2003	MRO
	Moraine II	33 (GE, 1.5 MW)	50	2009	MRO
	Trimont	67 (GE, 1.5 SLE RP1.62 MW)	107	2020	MRO
Missouri	Farmers City	72 (Gamesa G87, 2.0 MW)	144	2009	MRO
New Hampshire	Groton	24 (Gamesa G87, 2.0 MW)	48	2012	NPCC
	Lempster	12 (Gamesa G87, 2 MW)	24	2008	NPCC
New Mexico	El Cabo	140 (Gamesa G114, 2.1 MW); 2 (Gamesa G114, 2.0 MW)	298	2017	WECC
	La Joya	76 (GE 2.85, 2.85 MW); 35 (Gamesa G114, 2.6 MW)	306	2021	WECC
New York	Hardscrabble	37 (Gamesa G90, 2.0 MW)	74	2011	NPCC
	Maple Ridge I(2)	70 (Vestas V82, 1.65 MW)	116	2006	NPCC
	Maple Ridge II(2)	28 (Vestas V82, 1.65 MW)	45	2006	NPCC
	Roaring Brook	5 (Gamesa G114, 2.625); 15 (Gamesa G145, 4.5)	81	2021	NPCC
North Carolina	Desert Wind	104 (Gamesa G114, 2.0 MW)	208	2016	SERC
North Dakota	Rugby	71 (Suzlon S88, 2.1 MW)	149	2009	MRO
Ohio	Blue Creek	152 (Gamesa G90 – 2.0 MW)	304	2012	RFC
Oregon	Hay Canyon	48 (Suzlon S88, 2.1 MW)	101	2009	WECC
	Klondike I	16 (GE, 1.5 S – 1.5 MW)	24	2001	WECC
	Klondike II	50 (GE, 1.5 SLE RP1.62 MW)	81	2020	WECC
	Klondike III	44 (Siemens, 2.3 MW); 80 (GE, 1.5 SLE, 1.5 MW); 1 (Mitsubishi, 2.4 MW)	224	2007	WECC
	Klondike IIIa	51 (GE, 1.5 MW)	77	2008	WECC
	Leaning Juniper II	74 (GE, 1.5 MW); 42 (Suzlon, 2.1 MW)	199	2011	WECC
	Montague	51 (Vestas, 3.6 MW); 5 (Suzlon, 3.45 MW)	201	2019	WECC
	Pebble Springs	47 (Suzlon, 2.1 MW)	99	2009	WECC
	Star Point	47 (Suzlon, 2.1 MW)	99	2010	WECC
	Golden Hills	47 (Vestas, 4.3 MW)	190	2021	WECC
Pennsylvania	Casselman	23 (GE, 1.5 MW)	35	2008	RFC
	Locust Ridge I	13 (Gamesa G87, 2.0)	26	2006	RFC
	Locust Ridge II	50 (Gamesa G87, 2.0 MW)	100	2009	RFC
	South Chestnut	22 (Gamesa, 2.0 MW)	44	2012	RFC
South Dakota	Buffalo Ridge I	24 (Suzlon, 2.1 MW)	50	2009	MRO
	Buffalo Ridge II	105 (Gamesa G87, 2.0 MW)	210	2010	MRO
	Coyote Ridge (3)	35 (GE, 2.52 MW); 4 (GE, 2.3 MW)	20	2019	MRO
	Tatanka Ridge (3)	50 (GE, 2.3 MW); 6 (GE, 2.3 MW)	23	2021	MRO
Texas	Baffin	101 (Gamesa G97, 2.0 MW)	202	2015	TRE
	Barton Chapel	60 (Gamesa, 2.0 MW)	120	2009	TRE
	Karankawa	93 (GE, 2.52 MW); 22 (GE, 2.3 MW); 9 (GE, 2.5 MW)	307	2019	TRE

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Location	Wind Project	Turbines	Total Installed Capacity (MW)	Commercial Operation Date	North American Electric Reliability Corporation (NERC) Region
	Patriot	58 (Vestas, 3.6 MW);  5 (Vestas, 3.45 MW)	226	2019	TRE
	Peñascal I	84 (Mitsubishi, 2.4 MW)	202	2009	TRE
	Peñascal II	83 (Mitsubishi, 2.4 MW)	199	2010	TRE
Vermont	Deerfield	7 (Gamesa G87, 2.0 MW); 8 (Gamesa G97, 2.0 MW)	30	2017	NPCC
Washington	Big Horn I	133 (GE, 1.5 MW)	200	2006	WECC
	Big Horn II	25 (Gamesa, 2.0 MW)	50	2010	WECC
	Juniper Canyon	62 (Mitsubishi, 2.4 MW)	149	2011	WECC

(1)Jointly owned with Axium; capacity amounts represent only Renewables’ share of the wind farm.

(2)Jointly owned with Horizon Wind Energy; capacity amounts represent only Renewables’ share of the wind farm.

(3)Jointly owned with WEC Infrastructure; capacity amounts represent only Renewables’ share of the wind farm.

Additionally, set forth below are the solar and thermal facilities operated by Renewables as of December 31, 2021. Unless otherwise noted, Renewables owns each facility.

Facility	Location	Type of Facility	Installed Capacity (MW) (3)	Commercial Operation Date
Poseidon Solar (1)	Pinal County, Arizona	Solar	12	2011
San Luis Valley Solar Ranch (2)	Alamosa County, Colorado	Solar	35	2012
Gala Solar	Deschutes County, Oregon	Solar	70	2017
Wy’East Solar	Sherman County, Oregon	Solar	13	2018
Klamath Cogeneration	Klamath Falls, Oregon	Thermal	536	2001
Klamath Peakers	Klamath Falls, Oregon	Thermal	100	2009

(1)Jointly owned with Axium; capacity amounts represent only Renewables' share of the solar project.

(2)Operated pursuant to a sale-and-leaseback agreement.

(3)Previously reported in MWac. Reported in MWdc starting in 2020.

Infrastructure Protection and Cyber Security Measures

We have risk-based security measures in place designed to protect our facilities, assets and cyber-infrastructure, such as our transmission and distribution system.

While we have not had any significant security breaches, a physical security intrusion could potentially lead to theft and the release of critical operating information. In addition to physical security intrusions, a cyber breach could potentially lead to theft and the release of critical operating information or confidential customer information.

To manage these operational risks, pursuant to the cybersecurity risk policy and corporate security policy approved by the AVANGRID Board, we have implemented cyber and physical security measures and continue to strengthen our security posture by improving and expanding our physical and cyber security capabilities to protect critical assets. In addition, the Audit and Compliance Committee of the AVANGRID Board has responsibility for oversight of physical and cyber security matters, incident response management, and risks related to physical security, information security, cybersecurity, and technology, as well as the steps taken by management to mitigate such risks. Corporate Security maintains strong relationships with the U.S. Department of Homeland Security, or DHS, the Cybersecurity and Infrastructure Security Agency, or CISA, National Security Council, or NSC, the FBI, and the Department of Energy to ensure threat information is passed in a timely manner for situation awareness and that actions are taken to reduce risk.

In an effort to reduce our vulnerability to cyber-attacks, the AVANGRID Board appointed a senior officer responsible for security (Chief Security Officer) and we have established a dedicated corporate security office, responsible for improving and coordinating security across the company, who regularly reports to the Audit and Compliance Committee of the AVANGRID board on security matters. We have adopted a comprehensive company-wide physical and cyber security program, which is supported by a governance program to manage, oversee and assist us in meeting our corporate, legal and regulatory responsibilities with regard to the protection of our cyber, physical and information assets.

However, as threats evolve and grow increasingly more sophisticated, we cannot ensure that a potential security breach may not occur or quantify the potential impact of such an event. We continue to invest in technology, processes, security

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measures and services to predict, detect, mitigate and protect our assets, both physical and cyber. These investments include upgrades to our cyber-infrastructure assets, network architecture and physical security measures, and compliance with emerging industry best practice and regulation. See the risk factor “Security breaches, acts of war or terrorism, grid disturbances or unauthorized access could negatively impact our business, financial condition and reputation” under Item 1A - Risk Factors.

Human Capital Resources

At AVANGRID, we aspire to be a company where talented and committed people want to build long-term careers.

We foster a culture that values continuous improvement and seeks diverse perspectives. We recognize and reward behavior and ideas that drive company performance and that prepare us to meet the challenges and opportunities of the future.

The overall health of our workforce is important to us – from physical safety and financial security, to high levels of engagement and a respectful work environment. We invest in workforce programs that enable personal and professional growth, help employees build connections with one another, and meet the unique needs of our employees and their families.

As of December 31, 2021, we employed 7,348 employees, virtually all of whom are full-time. 91.8% of employees were based in five states – Connecticut, Massachusetts, Maine, New York, and Oregon. During fiscal year 2021, we hired and onboarded 974 employees.

Approximately 47.7% of our employees are represented by a collective bargaining agreement and we generally enjoy strong working relationships with all our labor unions. Agreements expiring in the coming year apply to approximately 18.8% of our employees. There is mutual respect and collaboration when discussing the variety of issues we face on an ongoing basis, and both parties share the goal of supporting the business while helping to ensure a positive customer experience.

For the year ended December 31, 2021, the information on turnover rates is as follows:

Employee Turnover	% of Total
Voluntary Turnover as a percent of workforce	4.9	%
Involuntary Turnover as a percent of workforce	0.9	%
Retirement as a percent of workforce	3.5	%
Total Turnover as a percent of workforce	9.3	%

Diversity, Equity and Inclusion

Diversity, equity and inclusion are critical to our future success. We strive to build and sustain a diverse workforce with a rich mix of differences, inclusive workplaces where each of us feel valued and connected, and receive equitable opportunities to grow and develop.

We have prioritized our Diversity, Equity & Inclusion, or DE&I, initiatives in 3 areas: increasing diverse representation, especially in positions of authority; promoting equitable opportunities to grow and develop; and establishing pathways for community and connection with others.

In 2021, AVANGRID became a member of Disability:IN, a leading nonprofit resource for business disability inclusion, and continued its active involvement with Paradigm for Parity and CEO Action for Diversity & Inclusion. These public memberships and involvement demonstrate our commitment to elevate the DE&I conversation with our peers, while creating effective change for individuals with varying abilities, increasing gender parity in senior operating roles, and supporting challenging, yet necessary, workplace conversations.

Over 90% of our lead-level employees completed 2 hours of self-guided DE&I and unconscious bias training in 2021, including a multi-day event attended by over 200 people leaders. Additionally, over 92% of executive participants had incentive compensation explicitly linked to increasing gender and racial diversity in succession plans.

Our growing community of Business Resource Groups, or BRGs, provide “safe-zones” where our employees can discuss relevant issues and celebrate different cultures, ethnicities, and identities. Over 10% of our employees are part of one of our seven BRGs, and in 2021, we welcomed two new BRGs – the AVANGRID Coalition for Asian & Pacific Americans, or ACAPA, and the Community for all Abilities and Resource for Excellence, or CARE. Our BRGs hosted over 25 events in 2021, promoting inclusive conversations and diverse thinking throughout the organization. As of December 31, 2021, the approximate demographic breakdowns of our workforce are as follows:

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Ethnicity	% of Total
All Employees	All		CT		MA		ME		NY		OR
% of Employees in State			24.5	%	2.6	%	16.8	%	42.7	%	5.2	%
American Indian or Alaska Native	0.4	%	0.1	%	0.5	%	0.8	%	0.3	%	0.3	%
Asian	2.7	%	4.6	%	2.1	%	1.4	%	1.9	%	6.8	%
Black or African American	5.8	%	13.3	%	1.6	%	0.9	%	5.1	%	1.0	%
Hispanic or Latino	6.9	%	14.0	%	4.2	%	1.9	%	4.2	%	6.5	%
Hawaiian Native or other Pacific Islander	0.1	%	0.0	%	0.0	%	0.0	%	0.0	%	0.5	%
Two or more races	1.3	%	1.5	%	0.5	%	1.4	%	1.1	%	1.8	%
White	76.8	%	63.3	%	82.7	%	90.1	%	83.2	%	65.7	%
Not reported	6.0	%	3.3	%	8.4	%	3.6	%	4.1	%	17.3	%
Senior Leadership	All		CT		MA		ME		NY		OR
% of Employees in State			31.8	%	5.5	%	15.3	%	17.4	%	17.7	%
American Indian or Alaska Native	0.3	%	—	%	—	%	—	%	—	%	—	%
Asian	2.4	%	2.9	%	—	%	—	%	1.8	%	3.4	%
Black or African American	2.8	%	5.8	%	—	%	—	%	3.5	%	1.7	%
Hispanic or Latino	8.0	%	15.4	%	5.6	%	6.0	%	7.0	%	—	%
Hawaiian Native or other Pacific Islander	—	%	—	%	—	%	—	%	—	%	—	%
Two or more races	2.1	%	2.9	%	—	%	4.0	%	—	%	1.7	%
White	71.6	%	64.4	%	66.7	%	76.0	%	73.7	%	74.1	%
Not reported	12.8	%	8.7	%	27.8	%	14.0	%	14.0	%	19.0	%

All Employees	All		CT		MA		ME		NY		OR
Female	27.4	%	29.8	%	29.8	%	30.2	%	27.4	%	29.1	%
Male	72.6	%	70.2	%	70.2	%	69.8	%	72.6	%	70.9	%

Senior Leadership	All		CT		MA		ME		NY		OR
Female	29.4	%	30.8	%	27.8	%	30.0	%	33.3	%	29.3	%
Male	70.6	%	69.2	%	72.2	%	70.0	%	66.7	%	70.7	%

Health and Safety

Safety is a core value at AVANGRID. Providing a safe and healthy workplace is our commitment to our employees, communities, customers, and investors. Daily emphasis on the importance of a safe workplace – and everyone’s role in supporting it – builds employee confidence, motivation, and productivity. A safe workplace encourages an environment where innovation can flourish. 100% of our leaders have a portion of their variable compensation tied directly to health and safety goals.

We continuously work to embed a safety-first culture across the company. In addition to ongoing safety training and awareness programs, we use Safety Excellence Awards and other recognition programs to recognize exemplary and proactive safety behavior. These programs, in addition to monthly leadership meetings dedicated to disseminating important safety updates while promoting a learning and improving safety culture, build critical skills for managers and supervisors to boost engagement for all employees. In 2021, we launched the Essential Controls Standard to strengthen safety performance and focus on reinforcing existing requirements, and expanded our “Good Catch” hazard recognition program, which recognizes employees for identifying a condition or situation that could have led to an incident.

A true culture of health and safety is dependent on not only a strong safety program, but also a program that focuses on employee well-being. Healthier employees are at lower risk of injury from industrial exposure and perform work more safely with lower rates of absenteeism. In 2021, well-being programming placed a strong emphasis on supporting employee mental health, with extensive resources offered including regular mental health webinars, mental health training for people managers, and online emotional well-being platforms to manage health and wellbeing, access discounts, and participate in activity challenges. In addition, we established a network of “mental health advocates,” a group of trained employees who volunteer their time to listen and provide guidance to others regarding available mental health resources. We also provided onsite

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prevention and risk reduction programs, such as early intervention programs, and onsite COVID-19 and influenza vaccination clinics. Our employees’ financial health is equally important, so we have deployed programs for financial education and advisory services.

AVANGRID has a dedicated COVID-19 cross-functional management team, which leads efforts to develop, implement and monitor mitigation and business continuity plans; track all relevant federal, state and local government guidelines, directives and regulations; develop and adopt work-from-home plans where possible; implement safe working protocols; assess appropriate return-to-office protocols; and provide critical updates via timely and transparent communications to all employees and key stakeholders. In response to the COVID-19 pandemic, we continue to provide benefits to our employees to cover the cost of COVID-19 testing, offer access to telehealth benefits, expand employee assistance and well-being programming, and provide supplemental paid leave for quarantined employees.

Employee Engagement

In 2021, AVANGRID continued listening to employees about areas of organizational strength and opportunities to improve via “The Loop”, our annual employee engagement survey.

A team of engagement leads representing a variety of functions, locations, and employees were responsible for promoting survey participation, assisting leaders in the analysis of survey data, and in implementing Action Plans to address opportunity areas. Action Plans were created at department and organizational levels, and progress was shared throughout the year to inform employees about how their feedback was being put into action.

In 2021, employees who were both engaged and enabled as measured through the survey remained stable at 47%, the same as compared to the previous year, with a 74% employee participation rate.

Growing our talent

We enable the personal and professional development of employees through on-demand skill building platforms, leadership programs, mentoring, technical and on-the-job training, community outreach opportunities, and tuition assistance.

During 2021, we enhanced our succession and talent management planning process to target the identification and development of key internal talent to meet future needs, with a particular focus on diverse representation. Our early career and internship programs continue to build a sustainable pipeline of in-demand and emerging skillsets. We also continued the evolution of our technical training programs by leveraging new technologies such as AR/VR and digital learning.

Rewards

Our compensation, benefits, and retirement programs are designed to attract and retain the right people to meet business and customer needs across a variety of markets and locations, and within the increasingly competitive context in which we operate.

The following principles guide our compensation philosophy:

1.Pay for Performance. We believe that our compensation programs should motivate higher performance among our employees, and compensation levels should broadly reflect the achievement of short-term performance objectives, and for key leaders, long-term performance objectives as well.

2.Competitive Pay. To support our need to recruit, retain and motivate our workforce, we aim to ensure that our compensation, in terms of structure and total amount, is competitive with that of comparable entities. We regularly review market data to obtain a general understanding of current compensation practices to ensure that compensation offered is reasonably market competitive, including for the applicable geographic location.

3.Executives: Long-Term Focus on Total Direct Compensation. The compensation program for our executive officers is designed to mitigate excessive short-term decision making and risk taking, while encouraging the attainment of strategic goals through the inclusion of long-term incentives. We regularly evaluate the effectiveness and competitiveness of our executive compensation and benefit programs and benchmark ourselves against our peers within our industry.

Additional Rewards programs for all employees include:

•Comprehensive health, dental and vision insurance, paid and unpaid leave, retirement savings plans and life insurance and disability plans.

•A variety of value-added benefits and programs that allow employees to make choices that meet their individual needs, including flexible time-off, telemedicine, adoption and surrogacy assistance, back-up child and elder care support, and

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physical, mental and financial wellness and wellness programs, tuition reimbursement, and additional services such as legal assistance and pet insurance.

•Charitable giving programs that offer both a cash match and direct donations for volunteer hours given by employees.

For information on the risks related to our human capital resources, see Item 1A - Risk Factors.

Available Information

Copies of our Annual Reports on Form 10-K, Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to these reports filed with the SEC may be requested, viewed or downloaded on-line, free of charge, on our website www.avangrid.com. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at 180 Marsh Hill Road, Orange, Connecticut, 06477.

Information about AVANGRID’s environmental, social and governance performance and sustainability reporting is also available on our website www.avangrid.com. under the heading “Sustainability.” Information contained on our website is not incorporated herein.

The Company may use its website and/or social media outlets, such as Facebook and Twitter, as distribution channels of material company information. Financial and other important information regarding the Company is routinely posted on and accessible through the Company’s website at www.avangrid.com, its Facebook page at https://www.facebook.com/Avangrid/, its Twitter account @AVANGRID, and its LinkedIn page at www.linkedin.com/company/avangrid. The information contained on these sites is not incorporated by reference into this Form 10-K. In addition, you may automatically receive email alerts and other information about the Company when you enroll your email address by visiting the Investor Relations section of www.avangrid.com.

Item 1A. Risk Factors

PNMR Merger Risk Factors

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

Completion of the proposed Merger is subject to the satisfaction or waiver of a number of conditions as set forth in the Merger Agreement, including certain regulatory approvals and other customary closing conditions. There can be no assurance that the conditions to completion of the proposed Merger will be satisfied or waived or that other events will not intervene to delay or result in the failure to close the proposed Merger. In addition, each of AVANGRID and PNMR may unilaterally terminate the Merger Agreement under certain circumstances set forth in the Merger Agreement and the Amendment, and AVANGRID and PNMR may agree at any time to terminate the Merger Agreement, even though PNMR's shareholders have already approved the proposed Merger and the other transactions contemplated by the Merger Agreement. The Merger Agreement provides for certain customary termination rights. If we were to terminate the Merger Agreement under certain circumstances, we could incur significant costs (including, without limitation, the payment of the termination fee and out-of-pocket fees and expenses).

AVANGRID and PNMR may be unable to obtain, extend or reapply for the regulatory approvals required to complete the proposed Merger.

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

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

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

The announcement and pendency of the proposed Merger could disrupt AVANGRID’s businesses, and uncertainty about the effect of the proposed Merger may have an adverse effect on AVANGRID or the combined company following the proposed Merger. AVANGRID’s employees may experience uncertainty regarding their roles after the proposed Merger, for example, employees may depart either before or after the completion of the proposed Merger because of such uncertainty and issues relating to the difficulty of coordination or a desire not to remain following the proposed Merger; and the pendency of the proposed Merger may adversely affect AVANGRID’s ability to retain, recruit and motivate key personnel. Additionally, the attention of AVANGRID’s management may be directed towards the completion of the proposed Merger including obtaining regulatory approvals and other transaction-related considerations and may be diverted from the day-to-day business operations of AVANGRID and matters related to the proposed Merger may require commitments of time and resources that could otherwise have been devoted to other opportunities that might have been beneficial to AVANGRID. Additionally, the Merger Agreement requires AVANGRID to obtain PNMR’s consent prior to taking certain specified actions while the proposed Merger is pending. These restrictions may prevent AVANGRID and PNMR from pursuing otherwise attractive business opportunities and executing certain of its business strategies prior to the consummation of the proposed Merger. Further, the proposed Merger may give rise to potential liabilities, including as a result of pending and future shareholder lawsuits relating to the proposed Merger. Any of these matters could adversely affect the businesses of, or harm the results of operations, financial condition or cash flows of AVANGRID and the market value of AVANGRID common stock and debt securities.

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

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

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

AVANGRID and PNMR have operated and, until the consummation of the proposed Merger will continue to operate, independently. Coordinating certain aspects of the operations and personnel of PNMR with AVANGRID after the consummation of the proposed Merger will involve complex operational, technological and personnel-related challenges, which may be made more difficult in light of the COVID-19 pandemic. This process will be time-consuming and expensive, may disrupt the businesses of either or both of the companies and may reduce the growth opportunities sought from the Merger. The potential difficulties, and resulting costs and delays, include examples such as:

•managing a larger combined company;

•coordinating corporate and administrative infrastructures;

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

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

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

•a deterioration of credit ratings.

While AVANGRID can refuse to consummate the proposed Merger if there is a material adverse effect (as defined in the Merger Agreement) affecting PNMR prior to the consummation of the proposed Merger, certain types of changes do not permit AVANGRID to refuse to consummate the proposed Merger, even if such changes would have a material adverse effect on

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PNMR. If adverse changes occur but AVANGRID must still consummate the proposed Merger, the market price of AVANGRID common stock may suffer. There can be no assurance that, if the proposed Merger is not consummated, these risks will not materialize and will not materially adversely affect the business and financial results of AVANGRID.

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

The success of the Merger will depend, in part, on the ability of PNMR to successfully execute its business strategy, including delivering electricity in a safe and reliable manner, minimizing service interruptions and investing in its transmission and distribution infrastructure to maintain its system, serve its growing customer base with a modernized grid and support energy production. These objectives are capital intensive and subject to substantial regulation by federal, state and local regulatory agencies and PNMR's business, results of operations and prospects may be adversely affected by legislative or regulatory changes, as well as liability under, or any future inability to comply with, existing or future regulations or requirements. If PNMR is not able to achieve these objectives, is not able to achieve these objectives on a timely basis, or otherwise fails to perform in accordance with AVANGRID’s expectations, the anticipated benefits of the Merger may not be realized fully or at all, and the Merger may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID common stock and debt securities.

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

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

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

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

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

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

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obligations resulting from this additional indebtedness could have a material adverse effect on the results of operations, financial condition and prospects of AVANGRID.

AVANGRID’s increased indebtedness could:

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

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

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

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

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

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

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

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

The Merger will increase our goodwill and other intangible assets.

Following the Merger, we will have a significant amount of goodwill and other intangible assets on our consolidated financial statements that could be subject to impairment based upon future adverse changes in our business or prospects. The impairment of any goodwill and other intangible assets may have a negative impact on our consolidated results of operations.

Any litigation filed against PNMR and the members of the PNMR board of directors could result in the payment of damages following completion of the Merger or prevent or delay completion of the Merger.

In connection with the Merger, purported shareholders of PNMR have filed lawsuits against PNMR and the members of the PNMR board of directors under the federal securities laws, challenging the adequacy of the disclosures made in PNMR’s proxy statement in connection with the Merger or otherwise.

The outcome of any such litigation is uncertain. If a dismissal is not granted or a settlement is not reached, the lawsuits could prevent or delay completion of the Merger and result in substantial costs to AVANGRID, including any costs associated with indemnification of PNMR's directors and officers. Additional lawsuits may be filed against PNMR or the directors and officers of PNMR in connection with the Merger. The defense or settlement of any lawsuit or claim that remains unresolved at the time the Merger is consummated may adversely affect the combined company’s business, financial condition, results of operations and cash flows.

The impact of severe weather conditions, including brown-outs and black-outs, could negatively affect PNMR.

PNMR has large networks of electric transmission and distribution facilities. Weather conditions in the U.S. Southwest region and Texas vary and could contribute to severe weather conditions, such as wildfires or the recent severe winter weather

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events in Texas or result in brown-outs or black-outs, in or near PNMR’s service territories. While PNMR may take certain proactive steps to mitigate the risks caused by severe weather conditions, brown-outs or black-outs, such risks are always present and PNMR could be held liable for damages incurred as a result of severe weather conditions, brown-outs or black-outs, or as a result of wildfires caused, or allegedly caused, by their transmission and distribution systems. In addition, wildfires could cause damage to PNMR’s assets that could result in loss of service to customers or make it difficult to supply power in sufficient quantities to meet customer needs. These events could adversely affect PNMR and may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

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

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

The costs of decommissioning any nuclear or fossil power plant are substantial. PNMR is responsible for all decommissioning obligations related to its entire proportionate interest in Palo Verde Nuclear Generating Station, or PVNGS, San Juan Generating Station, or SJGS, and Four Corners Power Plant, or FCPP, including portions under lease both during and after termination of the leases, other than amounts after the consummation of PNMR’s sale of its interest in the Four Corners Power Plant (assuming that transaction closes pursuant to the purchase and sale agreement on December 31, 2024). A delay or termination of the sale of PNMR's interest in the FCPP could have a negative impact on AVAGRID's sustainability reputation.

PNMR maintains trust funds and escrow accounts designed to provide adequate financial resources for decommissioning PVNGS, SJGS and FCPP and for reclamation of the coal mines serving SJGS and FCPP at the end of their expected lives. However, because the funds and accounts grow over time to meet decommissioning and reclamation responsibilities, if the PVNGS, SJGS or FCPP units are decommissioned before their planned dates or the coal mines are shut down sooner than expected, these funds may prove to be insufficient, which may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

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

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

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

In the event of noncompliance with its requirements, the NRC has the authority to impose a progressively increasing inspection regime that could ultimately result in the shutdown of a unit, civil penalties or both, depending upon the NRC’s assessment of the severity of the situation, until compliance is achieved. Increased costs resulting from penalties, a heightened level of scrutiny, and/or implementation of plans to achieve compliance with NRC requirements could adversely affect the financial condition, results of operations, and cash flows of PNMR. Although PNMR has no reason to anticipate a serious

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nuclear incident at PVNGS, if an incident did occur, it could materially and adversely affect PNMR and may materially adversely affect the results of operations, financial condition and prospects of the combined company and, consequently, the market value of AVANGRID’s common stock and debt securities.

Strategic Risk Factors

The success of AVANGRID depends on achieving our strategic objectives, which may be through acquisitions, joint ventures, dispositions and restructurings and failure to achieve these objectives could adversely affect our business, financial condition and prospects.

We are continuously reviewing the alternatives available to ensure that we meet our strategic objectives, which include, among other things, acquisitions, joint ventures, dispositions and restructuring. With respect to potential acquisitions, joint ventures and restructuring activities, we may not achieve expected returns, cost savings and other benefits as a result of various factors including integration and collaboration challenges such as personnel and technology. We also may participate in joint ventures with other companies or enterprises in various markets, including joint ventures where we may have a lesser degree of control over the business operations, which may expose us to additional operational, financial, legal or compliance risks. We also continue to evaluate the potential disposition of assets and businesses that may no longer help us meet our objectives or sell a stake of these assets as a way of maximizing the value of AVANGRID. When we decide to sell assets or a business, we may encounter difficulty in finding buyers or executing alternative exit strategies on acceptable terms in a timely manner, which could delay the accomplishment of our strategic objectives or be on terms less favorable than we anticipated.

We expect to invest in development opportunities in all segments of AVANGRID, but such opportunities may not be successful, projects may not commence operation as scheduled and/or within budget or at all, which could have an adverse effect on our business, financial condition and prospects.

We are pursuing additional development investment opportunities related to all segments of AVANGRID with a particular focus on additional opportunities in electric transmission, renewable energy generation and interconnections to generating resources. The development, construction and expansion of such projects involve numerous risks. Various factors could result in increased costs or result in delays or cancellation of these projects. Risks include regulatory approval processes, permitting, new legislation, citizen referendums or ballot initiatives, economic events, foreign currency risk, environmental and community concerns, negative publicity, design and siting issues, difficulties in obtaining required rights of way, difficulties in securing equipment orders, construction delays and cost overruns, including delays in equipment deliveries, severe weather, competition from incumbent facilities and other entities, and actions of strategic partners. There may be delays or unexpected developments in completing current and future construction projects. For example, we have capitalized approximately $546 million and expect to invest approximately $1.2 billion in total in our NECEC project. The outcome of ongoing legal proceedings, cost overruns and construction delays could impact these investments and have an adverse effect on the success of the NECEC project and our financial condition and prospects. While most of Renewables’ construction projects are constructed under fixed-price and fixed-schedule contracts with construction and equipment suppliers, these contracts provide for limitations on the liability of these contractors to pay liquidated damages for cost overruns and construction delays. These circumstances could prevent Renewables’ construction projects from commencing operations or from meeting original expectations about how much electricity it will generate or the returns it will achieve. In addition, for Renewables’ projects that are subject to PPAs, substantial delays could cause defaults under the PPAs, which generally require the completion of project construction by a certain date at specified performance levels. A delay resulting in a wind project failing to qualify for federal PTCs or ITCs could result in losses that would be substantially greater than the amount of liquidated damages paid to Renewables.

AVANGRID may be materially adversely affected by negative publicity related to or in connection with the proposed PNMR Merger, the NECEC transmission project, government-controlled power initiatives and in connection with other matters.

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

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adverse effect on AVANGRID’s business, financial condition, results of operations and cash flows and the market value of AVANGRID common stock and debt securities.

Regulatory and Legislative Risk Factors

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

The operations of AVANGRID are subject to, and influenced by, complex and comprehensive federal, state and local regulation and legislation, including regulations promulgated by state utility commissions and the FERC. This extensive regulatory and legislative framework regulates our ability to own and operate utilities, the industries in which our subsidiaries operate, our business segments, rates for our products and services, financings, capital structures, cost structures, construction, environmental obligations, development and operation of our facilities, acquisition, disposal, depreciation and amortization of facilities and other assets, service reliability, customer service requirements, hedging, derivatives transactions and commodities trading. For example, in Maine efforts to place a citizen’s referendum on the ballot affecting the ownership and operations of electric and gas utilities continue and proposed legislation intended to reform oversight of Maine utilities by requiring the MPUC to establish minimum standards for service subject to administrative penalties and forced divestiture.

The federal, state and local political and economic environment has had, and may in the future have, an adverse effect on regulatory decisions with negative consequences for AVANGRID. These decisions may require AVANGRID to cancel, reduce, or delay planned development activities or other planned capital expenditures or investments or otherwise incur costs that we may not be able to recover through rates. We are unable to predict future legislative or regulatory changes, initiatives or interpretations, and there can be no assurance that we will be able to respond adequately or sufficiently quickly to such actions.

AVANGRID is subject to the jurisdiction of various regulatory agencies including, but not limited to, the FERC, the NERC, the CFTC, the DOE and the EPA. Further, Networks’ regulated utilities are subject to the jurisdiction of the NYPSC, the MPUC, the New York State Department of Environmental Conservation, the Maine Department of Environmental Protection, the PURA, the CSC, the DEEP and the DPU. These regulatory agencies cover a wide range of business activities, including, among other items the retail and wholesale rates for electric energy, the transmission and distribution of energy, the setting of tariffs and rates including cost recovery clauses, procurement of electricity for Networks’ customers, and certain aspects of the siting, construction and transmission and distribution systems. These regulatory agencies have the authority to initiate associated investigations or enforcement actions or impose penalties or disallowances, which could be substantial. Certain regulatory agencies have the authority to review and disallow recovery of costs that they consider excessive or imprudently incurred and to determine the level of return that AVANGRID is permitted to earn on invested capital.

The regulatory process, which may be adversely affected by the political, regulatory, and economic environment in the states we operate in may limit our earnings and does not provide any assurance with respect to the achievement of authorized or other earnings levels. The disallowance of the recovery of costs incurred by us or a decrease in the rate of return that we are permitted to earn on our invested capital could have a material adverse effect on our financial condition. In addition, certain of these regulatory agencies also have the authority to audit the management and operations of AVANGRID and its subsidiaries, which could result in operational changes or adversely impact our financial condition. Such audits and post-audit work require the attention of our management and employees and may divert their attention from other regulatory, operational or financial matters.

AVANGRID’s regulated utility operations may not be able to recover costs in a timely manner or at all or obtain a return on certain assets or invested capital through base rates, cost recovery clauses, other regulatory mechanisms or otherwise.

Our regulated utilities are subject to periodic review of their rates and the retail rates charged to their customers through base rates and cost recovery clauses which are subject to the jurisdiction of the NYPSC, MPUC, PURA and DPU, as applicable. New rate proceedings can be initiated by the utilities or the regulators and are subject to review, modification and final authorization by the regulators. Networks’ regulated utilities’ business rate plans approved by state utility regulators limit the rates Networks’ regulated utilities can charge their customers. The rates are generally designed for, but do not guarantee, the recovery of Networks’ regulated utilities’ respective cost of service and the opportunity to earn a reasonable rate of Return on Equity, or ROE. Actual costs may increase due to inflation, supply chain constraints, or other factors and exceed levels provided for such costs in the rate plans for Networks’ regulated utilities. Utility regulators can initiate proceedings to prohibit Networks’ regulated utilities from recovering from their customers the cost of service that the regulators determine to have been imprudently incurred, including service and management company charges. Networks’ regulated utilities defer for future recovery certain costs as permitted by the regulators. Networks’ regulated subsidiaries could be denied recovery of certain costs, or deferred recovery pending the next general rate case, including denials or deferrals related to major storm costs and construction expenditures. In some instances, denial of recovery may cause the regulated subsidiaries to record an impairment

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of assets. If Networks’ regulated utilities’ costs are not fully and timely recovered through the rates ultimately approved by regulators, our financial condition could be adversely affected.

Current electric and gas rate plans of Networks’ regulated utilities include revenue decoupling mechanisms, or RDMs, and the provisions for the recovery of energy costs, including reconciliation of the actual amount paid by such regulated utilities. There is no guarantee that such decoupling mechanisms or recovery and reconciliation mechanism will apply in future rate proceedings.

There are pending challenges at the FERC against New England transmission owners (including UI and CMP) seeking to lower the ROE that these transmission owners are allowed to receive for wholesale transmission service pursuant to the ISO-NE Open Access Transmission Tariff. Reductions to the ROE adversely impact the revenues that Networks’ regulated utilities receive from wholesale transmission customers and could have a material effect on our financial condition.

Changes in regulatory and/or legislative policy could negatively impact Networks’ transmission planning and cost allocation.

The existing FERC-approved ISO-NE transmission tariff allocates the costs of transmission facilities that provide regional benefits to all customers of participating transmission-owning utilities in New England. FERC is currently reviewing its policies regarding transmission planning, cost allocation and generation interconnection and could require substantial changes in RTO and transmission owner tariffs. Changes in RTO tariffs, transmission owners’ agreements or legislative policy, or implementation of these new FERC planning rules, could adversely affect our transmission planning and financial condition.

AVANGRID’s operating subsidiaries’ purchases and sales of energy commodities and related transportation and services expose us to potential regulatory risks that could have a material adverse effect on our business, and financial condition.

Under the EPAct 2005 and the Dodd-Frank Act, AVANGRID is subject to enhanced FERC and CFTC statutory authority to monitor certain segments of the physical and financial energy commodities markets. Under these laws, the FERC and CFTC have promulgated regulations that have increased compliance costs and imposed reporting requirements on AVANGRID. These regulations require our operating subsidiaries to comply with certain margin requirements for our over-the-counter derivative contracts with certain CFTC- or SEC-registered entities that require us to post cash collateral with respect to swap transactions, that could potentially have an adverse effect on our liquidity or our ability to hedge commodity or interest rate risks.

With regard to the physical purchases and sales of energy commodities, the physical trading of energy commodities and any related transportation and/or hedging activities that some of our operating subsidiaries undertake, our operating subsidiaries are required to follow market-related regulations and certain reporting and other requirements enforced by the FERC, the CFTC and the SEC. Additionally, to the extent that operating subsidiaries enter into transportation contracts with natural gas pipelines or transmission contracts with electricity transmission providers that are subject to FERC regulation, the operating subsidiaries are subject to FERC requirements related to the use of such transportation or transmission capacity. Any failure on the part of our operating subsidiaries to comply with the regulations and policies of the FERC, the CFTC or the SEC relating to the physical or financial trading and sales of natural gas or other energy commodities, transportation or transmission of these energy commodities or trading or hedging of these commodities could result in the imposition of significant civil and criminal penalties, which could have a material adverse effect on our business.

The increased cost of purchasing natural gas during periods in which natural gas prices have increased significantly could adversely impact our earnings and cash flow.

Our regulated utilities are permitted to recover the costs of natural gas purchased for customers. Under the regulatory body-approved gas cost recovery pricing mechanisms, the gas commodity charge portion of gas rates charged to customers may be adjusted upward on a periodic basis. If the cost of purchasing natural gas increases and Networks’ regulated natural gas utilities are unable to recover these costs from its customers immediately, or at all, Networks may incur increased costs associated with higher working capital requirements and/or realize increased costs. In addition, any increases in the cost of purchasing natural gas may result in higher customer bad debt expense for uncollectible accounts and reduced sales volume and related margins due to lower customer consumption.

Climate related proceedings and legislation may result in the alteration of the public utility model in the states we operate in and could materially and adversely impact our business and operations.

Clean energy and emission reduction legislation, proceedings, or executive orders have been issued within New York, Maine, Connecticut and Massachusetts that, among other things, set renewable energy and carbon emission goals and create incentive programs for energy efficiency and renewable energy programs. Additionally, new legislation can require significant change to the natural gas portion of AVANGRID including reduction in usage and restriction of the expansion of natural gas

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within our territories. We are unable to predict the impact these law and actions may have on the operations of our subsidiaries in New York, Maine, Connecticut and Massachusetts which could have an adverse effect on our business and financial condition.

Renewables relies in part on governmental policies that support utility-scale renewable energy. Any reductions to, or the elimination of, these governmental mandates and incentives or the imposition of additional taxes or other assessments on renewable energy, could adversely impact our growth prospects, our business and financial condition.

Renewables relies, in part, upon government policies that support the development and operation of utility-scale renewable energy projects and enhance the economic feasibility of these projects. The federal government and many state and local jurisdictions have policies or other mechanisms in place, such as tax incentives or Renewable Portfolio Standards, or RPS, that support the sale of energy from utility-scale renewable energy facilities. Federal, state and local governments may review their policies and mechanisms that support renewable energy and take actions that would make them less conducive to the development or operation of renewable energy facilities. Any reductions to, or the elimination of, governmental policies or other mechanisms that support renewable energy or the imposition of additional taxes or other assessments on renewable energy, could result in, among other items, the lack of a satisfactory market for new development, Renewables abandoning the development of new projects, a loss of Renewables’ investments in the projects and reduced project returns.

New tariffs imposed on imported goods may increase capital expense in projects and negatively impact expected returns.

Changes in tariffs may affect the final cost of a significant portion of capital expenses in projects, with renewable projects being more exposed. Tariffs have been imposed in the recent years to imports of solar panels, aluminum and steel, among other goods or raw materials. Depending on the timing and contractual terms, tariff changes may have adverse impacts to the buyer of these goods which could affect expected returns on approved projects.

Operational, Environmental, Social and Legal Risk Factors

AVANGRID is subject to numerous environmental laws, regulations and other standards, including rules and regulations with respect to climate change, which could result in increased capital expenditures, operating costs and various liabilities, and could require us to cancel or delay planned projects or limit or eliminate certain operations, all of which could have an adverse effect on our business and financial condition.

AVANGRID is subject to environmental laws and regulations, including, but not limited to, extensive federal, state and local environmental statutes, rules and regulations relating to air quality, water quality and usage, climate change, emissions of greenhouse gases, waste management, hazardous wastes, wildlife mortality and habitat protection, historical artifact preservation, natural resources and health and safety that could, among other things, prevent or delay the development of power generation, power or natural gas transmission, or other infrastructure projects, restrict the output of some existing facilities, limit the availability and use of some fuels required for the production of electricity, require additional pollution control equipment, and otherwise increase costs, increase capital expenditures and limit or eliminate certain operations. There are significant costs associated with compliance with these environmental statutes, rules and regulations, and those costs could be even more significant in the future as a result of new legislation. Violations of current or future laws, rules, regulations or other standards could expose our subsidiaries to regulatory and legal proceedings, disputes with, and legal challenges by, third parties, and potentially significant civil fines, criminal penalties and other sanctions.

Security breaches, acts of war or terrorism, grid disturbances or unauthorized access could negatively impact our business, financial condition and reputation.

Cyber breaches, acts of war or terrorism or grid disturbances resulting from internal or external sources could target our facilities or our information technology systems. In the ordinary course of business, we maintain sensitive customer, employee, financial and system operating information and are required by various laws to safeguard this information. Cyber or physical security intrusions could potentially lead to disabling damage to our facilities or to theft and the release of critical operating information or confidential customer or employee information, which could adversely affect our operations and/or reputation, and could result in significant costs, fines and litigation. Additionally, because our generation and transmission facilities are part of an interconnected regional grid, we face the risk of blackout due to a disruption on a neighboring interconnected system. As threats evolve and grow increasingly more sophisticated, we may incur significant costs to upgrade or enhance our security measures to protect against such risks and we may face difficulties in fully anticipating or implementing adequate preventive measures or mitigating potential harms.

A physical attack on our infrastructure could interfere with our normal business operations and affect our ability to control our transmission and distribution assets. A physical security intrusion could potentially lead to theft and the release of critical operating information and could result in significant costs, fines and litigation. Theft, vandalism or damages to our facilities and equipment can cause significant disruption to operations and can lead to operating losses.

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The impact of COVID-19 on business and economic conditions could negatively affect our business, results of operations, financial condition, cash flows and the trading value of our securities.

The scale and scope of the COVID-19 pandemic and the impact on the economy, labor, and financial markets could adversely affect our business, financial performance and results of operations. Given the uncertain scope and duration of the COVID-19 outbreak and its potential effects on our business, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition in the future. While the situation surrounding COVID-19 remains fluid and its potential impact on AVANGRID is difficult to predict, the continued spread of the virus, vaccination rates and actions undertaken by national, regional, and local governments and health officials to contain COVID-19 or treat its effects could: impact customer demand for electricity particularly from businesses, commercial and industrial customers; cause us to experience an increase in costs as a result of our emergency measures, delayed payments from our customers and uncollectible accounts; cause delays and disruptions in the availability and timely delivery of materials and components used in our operations; cause delays and disruptions in the supply chain resulting in disruptions in the commercial operation dates of certain projects and impacting qualification criteria for certain tax credits and potential delay damages in our power purchase agreements; cause deterioration in credit quality of our counterparties, contractors or retail customers that could result in credit losses; cause impairment of goodwill or long-lived assets and impact our ability to develop, construct and operate facilities; result in our inability to meet the requirements of the covenants in our existing credit facilities, including covenants regarding the ratio of indebtedness to total capitalization; cause a deterioration in our financial metrics or the business environment that impacts our credit ratings; cause a delay in the permitting process of certain development projects, affecting the timing of final investment decisions and start of construction dates; cause employee turnover, labor shortages, and extended remote work, which could harm productivity, increase cybersecurity risk, strain our business continuity plans, give rise to claims by employees and otherwise negatively impact our business.

If Networks’ electricity and natural gas transmission, transportation and distribution systems do not operate as expected or are not available for operation, they could require unplanned expenditures, including the maintenance, replacement, and refurbishment of Networks’ facilities, which could adversely affect our business and financial condition.

Networks’ ability to operate and have available its electricity and natural gas transmission, transportation and distribution systems is critical to the financial performance of AVANGRID. The ongoing operation of Networks’ facilities involves risks customary to the electric and natural gas industry that include the breakdown, failure, loss of use or destruction of Networks’ facilities, equipment or processes or the facilities, equipment or processes of third parties due to natural disasters, war or acts of terrorism, operational and safety performance below expected levels, errors in the operation or maintenance of these facilities and the inability to transport electricity or natural gas to customers in an efficient manner. Any unexpected failure, including failure associated with breakdowns, forced outages or any unanticipated capital expenditures, accident, failure of major equipment, shortage of or inability to acquire critical equipment, replacement or spare parts could result in reduced profitability, impacted cash flows, harm to our reputation or result in regulatory penalties.

Storing, transporting and distributing natural gas involves inherent risks that could cause us to incur significant costs that could adversely affect our business, financial condition and reputation.

There are inherent hazards and operational risks in gas distribution activities, such as leaks, explosions and mechanical problems that could cause the loss of human life, significant damage to property, environmental pollution and impairment of operations. The location of pipelines and storage facilities near populated areas could increase the level of damages resulting from these risks. These incidents may subject us to litigation and administrative proceedings that could result in substantial monetary judgments, fines or penalties and damage to our reputation.

If Renewables’ equipment is not available for operation, Renewables projects’ electricity generation and the revenue generated from its projects may fall below expectations and adversely affect our financial condition and reputation.

The revenues generated by Renewables’ facilities depend upon the ability to maintain the working order of its projects. A natural disaster, severe weather, accident, failure of major equipment, failure of equipment supplier or shortage of or acquire critical replacement of spare parts not held in inventory or maintenance services, including the failure of interconnection to available electricity transmission or distribution networks, could damage or require Renewables to shut down its turbines, panels or related equipment and facilities, leading to decreases in electricity generation levels and revenues.

Renewables’ ability to generate revenue from renewable energy facilities depends on interconnecting utility and/or RTO rules, policies, procedures and FERC tariffs and market conditions that do not present restrictions to renewable project operations which could adversely impact our operations and financial condition.

If a transmission network connected to one or more generating facilities experiences outages or curtailments caused by interconnecting utility and/or RTO, the affected projects may lose revenue. In addition, certain Renewables’ generation facilities have agreements that may allow for economic curtailment by the off-taker, which could negatively impact revenues.

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Furthermore, economic congestion on the transmission grid (for instance, a negative price difference between the location where power is put on the grid by a project and the location where power is taken off the grid by the project’s customer) in certain of the bulk power markets in which Renewables operates may occur and its businesses may be responsible for those congestion costs. Similarly, negative congestion costs may require that the projects either not participate in the energy markets or bid and clear at negative prices which may require the projects to pay money to operate each hour in which prices are negative. If such businesses were liable for such congestion costs or if the projects are required to pay money to operate in any given hour when prices are negative, then our financial results could be adversely affected. Additionally, we are obligated to pay the FERC Tariff price, which can be adjusted from time to time, for Renewables’ facilities interconnection agreements even if the project has been curtailed.

AVANGRID’s subsidiaries do not own all the property and other sites on which their projects are located and our rights may be subordinate to the rights of lienholders and leaseholders, which could have an adverse effect on their business and financial condition.

Existing and future projects may be located on property on other sites occupied under long-term easements, leases and rights of way. The ownership interests in the property on other sites subject to these easements, leases and rights of way may be subject to mortgages securing loans or other liens and other easements, lease rights and rights of way of third parties that were created previously. As a result, some of these real property rights may be subordinate to the rights of these third parties, and the rights of our operating subsidiaries to use the property on other sites on which their projects are, or will be, located and their projects’ rights to such easements, leases and rights of way could be lost or curtailed.

AVANGRID and our subsidiaries face risks of strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms which could have an adverse effect on our business and financial condition.

The majority of employees at Networks’ facilities are subject to collective bargaining agreements with various unions. Unionization activities, including votes for union certification, could occur among non-union employees. If union employees strike, participate in a work stoppage or slowdown or engage in other forms of labor strike or disruption, our subsidiaries could experience reduced power generation or outages if replacement labor is not procured. The ability to procure such replacement labor or the ability to negotiate future collective bargaining agreements on commercially reasonable terms is uncertain.

Advances in technology and rate design initiatives could impair or eliminate AVANGRID’s competitive advantage or could result in customer defection, which could have an adverse effect on our growth prospects, business and financial condition.

Legislative and regulatory initiatives designed to reduce greenhouse gas emissions or limit the effects of global warming and overall climate change has increased the development of new technologies for renewable energy, energy efficiency and investment to make those technologies more efficient and cost effective. There is a potential that new technology or rate design incentives could adversely affect the demand for services of our regulated subsidiaries thus impacting our revenues, such as distributed generation. Similarly, future investments in Networks could be impacted if adequate rate making does not fully contemplate the characteristics of an integrated reliable grid from a unified perspective, regardless of customer disconnection. The interoperability, integration and standard connection of these distributed energy devices and systems could place a burden on the system of Networks’ operating subsidiaries, without adequately compensating them. The technology and techniques used in the production of electricity from renewable sources are constantly evolving and becoming more complex. In order to maintain its competitiveness and expand its business, Renewables must adjust to changes in technology effectively and in a timely manner, which could impact our cash flow and/or reduce our profitability.

Business and Market Risk Factors

AVANGRID’s operations and power production may fall below expectations due to the impact of natural events, which could adversely affect our financial condition and reputation.

Weather conditions influence the supply and demand for electricity, natural gas and other fuels and affect the price of energy and energy-related commodities. Severe weather can result in power outages, bodily injury and property damage or affect the availability of fuel and water. Many of our facilities could be at greater risk of damage should climate change produce unusual variations in temperature and weather patterns, resulting in more intense, frequent and extreme weather events and conditions.

Recoverability of additional costs associated with restoration and/or repair of regulated utilities facilities is defined within their respective rate decision. Regulatory agencies have the authority to review and disallow recovery of costs that they consider excessive or imprudently incurred. Reliability metrics may be negatively affected resulting in a potential negative rate adjustment or other imposed penalty. Our regulated utilities are subject to adverse publicity focused on the reliability of their distribution services and the speed with which they are able to respond to electric outages, natural gas leaks and similar

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interruptions caused by storm damage or other unanticipated events. Adverse publicity of this nature could harm our reputations and the reputations of our subsidiaries. Renewables can incur damage to wind or solar equipment, either through natural events such as lightning strikes that damage blades or in-ground electrical systems used to collect electricity from turbines or panels; or may experience production shut-downs or delayed restoration of production during extreme weather conditions resulting from, among other things, icing on the blades or restricted access to sites.

If weather conditions are unfavorable or below production forecasts, Renewables projects’ electricity generation and the revenue generated from its projects may fall below expectations and have an adverse effect on financial condition.

Changing weather patterns or lower than expected wind or solar resource could cause reductions in electricity generation at Renewables’ projects, which could negatively affect revenues. These events could vary production levels significantly from period to period, depending on the level of available resources. To the extent that resources are not available at planned levels, the financial results from these facilities may be less than expected. Changing weather patterns could also degrade equipment, components, and/or shorten interconnection and transmission facilities’ useful lives or increase maintenance costs.

Lower prices for other fuel sources may reduce the demand for wind and solar energy development, which could adversely affect Renewables’ growth prospects and financial condition.

Wind and solar energy demand is affected by the price and availability of other fuels, including nuclear, coal, natural gas and oil, as well as other sources of renewable energy. To the extent renewable energy, particularly wind and solar, becomes less cost-competitive due to reduced government targets, increases in the costs, new regulations, incentives that favor other forms of energy, cheaper alternatives or otherwise, demand for renewable energy could decrease.

There are a limited number of purchasers of utility-scale quantities of electricity, which exposes Renewables’ utility-scale projects to additional risk that could have an adverse effect on its business.

Since the transmission and distribution of electricity is highly concentrated in most jurisdictions, there are a limited number of possible purchasers for utility-scale quantities of electricity in a given geographic location, including transmission grid operators, state and investor-owned power companies, public utility districts and cooperatives. As a result, there is a concentrated pool of potential buyers for electricity generated by Renewables’ businesses, which may restrict our ability to negotiate favorable terms under new PPAs and could impact our ability to find new customers for the electricity generated by our generation facilities should this become necessary. Renewables’ PPA portfolio is mostly contracted with low risk regulated utility companies. In the past few years, there has been increased participation from commercial and industrial customers. The higher long-term business risk profile of these companies results in increased credit risk. Furthermore, if the financial condition of these utilities and/or power purchasers deteriorated or the RPS programs, climate change programs or other regulations to which they are currently subject and that compel them to source renewable energy supplies change, demand for electricity produced by Renewables’ businesses could be negatively impacted.

The benefits of any warranties provided by the suppliers of equipment for Networks and Renewables’ projects may be limited by the ability of a supplier to satisfy its warranty obligations, or if the term of the warranty has expired or has liability limits which could have an adverse effect on our business and financial condition.

Networks and Renewables expect to benefit from various warranties, including product quality and performance warranties, provided by suppliers in connection with the purchase of equipment by our operating subsidiaries. The suppliers may fail to fulfill their warranty obligations, or the warranty may not be sufficient to compensate for all losses or cover a particular defect. In addition, these warranties generally expire within two to five years after the date of equipment delivery or commissioning and are subject to liability limits. If installation is delayed, the operating subsidiaries may lose all or a portion of the benefit of warranty.

Renewables’ revenue may be reduced upon expiration or early termination of PPAs if the market price of electricity decreases and Renewables is otherwise unable to negotiate favorable pricing terms which could have a negative effect on our business and financial condition.

Renewables’ PPA portfolio primarily has fixed or otherwise predetermined electricity prices for the life of each PPA. A decrease in the market price of electricity could result in a decrease in revenues upon expiry or extension of a PPA. The majority of Renewables’ energy generation projects become merchant upon the expiration of a PPA and are subject to market risks unless Renewables can negotiate an extension or replacement contract. If Renewables is not able to secure a replacement contract with equivalent terms and conditions or otherwise obtain prices that permit operation of the related facility on a profitable basis, the affected project may temporarily or permanently cease operations and trigger an asset value impairment.

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Our risk management policies cannot fully eliminate the risk associated with some of our operating subsidiaries’ commodity trading and hedging activities, which may result in significant losses and adversely impact our financial condition.

Our subsidiaries’ commodity trading and hedging activities are inherently uncertain and involve projections and estimates of factors that can be difficult to predict such as future prices and demand for power and other energy-related commodities. In addition, Renewables has exposure to commodity price movements through their “natural” long positions in electricity in addition to proprietary trading and hedging activities. We manage the exposure to risks of such activities through internal risk management policies, enforcement of established risk limits and risk management procedures but they may not be effective and, even if effective, cannot fully eliminate the risks associated with such activities.

Risk Factors Relating to Ownership of Our Common Stock

Iberdrola exercises significant influence over AVANGRID, and its interests may be different from yours. Additionally, future sales or issuances of our common stock by Iberdrola could have a negative impact on the price of our common stock.

Iberdrola owns approximately 81.6% of outstanding shares of our common stock and will be able to exercise significant influence over AVANGRID’s policies and affairs, including the composition of our board of directors and any action requiring the approval of our shareholders, including the adoption of amendments to the certificate of incorporation and bylaws and the approval of a merger or sale of substantially all of our assets, subject to applicable law and the limitations set forth in the shareholder agreement to which we and Iberdrola are parties. The directors designated by Iberdrola may have significant authority to effect decisions affecting our capital structure, including the issuance of additional capital stock, incurrence of additional indebtedness, the implementation of stock repurchase programs and the decision of whether or not to declare dividends.

The interests of Iberdrola may conflict with the interests of our other shareholders. For example, Iberdrola may support certain long-term strategies or objectives for us that may not be accretive to shareholders in the short term. The concentration of ownership may also delay, defer or even prevent a change in control, even if such a change in control would benefit our other shareholders, and may make some transactions more difficult or impossible without the support of Iberdrola. This significant concentration of share ownership may adversely affect the trading price for shares of our common stock because investors may perceive disadvantages in owning stock in companies with shareholders who own significant percentages of a company’s outstanding stock.

Further, sales of our common stock by Iberdrola or the perception that sales may be made by it could significantly reduce the market price of shares of our common stock. Even if Iberdrola does not sell a large number of shares of our common stock into the market, its right to transfer such shares may depress the price of our common stock. Furthermore, pursuant to the shareholder agreement, Iberdrola is entitled to customary registration rights of our common stock, including the right to choose the method by which the common stock is distributed, a choice as to the underwriter and fees and expenses to be borne by us. Iberdrola also retains preemptive rights to protect against dilution in connection with issuances of equity by us. If Iberdrola exercises its registration rights and/or its preemptive rights, the market price of shares of our common stock may be adversely affected. Additionally, being a controlled company, relevant risks materializing at the ultimate parent level could have a negative impact on our share price, financial condition, credit ratings or reputation.

We have elected to take advantage of the “controlled company” exemption to the corporate governance rules for NYSE-listed companies, which could make shares of our common stock less attractive to some investors or otherwise harm our stock price.

Under the rules of the NYSE, a company in which over 50% of the voting power is held by an individual, a group or another company is a “controlled company” and may elect to take advantage of certain exemptions to the corporate governance rules for NYSE-listed companies. AVANGRID has elected to take advantage of these exemptions and, as a controlled company, is not required to have a majority of its board of directors be independent directors, a compensation committee and a nominating and corporate governance committee, or to have such committee composed entirely of independent directors. Because we are a “controlled company,” you will not have the same protections afforded to shareholders of companies that are subject to all the corporate governance requirements of the NYSE without regard to the exemptions available for “controlled companies.” Our status as a "controlled company" could make our shares of common stock less attractive to some investors or otherwise harm our stock price.

Our dividend policy is subject to the discretion of our board of directors and may be limited by our debt agreements and limitations under New York law.

Although we currently anticipate paying a regular quarterly dividend, any such determination to pay dividends is at the discretion of our board of directors and dependent on conditions such as our financial condition, earnings, legal requirements, including limitations under New York law and other factors the board of directors deem relevant. Our board of directors may, in

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its sole discretion, change the amount or frequency of dividends or discontinue the payment of dividends entirely. For these reasons, investors may not be able to rely on dividends to receive a return on their investments.

AVANGRID may be unable to meet our financial obligations and to pay dividends on our common stock if our subsidiaries are unable to pay dividends or repay loans from us.

We are a holding company and, as such, have no revenue-generating operations of our own. We are dependent on dividends and the repayment of loans from our subsidiaries and on external financings to provide the cash necessary to make future investments, service debt we have incurred, pay administrative costs and pay dividends. Our subsidiaries are separate legal entities and have no independent obligation to pay dividends. Our regulated utilities are restricted by regulatory decision from paying us dividends unless a minimum equity-to-total capital ratio is maintained. The future enactment of laws or regulations may prohibit or further restrict the ability of our subsidiaries to pay upstream dividends or to repay funds. In addition, in the event of a subsidiary’s liquidation or reorganization, our right to participate in a distribution of assets is subject to the prior claims of the subsidiary’s creditors. As a result, our ability to pay dividends on our common stock and meet our financial obligations is reliant on the ability of our subsidiaries to generate sustained earnings and cash flows and pay dividends to and repay loans from us.

General Risk Factors

If we are unable to implement and maintain effective internal control over financial reporting in the future, investors may lose confidence in the accuracy and completeness of our financial reports and the trading price of our common stock may be negatively affected.

As a public company, we are subject to reporting, disclosure control and other obligations in accordance with applicable laws and rules adopted, and to be adopted, by the SEC and the NYSE such as the requirement that our management report on the effectiveness of our internal control over financial reporting and our independent registered public accounting firm to attest to the effectiveness of our internal controls. Our management and other personnel devote a substantial amount of time to these compliance activities, and if we are not able to comply with these requirements in a timely manner or if we are unable to conclude that our internal control over financial reporting is effective, our ability to accurately report our cash flows, results of operations or financial condition could be inhibited and additional financial and management resources could be required. Any failure to maintain internal control over financial reporting or if our independent registered public accounting firm determines the we have a material weakness or significant deficiency in our internal control over financial reporting, could cause investors to lose confidence in the accuracy and completeness of our financial reports, a decline in the market price of our common stock, or subject us to sanctions or investigations by the NYSE, the SEC or other regulatory authorities. Failure to remedy any material weakness or significant deficiency in our internal control over financial reporting, or to implement or maintain other effective control systems required of public companies, could also restrict our future access to the capital markets and reduce or eliminate the trading market for our common stock.

Changes in tax laws, as well as judgments and estimates used in the determination of tax-related asset and liability amounts, could adversely affect our financial condition.

Our provision for income taxes and reporting of tax-related assets and liabilities require significant judgments and the use of estimates. Amounts of tax-related assets and liabilities involve judgments and estimates of the timing and probability of recognition of income, deductions and tax credits, including, but not limited to, estimates for potential adverse outcomes regarding tax positions that have been taken and the ability to utilize tax benefit carryforwards, such as net operating loss, or NOL, and tax credit carryforwards. Actual income taxes could vary significantly from estimated amounts due to the future impacts of, among other things, changes in tax laws, regulations and interpretations, our financial performance and results of operations.

Our investments and cash balances are subject to the risk of loss.

Our cash balances and the cash balances at our subsidiaries may be deposited in banks, may be invested in liquid securities such as commercial paper or money market funds or may be deposited in a liquidity agreement in which we are a participant along with other affiliates of the Iberdrola Group. Bank deposits in excess of federal deposit insurance limits would be subject to risks in the counterparty bank. Liquid securities and money market funds are subject to loss of principal, more likely in an adverse market situation, and to the risk of illiquidity.

The cost and availability of capital to finance our business is inherently uncertain and may adversely affect our financial condition.

AVANGRID and its subsidiaries are exposed to an increase in the general level of interest rates and to events, such as the 2008 financial crisis, affecting the capital markets that may increase the cost of capital or restrict its availability. In addition, AVANGRID’s performance directly affects its financial strength and credit ratings and therefore its cost of, and ability to

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attract, capital. Significant increases in the cost of capital, whether caused by economic or capital market conditions or adverse company performance, would adversely impact our financial performance and may make certain potential business opportunities uneconomic. Prolonged inability to access capital would impair our ability to execute our business plan and could impair AVANGRID’s ability to meet its financial obligations.

Moreover, certain of AVANGRID and its subsidiaries' debt securities and derivative contracts use the LIBOR as a benchmark for establishing the interest rate. In March 2021, the U.K. Financial Conduct Authority announced that all LIBOR settings will either cease to be provided by any administrator or no longer be representative immediately after December 31, 2021 for one-week and two-month U.S. dollar settings, as well as the sterling, euro, Swiss franc and Japanese yen settings, and immediately after June 30, 2023 for the remaining U.S. dollar settings. AVANGRID and its subsidiaries' existing debt securities and derivative contracts that reference LIBOR contain standard fallback language addressing the transition away from LIBOR. However, the discontinuation and replacement of LIBOR may have an unpredictable impact on the credit and financial markets. Additionally, uncertainty as to the nature of such potential discontinuation and replacement, including that any benchmark may not be the economic equivalent of LIBOR or not achieve market acceptance similar to LIBOR, may negatively impact the cost of our debt securities.

AVANGRID and our subsidiaries are subject to litigation or administrative proceedings, the outcome or settlement of which could adversely affect our business, financial condition and reputation.

AVANGRID and our operating subsidiaries have been and continue to be involved in legal proceedings, administrative proceedings, claims and other litigation that arise in the ordinary course of business. AVANGRID could experience unfavorable outcomes, developments or settlement of claims relating to these proceedings or future proceedings such as judgments for monetary damages, injunctions, unfavorable settlement terms, or denial or revocation of permits or approvals that could adversely impact our business, financial condition and reputation.

AVANGRID is not able to insure against all potential risks which could adversely affect our financial condition.

AVANGRID is exposed to certain risks inherent in our business such as equipment failure, manufacturing defects, natural disasters, terrorist attacks, cyber-attacks and sabotage, as well as affected by international, national, state or local events. Our insurance coverage may not continue to be offered or offered on an economically feasible basis and may not cover all events that could give rise to a loss or claim involving the assets or operations of our subsidiaries.

Pension and post-retirement benefit plans could require significant future contributions to such plan that could adversely impact our business and financial condition.

We provide defined benefit pension plans and other post-retirement benefits administered by our subsidiaries for a significant number of employees, former employees and retirees. Financial market disruptions and significant declines in the market values of the investments held to meet those obligations, discount rate assumptions, participant demographics and increasing longevity, and changes in laws and regulations may require us to make significant contributions to the plans.

AVANGRID and our subsidiaries may suffer the loss of key personnel or the inability to hire and retain qualified employees in a competitive labor market, which could have an adverse effect on our operations and financial condition.

The operations of AVANGRID depend on the continued efforts of our employees. Retaining key employees and attracting new employees are important to our financial performance and our operations. We cannot guarantee that any member of our management will continue to serve in any capacity for any length of time. We operate in an increasingly competitive labor market. If employee turnover increases or our workforce continue to age without appropriate replacements, our efficiency and effectiveness, productivity, and ability to pursue growth opportunities may be impaired. In addition, a significant portion of our skilled workforce will be eligible to retire in the next five to ten years. Such highly skilled individuals cannot be quickly replaced due to the technically complex work they perform, the competitive labor market and changing workplace. This could lead to a loss in productivity and increased recruiting and training costs.

Item 1B. Unresolved Staff Comments.

None.

Item 2. Properties.

We have included descriptions of the location and general character of our principal physical operating properties by segment in “Item 1. Business”, which is incorporated herein by reference. The principal offices of AVANGRID and Networks are located in Orange, Connecticut; Portland, Maine; and Rochester, New York, while Renewables’ headquarters are located in Portland, Oregon and Boston, Massachusetts. In addition, AVANGRID and its subsidiaries have various administrative offices located throughout the United States. AVANGRID leases part of its administrative and local offices.

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The following table sets forth the principal properties of AVANGRID, by location, type, lease or ownership and size as of December 31, 2021:

Location	Type of Facility	Leased/Owned	Size (square feet)
Orange, Connecticut	Office	Owned	123,125
Augusta, Maine	Office	Leased	215,832
Portland, Maine	Office	Leased	90,325
Rochester, New York	Office	Leased	116,472
Portland, Oregon	Office	Leased	52,107
Boston, Massachusetts	Office	Leased	39,215

We believe that our office facilities are adequate for our current needs and that additional office space can be obtained if necessary.

Item 3. Legal Proceedings.

For information with respect to this item see Notes 14 and 15 of our consolidated financial statements included in Part II, Item 8, "Financial Statements and Supplementary Data" of this Annual Report on Form 10-K, which information is incorporated herein by reference.

Item 4. Mine Safety Disclosures.

Not applicable.

Information about our Executive Officers

The names and ages of all executive officers of AVANGRID as of February 22, 2022 and a brief account of the business experience during the past five years of each executive officer are as follows:

Name	Age (1)	Title
Dennis V. Arriola	61	Chief Executive Officer
Douglas K. Stuver (2)	58	Senior Vice President – Chief Financial Officer
Scott M. Tremble	42	Senior Vice President – Controller
Jose Antonio Miranda Soto	50	Co-Chief Executive Officer and President of Renewables Onshore
William White	56	Co- Chief Executive Officer and President of Renewables Offshore
Robert D. Kump	60	Deputy Chief Executive Officer and President
R. Scott Mahoney	56	Senior Vice President – General Counsel and Corporate Secretary
Catherine Stempien	52	President and Chief Executive Officer of Networks

(1)Age as of December 31, 2021.

(2)On January 17, 2022, Mr. Stuver provided notice of his intention to resign from AVANGRID, effective February 23, 2022. Effective February 24, 2022, Patricia Cosgel, AVANGRID's current Vice President - Investor and Shareholder Relations, will be appointed Interim Chief Financial Officer.

Dennis V. Arriola. Mr. Arriola was appointed Chief Executive Officer of AVANGRID effective July 22, 2020. Mr. Arriola joined AVANGRID from Sempra Energy (Sempra), a publicly-traded energy infrastructure company, where he served as executive vice president and group president, and chief sustainability officer. Previously, he served as chairman, president and chief executive officer of Southern California Gas Co. (SoCalGas), one of Sempra’s regulated California utilities. Mr. Arriola spent most of the past 28 years in a broad range of leadership roles for the Sempra companies including as chief executive officer of SoCalGas, senior vice president and chief financial officer of both San Diego Gas & Electric and SoCalGas, vice president of communications and investor relations for Sempra, and regional vice president and general manager of Sempra’s South American operations. From 2008 to 2012, Mr. Arriola worked as executive vice president and president and chief financial officer for SunPower Corp., a Silicon Valley based solar technology company. Mr. Arriola previously served on the boards of directors for several Sempra operating companies, including Infraestructura Energética Nova (IEnova), a publicly-traded company in Mexico, Luz del Sur S.A.A., a publicly-traded company in Peru and Chilquinta Energía in Chile. He holds a bachelor’s degree in economics from Stanford University and a master’s degree in business administration from Harvard University. Mr. Arriola serves on the board of directors for Auto Club of Southern California, the U.S. Chamber of Commerce and the Edison Electric Institute, and previously served on the board of the California Business Roundtable and the California Latino Economic Institute.

Douglas K. Stuver. Mr. Stuver was appointed Senior Vice President - Chief Financial Officer of AVANGRID on July 8, 2018, and is responsible for AVANGRID’s investor relations corporate communications, risk management, treasury and

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purchasing divisions. Mr. Stuver joined AVANGRID in 2015 as Managing Director, Finance of Avangrid Renewables, LLC and served as Vice President – Controller of Avangrid Renewables, LLC from 2017 until 2018. Prior to joining the Company, he served as chief financial officer of the Company’s prior affiliate, PacifiCorp, from 2008 to 2015. Mr. Stuver graduated magna cum laude with a B.A. from University of Pittsburgh and is a Certified Public Accountant (inactive status).

Scott M. Tremble. Mr. Tremble was appointed Senior Vice President – Controller of AVANGRID on May 1, 2018, and is responsible for the execution and recording of AVANGRID’s transactional processes while meeting mandatory reporting requirements and tax obligations. Mr. Tremble also serves as a director of AVANGRID’s subsidiaries Networks, Renewables and UIL. Mr. Tremble joined the Company as chief accounting officer of Avangrid Management Company, LLC, a wholly-owned subsidiary of AVANGRID, in 2015, and was responsible for oversight in the areas of consolidation, financial reporting, internal controls, technical accounting and corporate accounting for the Company. From 2014 to 2015, he served as the international controller of Cole Haan LLC. Mr. Tremble started his career at PricewaterhouseCoopers in October 2002 and served various roles, including, most recently, as senior manager in the assurance practice. Mr. Tremble received his B.S. in Accountancy from Bentley University and is a Certified Public Accountant.

Jose Antonio Miranda Soto. Mr. Miranda Soto was appointed as Co-Chief Executive Officer and President-Onshore of Renewables on October 12, 2021, responsible for leading the growth and development of the company’s onshore wind and solar pipeline in the United States. Prior to joining AVANGRID, he served as Chief Executive Officer of Onshore in the Americas region for Siemens Gamesa and Chairman of its boards in US, Mexico and Brazil. He also served as Secretary of the Board and Executive Committee member of the American Wind Energy Association (AWEA). Prior to his fourteen-year tenure at Siemens Gamesa where he held roles in Europe, Asia and the Americas, he held a variety of roles over a ten-year period at the multinational engineering firm, ABB. Mr. Miranda Soto holds a Master of Business Administration ICADE (Universidad Pontificia de Comillas, Madrid, Spain) and a Maser degree in Industrial Engineering from the Superior Technical Institute of Industrial Engineers of Gijón (Oviedo University, Spain).

William White. Mr. White was appointed Co-Chief Executive Officer and President-Offshore of Renewables on October 12, 2021, responsible for leading the growth and development of the company’s offshore wind business. Mr. White joined AVANGRID as Head of the U.S. Offshore Business in October 2020. Previously, Mr. White served as president and chief executive officer of EnBW North America, the U.S. subsidiary of a German utility and offshore wind developer, from October 2018 until September 2020. Mr. White also served as Senior Director, Offshore Wind Sector Development for the Massachusetts Clean Energy Center from November 2012 to October 2018, where he led the state’s efforts on the federal leasing process for offshore wind development, as well as transmission planning, environmental surveys, supply chain and workforce development efforts, and stakeholder engagement efforts related to offshore wind, and as Special Assistant to President Clinton from 1996 to 1999. He is a graduate of Boston College’s School of Management (B.S.) and Harvard University’s John F. Kennedy School of Government (MPA).

Robert D. Kump. Mr. Kump was appointed Deputy Chief Executive Officer and President of AVANGRID on June 5, 2019. Mr. Kump served as President and Chief Executive Officer of Networks from November 2010 until June 5, 2019 and as AVANGRID’s Chief Corporate Officer from January 2014 to December 2016. Mr. Kump also served as a director of AVANGRID’s subsidiaries CMP, NYSEG and RG&E from 2009 until June 5, 2019, and as the Chief Executive Officer of Avangrid Service Company from October 2009 until June 5, 2019. Mr. Kump held various positions from February 1997 to October 2009 as AVANGRID’s senior vice president and chief financial officer, vice president, controller and chief accounting officer, treasurer and secretary. Mr. Kump also previously held a number of positions at NYSEG from 1986 to 1997, including senior accountant-external financial reporting, director-investor relations, director-financial services and treasurer. Mr. Kump earned a B.A. in accounting from Binghamton University and is a Certified Public Accountant in New York (inactive status).

R. Scott Mahoney. Mr. Mahoney was appointed Senior Vice President – General Counsel of AVANGRID on December 17, 2015. He was appointed Secretary of AVANGRID on January 27, 2016, and previously served as vice president-general counsel and secretary of Networks. Mr. Mahoney previously served as Deputy General Counsel and Chief FERC Compliance Officer for AVANGRID from January 2007 to June 2012, and served in legal and senior executive positions at AVANGRID subsidiaries from October 1996 until January 2007. Mr. Mahoney also serves on the board of directors of the Gulf of Maine Research Institute. Mr. Mahoney earned a B.A. from St. Lawrence University, a J.D. from the University of Maine, a master’s degree in environmental law from the Vermont Law School, and a postgraduate diploma in business administration from the University of Warwick. He has received bar admission to the State of Maine, the State of New York, the U.S. Court of Appeals, the U.S. District Court and the U.S. Court of Military Appeals and is a State of Connecticut Authorized House Counsel.

Catherine Stempien. Ms. Stempien was appointed President and Chief Executive Officers of Networks on March 15, 2021. Prior to joining AVANGRID, Ms. Stempien served in various roles for Duke Energy Corporation, a publicly-traded energy company, including as the President of Duke Energy Florida, as senior vice president of corporate development with responsibility for Duke Energy's corporate development activities, and as vice president legal for Duke Energy. Ms. Stempien

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has more than 25 years of legal and financial experience, predominantly in the energy and telecommunications fields. Ms. Stempien previously served as associate general counsel for Cinergy Corp., senior attorney for AT&T Corporation and AT&T Broadband, and associate with Covington & Burling LLP. Ms. Stempien earned a Juris Doctor degree, magna cum laude, from Boston University School of Law and a Bachelor of Arts degree in government from Dartmouth College. She also completed a joint Dartmouth/London School of Economics program in comparative political studies and participated in the Advanced Management Program at Harvard Business School. She is a member of the Bar in the District of Columbia, Colorado, the U.S. Supreme Court, and the U.S. Court of Appeals for the Third Circuit.

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PART II

Item 5. Market for Registrant’s Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities.

Market Information and Holders

Our shares of common stock began trading on the NYSE on December 17, 2015, under the symbol “AGR.” Prior to that time, there was no public market for shares of our common stock.

As of February 22, 2022, there were 3,142 shareholders of record.

Dividends

AVANGRID expects to continue paying quarterly cash dividends, although there is no assurance as to the amount of future dividends, which depends on future earnings, capital requirements and financial condition.

Further information regarding payment of dividends is provided in “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” of this Annual Report on Form 10-K.

Performance Graph

The line graph appearing below compares the change in AVANGRID’s total shareowner return on its shares of common stock with the return on the S&P Composite-500 Stock Index, the S&P Electric Utilities Index and the S&P Utilities Index for the period December 31, 2016 through December 31, 2021.

	December 31, 2016		December 31, 2021
AVANGRID	$	100.00	$	156.48
S&P 500	$	100.00	$	231.31
S&P Electric Utilities Index	$	100.00	$	182.51
S&P Utilities Index	$	100.00	$	174.96

The above information assumes that the value of the investment in shares of AVANGRID’s common stock and each index was $100 on December 31, 2016, including dividend reinvestment during this time period. The changes displayed are not necessarily indicative of future returns.

Recent Sales of Unregistered Securities

None.

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Issuer Repurchases of Equity Securities

AVANGRID repurchased 640,837 shares of common stock in open market transactions within the fourth quarter of the year ended December 31, 2021, as an advanced re-purchase to hedge a portion of the anticipated payouts under AVANGRID stock-based compensation plans.

Period	Total Number of Shares Purchased*	Average Price Paid Per Share		Total number of shares purchased as part of publicly announced plans or programs	Maximum number of shares that may yet be purchased under the plans or programs
October 1-31	—	—		—	—
November 1-30	—	—		—	—
December 1-31	640,837	$	48.34	None	None
Total	640,837	$	48.34	None	None

* All shares were purchased in open market transactions. The effects of these transactions did not change the number of outstanding shares of AVANGRID common stock.

Equity Compensation Plan Information

For information regarding securities authorized for issuance under equity compensation plans, see Part III, Item 12 of this Annual Report on Form 10-K.

Item 6. [Reserved]

Item 7. 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 consolidated financial statements and the notes thereto included elsewhere in this Annual Report on Form 10-K. In addition to historical 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. Factors that could cause or contribute to these differences include those discussed below and elsewhere in this Annual Report on Form 10-K, particularly in Part I, Item 1A, “Risk Factors.”

Overview

AVANGRID aspires to be the leading sustainable energy company in the United States. Our purpose is to work every day to deliver a more accessible clean energy model that promotes healthier, more sustainable communities. A commitment to sustainability is firmly entrenched in the values and principles that guide AVANGRID, with environmental, social, governance and financial sustainability key priorities driving our business strategy.

AVANGRID has approximately $40 billion in assets and operations in 24 states concentrated in our two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving approximately 3.3 million customers in New York and New England. Avangrid Renewables owns and operates 8.8 gigawatts of electricity capacity, primarily through wind and solar power, with a presence in 22 states across the United States. AVANGRID supports the achievement of the Sustainable Development Goals approved by the member states of the United Nations, was named among the World’s Most Ethical companies in 2022 for the fourth consecutive year by the Ethisphere Institute and is listed by Forbes and Just Capital as one of the 2022 Just 100, an annual ranking of the most just U.S. public companies. AVANGRID employs approximately 7,300 people. Iberdrola S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.6% of the outstanding shares of AVANGRID common stock. 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

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approximately 2.3 million electric utility customers and delivering natural gas to approximately 1.0 million natural gas utility customers as of December 31, 2021.

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 8,813 megawatts, or MW, as of December 31, 2021, including Renewables’ share of joint projects, of which 7,945 MW was installed wind capacity. Renewables targets to contract or hedge 85% to 95% of its capacity under long-term PPAs and hedges to limit market volatility. As of December 31, 2021, approximately 72% of the capacity was contracted with PPAs for an average period of approximately 9 years and an additional 18% of production was hedged. AVANGRID is one of the three largest wind operators in the United States based on installed capacity as of December 31, 2021, and strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. Renewables installed capacity includes 66 wind farms and four solar facilities in 21 states across the United States.

Texas Weather Event

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

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

Proposed Merger with PNMR

On October 20, 2020, AVANGRID, PNM Resources, Inc., a New Mexico corporation, or PNMR, and NM Green Holdings, Inc., a New Mexico corporation and wholly-owned subsidiary of AVANGRID, or Merger Sub, entered into an Agreement and Plan of Merger, or Merger Agreement, pursuant to which Merger Sub is expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of AVANGRID, or the Merger. PNMR is a publicly-owned holding company with two regulated utilities providing electricity and electric services in New Mexico and Texas. PNMR's electric utilities are the Public Service Company of New Mexico and the Texas-New Mexico Power Company. Following consummation of the Merger, AVANGRID will expand its geographic and regulatory diversity with ten regulated electric and gas companies in six states to help expand our growing leadership position in transforming the U.S. energy industry.

Pursuant to the Merger Agreement, each issued and outstanding share of the common stock of PNMR (other than (i) the issued shares of PNMR common stock that are owned by AVANGRID, Merger Sub, PNMR or any wholly-owned subsidiary of AVANGRID or PNMR, which will be automatically cancelled at the time the Merger is consummated and (ii) shares of PNMR common stock held by a holder who has not voted in favor of, or consented in writing to, the Merger who is entitled to,

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and who has demanded, payment for fair value of such shares) will be converted, at the time the Merger is consummated, into the right to receive $50.30 in cash, or Merger Consideration, or approximately $4.3 billion in aggregate consideration. In connection with the Merger, Iberdrola has provided the Iberdrola Funding Commitment Letter, pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration.

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

On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order 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. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, AVANGRID, PNMR and Merger Sub entered into an Amendment to the Merger Agreement, or the Amendment, pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the New Mexico Public Regulation Commission, or NMPRC, has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals.

In connection with the Merger, purported shareholders of PNMR have filed lawsuits against PNMR and the members of the PNMR board of directors under the federal securities laws, challenging the adequacy of the disclosures made in PNMR’s proxy statement in connection with the Merger or otherwise. Five lawsuits were filed in the United States District Court for the Southern District of New York and one was filed in the United States District Court for the Eastern District of New York. The lawsuits pending in the Southern District of New York were consolidated and the five plaintiffs filed notices of voluntary dismissal and the cases were dismissed in April. The remaining case is pending in the Eastern District of New York and PNMR and the members of the PNMR board have not yet been served. We cannot predict the outcome of this lawsuit.

For additional information on the Merger, see Note 1 - Background and Nature of Operations.

COVID-19

The COVID-19 pandemic continues to cause global economic disruption and volatility in financial markets and the United States economy. AVANGRID is one of the many companies providing essential services during this national emergency and we communicate regularly with federal and state authorities and industry resources to ensure a coordinated response. We continue to operate pursuant to our business continuity and emergency response plans in order to provide safe and reliable service to our customers and support our operational needs while managing the impacts of the COVID-19 pandemic and begin recovery from the pandemic. We deployed COVID-19 safety protocols for our front-line essential workers and, where possible, moved employees to remote work. We continue to monitor developments affecting both our workforce and our customers and will take precautions that we determine are necessary or appropriate. We continue to regularly communicate with our customers regarding the tools and resources available and to help our customers stay informed during this public health crisis. In addition to measures to protect our workforce and critical operations, we established a cross-functional task force that is coordinating the safe and effective return to office, with a portion of our workforce already returned to the office. AVANGRID continues to actively monitor potential supply chain and transportation disruptions that could impact the Company’s operations and will implement plans to address any such impacts on our business.

While we have developed and implemented and continue to develop and implement health and safety protocols, business continuity plans and emergency response plans in an effort to mitigate the negative impact of COVID-19 to our employees,

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customers and business, the extent of the impact of the pandemic on our business and financial results will continue to depend on numerous evolving factors that we are not able to accurately predict and which will vary by jurisdiction, including the duration and scope of the pandemic, the emergence of new variants of the virus, the likelihood of a resurgence of positive cases, the development and availability of effective treatments and vaccines, the speed at which such vaccines are administered, economic conditions during and after the pandemic, and governmental actions that have been taken, or may be taken in the future, in response to the pandemic. We will continue to actively monitor the situation and may take further actions that may be required by federal, state or local authorities or that we determine are in the best interests of our employees, customers, suppliers and shareholders.

We have not yet experienced a materially adverse impact to our business, results of operations or financial condition, however, given the uncertain scope and duration of the COVID-19 outbreak and its potential effects on our business, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition in the future.

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

Summary of Results of Operations

Our operating revenues increased by 10%, from $6,320 million for the year ended December 31, 2020, to $6,974 million for the year ended December 31, 2021.

Networks business revenues increased mainly due to increased rates from the New York rate plan that was approved on November 19, 2020. Renewables revenues increased mainly due to higher merchant pricing driven by the Texas weather event during the period.

Net income attributable to AVANGRID increased by 22% from $581 million for the year ended December 31, 2020, to $707 million for the year ended December 31, 2021, primarily due to higher Networks revenues from the New York rate plan.

Adjusted net income (a non-GAAP financial measure) increased by 25%, from $625 million for the year ended December 31, 2020 to $780 million for the year ended December 31, 2021. The increase is primarily due to a $93 million increase in Networks driven primarily by a new rate plan in New York that was approved on November 19, 2020, a $55 million increase in Renewables driven by higher merchant pricing mainly from the Texas weather event and a $7 million increase in Corporate mainly driven by favorable tax expense in the period.

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

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

Our financial condition and financing capability will be dependent on many factors, including the level of income and cash flow of its subsidiaries, conditions in the bank and capital markets, economic conditions, interest rates and legislative and regulatory developments.

Networks

Electric Transmission and Distribution and Natural Gas Distribution

The operating subsidiaries of Networks are regulated electric distribution and transmission and natural gas transportation and distribution utilities whose structure and operations are significantly affected by legislation and regulation. The FERC regulates, under the FPA, the interstate transmission and wholesale sale of electricity by these regulated utilities, including transmission rates and allowed ROE on transmission assets. Further, the distribution rates and allowed ROEs for Networks’ regulated utilities in New York, Maine, Connecticut and Massachusetts are subject to regulation by the NYPSC, the MPUC, PURA and DPU, respectively. Legislation and regulatory decisions implementing legislation establish a framework for Networks’ operations. Other factors affecting Networks’ financial results are operational matters, such as the ability to manage expenses, uncollectibles and capital expenditures, in addition to weather disturbances, equipment failures and environmental regulation. Networks expects to continue to make significant capital investments in its distribution and transmission infrastructure.

Pursuant to Maine law, CMP earns revenue for the delivery of energy to its retail customers, but is prohibited from selling power to them. CMP generally does not enter into purchase or sales arrangements for power with ISO-NE, the New England power pool, or any other ISO or similar entity. CMP generally sells all of its power entitlements under its nonutility

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generator and other PPAs to unrelated third parties under bilateral contracts. If the MPUC does not approve the terms of bilateral contracts, it can direct CMP to sell power entitlements that it receives from those contracts on the spot market through ISO-NE. NYSEG and RG&E enter into power purchase and sales transactions with the NYISO to have adequate supplies for their customers who choose to purchase energy directly from them. Customers may also choose to purchase energy from other energy supply companies.

Under Connecticut law, UI’s retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the generation services charge on their bills.

UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2022, 60% of its standard service load for the second half of 2022. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first quarter of 2022. However, from time to time, there are no bidders in the procurement process for supplier of last resort service and UI manages the load directly.

For additional information regarding Networks, including a comprehensive overview of our regulated businesses, please see the section entitled, “Business—Networks” in Part I, Item 1 in this report.

Revenues

Networks obtains its operating revenues primarily from the sale of electricity and natural gas at rates established by the state utilities commissions and the FERC in its jurisdictions through base rates and cost recovery deferral mechanisms, including reconciling differences between actual revenue received or cost incurred with the rate allowances provided under the approved tariffs. Cost recovery deferral mechanisms create regulatory assets and liabilities under the FERC, consistent with generally accepted accounting principles for financial reporting in the United States, or U.S. GAAP.

Regulatory deferrals in New York include electric and gas supply costs, PPAs, net plant reconciliations (downward only), revenue decoupling, system benefit charges, RPS, energy efficiency programs, including heat pumps, economic development programs, earnings sharing mechanism, electric vehicle program costs, labor FTE's, low income programs, pension costs, other post-employment benefits costs, environmental remediation costs, major storm costs, distribution vegetation management costs (downward only), gas research and development, incremental maintenance initiatives (downward only), management audit consultant and implementation costs, property taxes, Reforming the Energy Vision, or REV, initiatives, Nuclear Electric Insurance Limited credits, credit and debit card fees, debt costs, power tax, 2017 Tax Act, exogenous costs and certain legislative, accounting, regulatory and tax related actions.

Regulatory deferrals in Maine include stranded costs, distribution revenue decoupling, power tax regulatory asset, 2017 Tax Act, environmental remediation, storm reserve accounting, electric thermal storage pilot costs, standard offer retainage costs, AMI opt-out program costs, AMI deferral costs, AMI legal/health proceeding costs, conservation program costs, demand side management costs, low income program costs, electric lifeline program costs, make-ready line extension costs, electric vehicle pilot program costs and transmission planning and related cost allocation.

Regulatory deferrals in Connecticut include electric and gas supply costs, PPAs, revenue decoupling, earnings sharing mechanism, system benefit charges, certain hardship bad debt expense, transmission revenue requirements, gas distribution integrity management program costs, gas system expansion costs, certain public policy costs, certain environmental remediation costs, major storm costs and certain legislative, accounting, regulatory and tax related actions.

Regulatory deferrals in Massachusetts include gas supply costs, gas supply-related bad debt costs, environmental remediation costs, arrearage management program costs, gas system enhancement program costs, energy efficiency program costs, 2017 Tax Act and certain other public policy costs.

Each of Networks' regulated utilities' rate plans, other than MNG, contain an RDM under which their actual energy delivery revenues are compared on a periodic basis with the authorized delivery revenues and the difference accrued, with interest, for refund to or recovery from customers, as applicable.

NYSEG, RG&E and UI are energy delivery companies and also provide energy supply as providers of last resort. Energy costs that are set on the wholesale markets are passed on to consumers. The difference between actual energy costs that are incurred and those that are initially billed are reconciled in a process that results in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather

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conditions, environmental factors, regulatory and accounting changes and treatment of vulnerable customers, that are offset in the tariff process.

Pursuant to agreements with, or decisions of the NYPSC and the MPUC, Networks’ Maine and New York regulated utilities are each subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements, each of NYSEG, RG&E, CMP and MNG must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis, each utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that can be paid if the minimum equity ratio is not maintained and can, under certain circumstances, require that AVANGRID contribute equity capital. For CMP and MNG, equity distributions that would result in equity falling below the minimum level are prohibited. For NYSEG and RG&E, equity distributions that would result in a 13-month average common equity less than the maximum equity ratio utilized for the earnings sharing mechanism, or ESM, are prohibited if the credit rating of NYSEG, RG&E, AVANGRID or Iberdrola are downgraded by a nationally recognized rating agency to the lowest investment grade with a negative watch or downgraded to noninvestment grade. UI, SCG, CNG and BGC may not pay dividends if paying such dividend would result in a common equity ratio lower than 300 basis points below the equity percentage used to set rates in the most recent distribution rate proceeding as measured using a trailing 13-month average calculated as of the most recent quarter end. In addition, UI, SCG, CNG and BGC are prohibited from paying dividends to their parent if the utility’s credit rating, as rated by any of the three major credit rating agencies, falls below investment grade, or if the utility’s credit rating, as determined by two of the three major credit rating agencies, falls to the lowest investment grade and there is a negative watch or review downgrade notice. We believe that these minimum equity ratio requirements do not present any material risk with respect to our performance, cash flow or ability to pay quarterly dividends. In the ordinary course, Networks utilities manage their capital structures to allow the maximum level of returns consistent with the levels of equity authorized to set rates, and accordingly, compliance with these requirements does not alter ordinary equity level management. The regulated utility subsidiaries are also prohibited by regulation from lending to unregulated affiliates.

Rates

In December 2016, PURA approved new distribution rate schedules for 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 ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist.

In December 2017, PURA approved new tariffs for 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 approximately 52.00% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.

In December 2018, PURA approved new tariffs for CNG effective January 1, 2019 for a three-year rate plan with annual rate increases. The new tariffs continued the RDM and DIMP mechanism, ESM and tariff increases based on an ROE of 9.30% and an equity ratio of 54.00% in 2019, 54.50% in 2020 and 55.00% in 2021.

On January 18, 2019, the DPU approved new distribution rates for BGC. The distribution rate increase is based on an ROE of 9.70% and 54.00% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021. BGC expects to file an application to amend its distribution rates in its first half of 2022. We cannot predict the outcome of this proceeding.

On June 15, 2016, the NYPSC approved NYSEG's and RG&E's 2016 Joint Proposal for a three-year rate plan for electric and gas service which balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The 2016 Joint Proposal reflected many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows:

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	May 1, 2018
	Rate Increase		Delivery Rate Increase
Utility	(Millions)		%
NYSEG Electric	$	30	4.10	%
NYSEG Gas	$	15	7.30	%
RG&E Electric	$	26	5.70	%
RG&E Gas	$	10	5.20	%

The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas was 9.00%. The equity ratio for each company was 48.00%; however, the equity ratio was set at the actual up to 50.00% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increased as the ROE increased, with customers receiving 50.00%, 75.00% and 90.00% of earnings in rate year three (May 1, 2018 – April 30, 2019) above 9.75%, 10.25% and 10.75% ROE, respectively. The rate plans also included the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates and continuation of the existing RDM for each business. The 2016 Joint Proposal reflected the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($26 million annually for NYSEG Electric and $3 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds.

On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan (the "2020 Joint Proposal"). On November 19, 2020, the NYPSC approved the 2020 Joint Proposal, with modifications to the rate increases at the two electric businesses. The modifications were made to limit the overall bill impacts, to a level at or below 2.00% per year, in consideration of the current impacts of COVID-19 on the economic climate. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The new rates help to 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 ESM, 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 Increase		Rate Increase		Delivery Rate Increase		Rate Increase		Delivery Rate Increase
Utility	(Millions)		%		(Millions)		%		(Millions)		%
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	%

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. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency adjustment was ordered to remain in effect until CMP demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment starting from September 1, 2021. The MPUC approved CMP's request for removal of the management efficiency adjustment 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

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also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC’s consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. We cannot predict the outcome of this investigation.

On May 17, 2016, the MPUC approved MNG's ten-year rate plan through April 30, 2026. The settlement structure for non-Augusta customers includes a 34.60% delivery revenue increase over five years with an allowed 9.55% ROE and 50.00% common equity ratio. The settlement structure for Augusta customers includes a ten-year rate plan with existing Augusta customers being charged rates equal to non-Augusta customers plus a surcharge which increases annually for five years. New Augusta customers will have rates set based on an alternate fuel market model. In year seven of the rate plan MNG will submit a cost of service filing for the Augusta area to determine if the rate plan should continue. This cost of service filing will exclude $15 million of initial 2012/2013 gross plant investment, however the stipulation allows for accelerated depreciation of these assets. If the Augusta area’s cost of service filing illustrates results above a 14.55% ROE then the rate plan may cease, otherwise the rate plan would continue.

CMP’s and UI’s electric transmission rates are determined by a tariff regulated by the FERC and administered by ISO-NE. Transmission rates are set annually pursuant to a FERC authorized formula that allows for recovery of direct and allocated transmission operating and maintenance expenses, including return of and on investment in assets. The FERC currently provides an initial base ROE of 10.57% and additional incentive adders applicable to assets based upon vintage, voltage and other factors.

In September 2011, several New England governmental entities, including PURA, the Connecticut Attorney General and the Connecticut Office of Consumer Counsel filed a joint complaint with the FERC against ISO-NE and several New England Transmission Owners, or NETOs, (including CMP and UI) claiming that the current approved base ROE used in calculating formula rates for transmission service under the ISO-NE Open Access Transmission Tariff, or OATT, by the NETOs of 11.14% 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).

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, or the October 2018 Order. The FERC proposed to use this new methodology to resolve Complaints I, II, III and IV filed by the New England state consumer advocates.

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

Legislative and Regulatory Update

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

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$1.2 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 has been appealed by certain intervenors. The appeals are currently pending before the Maine Board of Environmental Protection and the Maine Superior Court. In addition, certain intervenors have appealed MDEP’s December 4, 2020 Order approving the transfer of the permits for the project to NECEC Transmission LLC and MDEP’s May 7, 2021 Order approving certain minor revisions. These appeals are currently pending before the Maine Board of Environmental Protection. We cannot predict the outcome of these proceedings.

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

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

On January 14, 2021, the DOE issued a Presidential Permit granting permission to NECEC Transmission LLC to construct, operate, maintain and connect electric transmission facilities at the international border of the United States and Canada. On March 26, 2021, the plaintiffs challenging the Army Corps permit filed a motion for leave before the District Court in Maine to supplement their complaint to add claims against DOE in connection with the Presidential Permit. On April 20, 2021, the District Court granted the plaintiffs motion to amend the complaint. On April 22, 2021 the plaintiffs filed their amended complaint asking the court, among other things, to vacate, set aside, remand or stay the Presidential Permit. This challenge to the Presidential Permit is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.

On August 10, 2021, the Maine Superior Court issued a ruling reversing the Maine Bureau of Parks and Lands’, or BPL, decision to grant a lease over a small area of public reserved lands to host a small section of the NECEC project. On August 13, 2021, BPL, and NECEC Transmission LLC appealed this ruling and prior decisions and orders in the case. The appeal is currently pending before the Maine Supreme Judicial Court sitting as the Law Court, or the Maine Law Court. As a result of the appeal, the Maine Superior Court decision vacating the lease is stayed. On September 15, 2021, the Maine Law Court ordered NECEC Transmission LLC to refrain from construction activities on the public reserved lands lease area during the pendency of the appeal. 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

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Lines and Facilities and Other Projects on Public Reserved Lands and Prohibit the Construction of Certain Transmission Lines in the Upper Kennebec Region” (the “Initiative”). The Initiative (i) requires, retroactive to 2020, legislative approval for the construction of any high-impact transmission line in Maine, with approval by a 2/3 vote of all members elected to each House of the Maine Legislature required for such lines crossing or utilizing public lands; (ii) prohibits, retroactive to 2020, construction of a high-impact electric transmission line in the Upper Kennebec Region and (iii) requires, retroactive to 2014, the vote of 2/3 of all members elected to each House of the Maine Legislature for a lease by BPL of public reserved lands for transmission lines and similar linear projects.

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

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

On December 16, 2021, the Maine Business & Consumer Court denied Networks and NECEC Transmission LLC’s request for a preliminary injunction temporarily precluding application of the Initiative to the NECEC transmission project. The Initiative took effect on December 19, 2021. On December 22, 2021, Networks and NECEC Transmission LLC moved that the Business & Consumer Court report its decision to the Maine Law Court for an interlocutory appeal under the applicable rule of appellate procedure. On December 28, 2021, the Business & Consumer Court granted this motion, thereby sending its decision to the Law Court for review. On January 3, 2022, the Law Court issued a procedural order setting the report for briefing. On January 10, 2022, the Law Court approved an expedited briefing schedule pursuant to which briefing on the report will take place between February and April 2022. Oral argument is expected to be scheduled by the Law Court during the first two weeks of May 2022. We cannot predict the outcome of these proceedings.

At the municipal level, twenty towns have granted municipal approvals to date. The remaining municipal approvals are being pursued gradually, consistent with the terms of the applicable ordinances and taking into account the project schedule and sequence.

Construction of the NECEC project started in January 2021 and was halted in November 2021. Construction remains stopped pending a decision by the Maine Law Court on the report of the Business & Consumer Court decision that denied Networks and NECEC Transmission LLC’s request for preliminary injunction preventing enforcement of the Initiative against the NECEC project during the pendency of the challenge against the Initiative. NECEC Transmission LLC has communicated to the counterparties to its agreements, including, without limitation, vendors, suppliers and TSA parties, the suspension of the MDEP permit, the Initiative and the status of the pending challenge. There are potentially adverse implications arising out of the suspension of the MDEP permit, the Initiative and the pending challenge, which may have negative impacts on the NECEC project. We cannot predict the outcome of the pending challenge against the Initiative. The company estimates a commercial operation date in the second half of 2024, assuming construction activities resume in 2022. As of December 31, 2021, we have capitalized approximately $546 million for the NECEC project.

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. We cannot predict the outcome of this request or any potential referendum.

CMP System Upgrades Due to Distributed Generation Demand

CMP has entered into certain interconnection agreements with distributed generation operators and/or developers. Due to the increased demand for solar distribution-side connections, certain reconfigurations of the grid and substation and systems upgrades may be necessary to prevent potential safety issues. CMP is analyzing the anticipated costs of the necessary upgrades and the distributed generation operations and/or developers responsibility for such costs under the interconnection agreements. We cannot predict the outcome of this matter, including any potential proceedings before the MPUC.

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New England Clean Energy Request for Proposals

On May 25, 2017, UI entered into six 20-year PPAs, totaling approximately 32 MW with developers of wind and solar generation. These PPAs originated from a three-state Clean Energy RFP, and were entered into pursuant to PA 13-303, which provides that the net costs of the PPAs are recoverable through electric rates. The PPAs were approved by PURA on September 13, 2017.

On June 20, 2017, UI entered into twenty-two 20-year PPAs totaling approximately 72 MW with developers of wind and solar generation. These PPAs originated from an RFP issued by the DEEP under PA 15-107 1(b) which provides that the net costs of the PPAs are recoverable through electric rates. The PPAs were approved by PURA on September 7, 2017. One contract was terminated on October 24, 2017, resulting in UI having twenty-one remaining contracts from this solicitation totaling approximately 70 MW.

In October of 2018, UI entered into five PPAs totaling approximately 50 MW from developers of offshore wind and fuel cell generation. These PPAs originated from an RFP issued by DEEP, under PA 17-144 which provides that the net costs of the PPAs are recoverable through electric rates. The PPAs were filed for PURA approval on October 25, 2018. On December 19, 2018, PURA issued its final decision approving the five PPAs and approved UI’s use of the non-bypassable federally mandated congestion charges for all customers to recover the net costs of the PPAs.

On December 28, 2018, DEEP issued a directive to UI to negotiate and enter into PPAs with twelve projects, totaling approximately 12 million MWh, selected as a result of the Zero Carbon RFP issued by DEEP pursuant to PA 17-3, which provides that the net costs of the PPAs are recoverable through electric rates. One of the selected projects is the Millstone nuclear facility located in Waterford, Connecticut which is owned by Dominion Energy, Inc. The PPA with Dominion was executed and approved by PURA in September 2019. Of the eleven other projects, one dropped out and PPAs with nine other projects were executed and approved by PURA in November 2019. The PPA for the final project was approved in August 2020.

Pursuant to Connecticut Act Concerning the Procurement of Energy Derived from Offshore Wind, DEEP solicited proposals from providers of energy derived from offshore wind facilities that are Class I renewable energy sources for up to 2,000 MW in the aggregate and selected Vineyard Wind, an affiliate of UI, to provide 804 MW of offshore wind through the development of its Park City Wind Project. In 2020, UI entered into a PPA with Vineyard Wind for the offshore wind energy. Similar to the case with the zero carbon PPAs discussed above, the net costs of the PPAs are recoverable through electric rates.

Reforming the Energy Vision

In 2014, the NYPSC instituted its REV proceeding, the goals of which are to improve electric system efficiency and reliability, encourage renewable energy resources, support distributed energy resources, or DER, and empower customer choice. In this proceeding, the NYPSC is examining the establishment of a Distributed System Platform to manage and coordinate DER, and provide customers with market data and tools to manage their energy use. The NYPSC is also examining how its regulatory practices should be modified to incentivize utility practices to promote REV objectives. REV has been divided into two tracks, Track 1 for market design and technology, and Track 2 for regulatory reform. REV proposes regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar, and wider deployment of DER, such as micro grids, on-site power supplies and storage. Track 2 was undertaken in parallel with Track 1, and examines changes in current regulatory, tariff, market design and incentive structures to better align utility interests with achieving NYPSC’s policy objectives. Our New York utilities are addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in 2016 which included guidance related to the potential for earnings adjustment mechanisms, or EAMs, platform service revenues, innovative rate designs, and data utilization and security. In 2016, NYSEG and RG&E filed a proposal for the implementation of EAMs in the areas of system efficiency, energy efficiency, interconnections and clean air. The EAM is reflected in the rate plan approved in 2020.

In 2016, an initial DSIP was filed by NYSEG and RG&E and included information regarding the potential deployment of Automated Metering Infrastructure, or AMI. A separate petition for the cost recovery associated with full deployment of AMI was filed by NYSEG and RG&E. In March 2017, the NYPSC issued three separate REV-related orders. The three orders involved: 1) modifications to the electric utilities’ proposed interconnection EAM framework; 2) further DSIP requirements, including the filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at NYSEG by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of VDER. NYSEG and RG&E submitted biannual updates of the DSIP plan on July 31, 2018 and June 30, 2020, consistent with guidance received from the NY Department of Public Service. The next DISP update is scheduled for June 2022. As of the end of 2018, both NYSEG and RG&E had deployed two energy storage projects each, consistent with the March 2017 NYPSC order requirements. In December 2018, the NYPSC staff submitted whitepapers on standby and buyback service rate design, future value stack compensation and capacity value compensation. The NYPSC ruled on the proposals set forth in the whitepapers on May 16, 2019. NYSEG and RG&E filed proposed standby and buyback rates with the NYPSC on September 24, 2019. A final

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Commission Order is expected in 2022. The NYPSC also issued an order on value stack compensation for high-capacity-factor resources on December 12, 2019 modifying the treatment of certain high-capacity-factor DER in the Value Stack compensation framework. The modification per the December 12, 2019 Order became effective February 1, 2020. On March 19, 2020, the Commission issued an additional Order regarding Value Stack Compensation. The Order directs National Grid, NYSEG and RGE to reallocate capacity from closed tranches where available capacity remained due to projects being canceled since the issuance of the VDER Compensation Order, and to assign that capacity to a new Community Credit Tranche with compensation at 2 cents per kWh. The utilities must also continue to reallocate capacity to this new Tranche for the next six months when there are cancellations of projects that have received a Market Transition Credit (MTC) or Community Credit allocation. The new provisions per the March 19, 2020 Order became effective on May 1, 2020. On July 16, 2020, the Commission issued an Order establishing a net metering successor tariff. The Order continues Phase One NEM for all eligible mass market and commercial projects under 750 kW interconnected after January 1, 2022 and implements a modest customer benefit contribution (CBC) for onsite DERs to address cost recovery of certain public benefit programs. Customers that install DERs interconnected after January 1, 2022 shall be charged a monthly per kW fee based on the nameplate rating of the DER. Draft tariff leaves implementing the Commission’s Order and proposed CBC calculations were filed on November 1, 2020. A final Commission Order was issued on August 13, 2021, implementing the CBC effective January 1, 2022 for new mass market net metering customers.

On May 14, 2020, the Commission issued an Order extending and expanding distributed solar incentives. In addition to authorizing the extension of and additional funding for the NY-Sun program, the Commission modified certain program rules related to the NY-Sun program and the VDER policy. As part of the ordered modifications, the Commission directed the electric utilities with VDER tariffs to add tariff language for a Remote Crediting program that will allow Value-Stack-eligible generation resources to distribute the credits they receive for generation injected into the utility system to the utility bills of multiple, separately sited, non-residential customers. The Commission ordered the utilities to submit tariff leaves that implement the modifications associated with the Remote Crediting program to become effective November 1, 2020. Given the complexity of the program changes, the utilities petitioned the Commission for an extension. Tariffs were filed on August 16, 2021, becoming effective on September 1, 2021.

On April 24, 2018, the Commission instituted a proceeding to consider the role of utilities in providing infrastructure and rate design to encourage the adoption of electric vehicles and expansion of electric vehicle supply equipment. The Commission issued an Order on February 2, 2019 to establish a Direct Current Fast Charger incentive program, and subsequently clarified its Order on July 12, 2019 and March 3, 2020. A Whitepaper was issued by DPS Staff on January 13, 2020, proposing a make-ready infrastructure program with a budget estimated at $582 million. An order in this proceeding was issued on July 16, 2020 approving a $700 million statewide program (NYSEG and RG&E combined share is approximately $118 million) funded by customers to accelerate the deployment of electric vehicle charging stations in an effort to increase the number of electric vehicles.

On February 11, 2021, the Commission issued an Order to implement an Integrated Energy Data Resource platform, where NYSERDA was designated as the Program Sponsor of the platform. The development of the platform will be an iterative process, currently separated into two phases. Utilities will be expected to transmit data to the platform through processes to be established with the Program Manager (to be determined). The Order established a combined cost cap of $12 Million for NYSEG and RG&E for Phase 1, to be deferred and recovered in the next rate case filing after Phase 1 is complete. On April 15, 2021, the Commission issued an Order Adopting a Data Access Framework and Establishing Further Process (“DAF Order”). The DAF Order establishes a centralized data access certification process. On May 14, 2021, a stakeholder (Mission:data Coalition) filed a petition for rehearing on the DAF Order citing concerns with the audit requirements. The NY utilities also jointly filed a petition for rehearing on May 17, 2021 regarding the Commission’s directive to remove fees for certain requests for data. The Commission issued an Order on November 18, 2021 denying both requests for rehearing.

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

In March 2018, following two severe winter storms that impacted more than a million electric utility customers in New York, including 520,000 NYSEG and RG&E customers, the NYDPS commenced a comprehensive investigation of the preparation and response to those events by New York's major electric utility companies. The investigation was expanded in the spring of 2018 to include other 2018 New York spring storm events.

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

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Also on April 18, 2019, the NYPSC issued an Order Instituting Proceeding and to Show Cause directed to all major electric utilities in New York, including NYSEG and RG&E. The order directs the utilities, including NYSEG and RG&E, to show cause why the NYPSC should not pursue civil and/or administrative penalties for the apparent failure to follow their respective ERPs as approved and mandated by the NYPSC. The NYPSC also directed the utilities, within 30 days, to address whether the NYPSC should mandate, reject or modify in whole or in part, the 94 recommendations contained in the 2018 Staff Report. On May 20, 2019, NYSEG and RG&E responded to the portion of the Order to Show Cause with respect to the recommendations contained in the 2018 Staff Report. A petition requesting Commission approval of a joint settlement agreement was filed with the Commission on December 17, 2019. On February 6, 2020, the Commission approved the joint settlement agreement, which allows the companies to avoid litigation and provides for payment by the companies of a $10.5 million penalty ($9.0 million by NYSEG and $1.5 million by RG&E). The settlement reached as part of the NYSEG Electric and RG&E Electric three-year rate plan provides for utilization of these penalties as rate modifiers by the establishment of regulatory liabilities that will be amortized over the three-year term of the rate plans for both NYSEG Electric and RG&E Electric.

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

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

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

CMP Customer Billing System Investigation and Class Action

On March 1, 2018, the MPUC issued a Notice of Investigation initiating a summary investigation into CMP’s metering, billing, and customer communications practices. Due to the highly technical nature of CMP’s customer billing system, on March 22, 2018 the MPUC issued an Order Initiating Audit commencing a forensic audit of CMP’s customer billing system to identify any errors that have, or continue to be resulting in billing inaccuracies. On July 10, 2018, the MPUC issued an Order Modifying Scope of Audit, which expanded the scope of the audit to include CMP’s customer communication practices. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 14, 2019, the MPUC issued an Order and Notice of Investigation initiating an investigation of CMP’s metering and billing practices. On September 3, 2019, the MPUC issued its Bench Analysis in the Metering and Billing Investigation and supported the findings of the independent audit. On September 7, the OPA issued testimony and findings from a separate audit firm which agreed with certain portions of the independent audit and also stated that continuing problems still persist in CMP’s billing system. CMP provided rebuttal testimony on October 16, 2019, and hearings were held in November 2019. On January 30, 2020, the MPUC Commissioners deliberated and based on the verbal discussion, the Commissioners indicated that CMP’s Metering and Billing system is accurately reporting data; there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The Commissioners were critical of CMP finding that CMP failed to implement proper testing of the SmartCare system prior to go-live; CMP’s implementation of SmartCare was imprudent; CMP’s SmartCare implementation experienced an unacceptable number of billing errors, delayed or estimated bills, bill presentment issues and unreasonable time required to address these issues; and the implementation issues were compounded by inadequate staffing, resulting in the inability of customers to contact a CMP representative. On February 19, 2020, the MPUC issued an order in CMP’s distribution rate case proceeding discussed above and on February 24, 2020 issued an order in the metering and billing investigation. Each order reflected the MPUC’s conclusion that CMP’s Metering and Billing system is accurately reporting data, there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. However, the MPUC orders imposed a reduction of 100 basis points in ROE, as a management

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efficiency adjustment, to address the MPUC Commissioners’ concerns with CMP’s customer service implementation and performance following the launch of its new billing system in 2017. The management efficiency adjustment will remain in effect until CMP has demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment starting from September 1, 2021. The MPUC approved CMP’s request for removal of the management efficiency adjustment effective as of its February 18, 2022 order.

On August 16, 2018, an amended class action lawsuit was filed against CMP and the Company in the Cumberland County Superior Court on behalf of all CMP customers alleging that CMP’s new billing software and metering system improperly overcharged customers. The plaintiff asserts this claim under the common law of unjust enrichment, breach of contract and fraudulent and intentional misrepresentation and seeks damages, punitive damages, attorney fees and costs. On September 21, 2018, we filed a Motion to Dismiss all of the claims that was opposed by the plaintiffs. On November 14, 2018, the plaintiff filed a motion for a preliminary and permanent injunction enjoining CMP from sending disconnection notices and/or disconnecting their power until this litigation is resolved. On February 22, 2019, the Cumberland County Superior Court ordered that the proceedings be stayed until November 1, 2019 to allow resolution of the MPUC’s formal investigation of CMP’s billing practices and denied the plaintiff’s motion for a temporary restraining order. On July 30, 2019, Douglas Herling, chief executive officer of CMP, and Iberdrola, S.A. were added as defendants and additional claims alleging violations of the Racketeer Influenced and Corrupt Organizations Act were added to the case. CMP and the Company removed the case to federal court and filed a Motion to Dismiss on September 30, 2019. On November 22, 2019, upon agreement of the parties, CMP and the Company withdrew its motion to dismiss without prejudice and the plaintiffs were granted leave to file an amended complaint on or before January 31, 2020 to allow for the conclusion of the MPUC investigation into CMP’s metering, billing, and customer communications practices. On January 30, 2020, the MPUC deliberated the metering, billing and customer communications investigation. The MPUC found that with exception of certain localized and random errors, CMP’s billing system is working as designed and there were no systemic errors in billing. The decision also included an administrative process to address unresolved customer complaints of high bills. On January 31, 2020, the plaintiffs filed their third amended complaint. On February 28, 2020, CMP and the Company filed a Motion to Dismiss Plaintiff’s Third Amended Complaint Without Prejudice or to Stay Proceedings Pending Plaintiffs’ Exhaustion of Administrative Remedies which was denied on November 25, 2020. On February 1, 2021, CMP and the Company filed its Motion to Dismiss with prejudice for all claims except the breach of contract claim, which under the rules cannot be dismissed via this motion. The plaintiffs’ opposition was filed on March 9, 2021, and CMP filed its reply on March 29, 2021. Oral argument on the Motion to Dismiss was held on May 20, 2021. We cannot predict the outcome of this class action lawsuit.

CMP Revenue Decoupling Mechanism Investigation

On June 9, 2020, the MPUC issued a Notice of Investigation to open an investigation into the effects of the COVID-19 pandemic on customers’ electricity-usage patterns and whether CMP’s RDM should be suspended for the annual distribution rate change that is expected to occur on July 1, 2021, for electricity delivered in calendar year 2020. On June 24, 2020, the MPUC issued a procedural order setting forth initial steps in this proceeding. On July 21, 2020, CMP filed testimony presenting electricity-usage data for its two RDM classes (residential and commercial/industrial) through June 2020, along with testimony explaining the data and the reasons why the current RDM should remain in place without alteration. On August 11, 2020, a technical conference was held and CMP filed electricity-usage data on August 20, 2020. On December 16, 2020, the MPUC issued an Order determining that CMP’s RDM should not be suspended and the RDM should be simplified by merging the two RDM classes into a single class. There is no impact to existing RDM balances as a result of the order issued by the MPUC.

CMP Annual Compliance Filing

On March 31, 2020, CMP submitted its annual compliance filing in accordance with the Commission’s February 19, 2020 decision in Public Utilities Commission, Investigation into Rates and Revenue Requirements of Central Maine Power Company. In its filing, CMP proposed an overall increase in its distribution delivery revenues of $14.5 million, or 5.6% over current rates, effective July 1, 2020. This increase is due primarily to storm costs and RDM, which are offset by excess deferred income taxes. As a result of the COVID-19 pandemic, CMP’s filing proposed cost recovery provisions designed to minimize the rate impacts on customers including, without limitation, an extended period for recovery of storm costs incurred in 2019. On June 18, 2020, the MPUC approved a partial stipulation, which adopted CMP’s proposal to recover 2019 major storm costs over a three-year period commencing on July 1, 2020, but denied CMP’s proposed recovery of costs related to its legacy billing system, which are less than $1 million. On June 18, 2020, CMP made a compliance filing with revised tariffs, which was approved by the MPUC on June 23, 2020, and the new rates took effect on July 1, 2020.

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CMP Standard Offer Uncollectible Adder Investigation

On August 19, 2020, the MPUC issued a Notice of Investigation to open an investigation into whether the uncollectible adder to CMP’s standard offer retainage account for the residential and small non-residential standard offer customer class should be increased for standard offer electricity-supply rates that go into effect January 1, 2022. The investigation also included a review of CMP’s credit and collection practices.

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

Tax Act Proceedings

The Tax Act significantly changed the federal taxation of business entities including, among other things, implementing a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates 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, to review and address the implications of the Tax Act on the utilities.

In New York, the NYPSC issued an order requiring sur-credits to return benefits reflecting the lower effective tax rate of 21% to customers effective October 1, 2018. For NYSEG Gas, RG&E Electric and RG&E Gas the NYPSC also required the sur-credit to include the return to customers of the January - September 2018 Tax Act savings over three years. The remaining deferred amounts associated with the recognition of the effects of the Tax Act are being used as rate moderators in the approved 2020 Joint Proposal. In Connecticut, with regard to UI, the PURA approved a multi-docket settlement proposal on June 28, 2021, which required UI to flow accumulated Tax Act savings back to customers over a 22-month period, commencing on July 1, 2021 through April 30, 2023. With regard to SCG, we expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case, unless PURA determines otherwise. CNG and BGC include Tax Act savings in their current rate plans. In Maine, CMP adjusted rates beginning July 1, 2018 to pass back to customers the Tax Act savings after offsetting for recovery of deferred 2017 storm costs and in the general rate case filing with the MPUC is proposing to use savings arising out of the Tax Act to minimize rate increases while making its electric system more reliable. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above, the MPUC approved CMP’s distribution related accumulated deferred income tax balances associated with the Tax Act as well as the authorized amortization periods for the return of regulatory liabilities and the recovery regulatory assets. At the FERC, CMP transmission and UI transmission adjusted their tariffs in June 2018 to reflect the income statement value of Tax Act savings. On December 22, 2021, the FERC issued an order finding that the NETOs Regional Network Service proposed revisions partially comply with the requirements of Order 864 and directed the NETOs to submit a further compliance filing within 60 days of the date of the order. The compliance is effective January 27, 2020, consistent with Order 864 and January 1, 2022, to reflect the fact that the NETOs existing transmission formula rates under the ISO-NE Tariff will be replaced by a settled formula rate effective January 1, 2022.

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 $142 million and $148 million, respectively, for this item at December 31, 2021 and December 31, 2020.

CMP began recovering its regulatory asset in 2020. In 2017, the NYPSC commenced an audit of the power tax regulatory assets. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax accounting. The NYPSC audit report is expected to be completed during 2022.

Weather Impact

The demand for electric power and natural gas is affected by seasonal differences in the weather. Statewide demand for electricity in New York, Connecticut and Maine tends to increase during the summer months to meet cooling load or in winter months for heating load while statewide demand for natural gas tends to increase during the winter to meet heating load. Market prices for both electricity and natural gas reflect the demand for these products and their availability at that time. Overall operating results of Networks do not fluctuate due to commodity costs as the regulated utilities generally recover those costs

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coincident with their expense or defer any differences for future recovery. Networks has historically sold less power when weather conditions are milder and may also be affected by severe weather, such as ice and snow storms, hurricanes and other natural disasters which may result in additional cost or loss of revenues that may not be recoverable from customers. However, Networks’ regulated utilities, other than MNG, have approved RDMs as part of the NYPSC, PURA and MPUC rate plans in place for the period ended December 31, 2021. The RDM allows the regulated utilities to defer for future recovery and shortfall from projected revenues whether due to weather, economic conditions, conservation or other factors.

New Renewable Source Generation

Under Connecticut Public Act 11-80, or PA, Connecticut electric utilities are required to enter into long-term contracts to purchase Connecticut Class I Renewable Energy Certificates, or RECs, from renewable generators located on customer premises. Under this program, UI is required to enter into contracts totaling approximately $200 million in commitments over approximately 21 years. The obligations were initially expected to phase in over a six-year solicitation period and to peak at an annual commitment level of about $13.6 million per year after all selected projects are online. PA 17-144, PA 18-50 and PA 19-35 extended the original six-year solicitation period of the program by adding seventh, eighth, ninth, and tenth years, and increased the original funding level of this program by adding up to $64 million in additional commitments by UI. UI expects to partially mitigate the cost of these contracts through the resale of the RECs. PA 11-80 provides that the remaining costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable from (or credited to) customers through electric rates.

Pursuant to Connecticut statute, in January 2017, UI entered into a master agreement with the Connecticut Green Bank to procure Connecticut Class I RECs produced by residential solar installations in 15-year tranches, with a final tranche to commence no later than 2022. UI’s contractual obligation is to procure 20% of RECs produced by about 255 MW of residential solar installations. Connecticut statutes provides that the net costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable from (or credited to) customers through electric rates.

Pursuant to Maine law, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of energy, capacity or RECs, from qualifying resources. The MPUC is further authorized to order Maine transmission and distribution utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreen’s 60 Megawatt (MW) Rollins wind farm. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. Pursuant to a MPUC Order dated December 18, 2017, CMP entered into a 20-year agreement with Dirigo Solar, LLC on September 10, 2018, to purchase capacity and energy from multiple Dirigo solar facilities throughout CMP’s service territory. CMP’s purchase obligations under the Dirigo contract will increase as additional solar facilities are brought on line, eventually reaching a level of approximately $4 million per year. Pursuant to a MPUC Order dated November 6, 2019, CMP entered into a 20-year agreement with Maine Aqua Ventus I GP LLC on December 9, 2019, to purchase capacity and energy from an off-shore wind farm under development near Monhegan Island, Maine. CMP’s purchase obligations under the Maine Aqua Ventus contract will be approximately $12 million per year once the facility begins commercial operation. Pursuant to Maine law, the MPUC conducted two competitive solicitation processes to procure, in the aggregate, an amount of energy or RECs from Class 1A resources that is equal to 14% of retail electricity sales in the State during calendar year 2018, or 1.715 million MWh. Of that 14% total, the MPUC must acquire at least 7%, but not more than 10%. Through contracts approved in December 2020 (Tranche 1), CMP was ordered to execute 13 contracts. In October 2021 CMP executed contracts with 6 additional facilities (Tranche 2). Each of the Tranche 1 and Tranche 2 are for 20-year terms. In accordance with MPUC orders, CMP either sells the purchased energy, or in one case the RECs, from these facilities in the ISO New England markets, through periodical auctions of the purchased output to wholesale buyers in the New England regional market, or through a sale to a third party for the RECs. Under Maine law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under Maine law, and has tentatively accepted long-term proposals from other sellers, these selections have not yet resulted in additional currently effective contracts with CMP.

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

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

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

Connecticut Energy Legislation

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

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

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

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

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

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

In August 2020, following Tropical Storm Isaias, the NYDPS commenced a comprehensive investigation of the preparation and response to this event by New York's major electric utility companies. In addition, on August 20, 2020, the New York State Senate and Assembly held a joint hearing to examine the response of various utility companies during the aftermath of Tropical Storm Isaias. On December 31, 2020, NYSEG and NYDPS Staff entered into a settlement agreement regarding three alleged violations by NYSEG of its emergency response plan pursuant to which NYSEG agreed to make a payment of a penalty of approximately $1.5 million. The settlement was approved by the NYPSC on January 21, 2021.

Proposed New York Legislation in Response to the Tropical Storm Isaias

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

CMP Generator Interconnection Investigation

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

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

Summary Investigation of Management Issues Identified in Management Audit of CMP

As noted above, on February 19, 2020, the MPUC issued its final order in CMP’s distribution revenue case. As part of that order, the MPUC initiated a management audit of CMP and its affiliates 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 on July 12, 2021, the independent auditor released its final report. On September 28, 2021, the MPUC opened a summary investigation to follow up on the management audit report. The MPUC directed CMP to file a plan to incorporate feedback from the management audit. CMP filed a Performance Improvement Plan and parties commented on the plan. CMP provided responsive comments on January 6, 2022. The matter is pending MPUC consideration.

Summary Investigation into Security Limits Litigation

On December 13, 2021, the MPUC issued a Notice initiating a summary investigation of certain allegations with respect to the recovery of capital expenditure costs contained in the lawsuit filed by Security Limits, Inc. and Paul Silva against the Company, Networks and Iberdrola, S.A. and several other entities and individuals in the United States District Court Southern District of New York. CMP filed a report describing any costs described in the complaint that are currently being recovered or will be recovered in rates on January 18, 2022 as directed by the Notice of Summary Investigation. In the report, CMP noted that the plaintiffs’ had not yet served the complaint upon Networks or the Company. The MPUC directed CMP to submit notification to the MPUC when the Complaint has been served or when the procedural deadline for serving the Complaint has passed. On February 9, 2022, Security Limits, Inc. and Paul Silva dismissed their complaint. On February 10, 2022, CMP notified the MPUC of the dismissal and requested that the proceeding be closed. We cannot predict the outcome of this summary investigation.

Renewables

Renewable Energy Incentives

Renewables relies, in part, upon government policies that support utility-scale renewable energy and enhance the economic feasibility of development and operating wind energy projects in regions in which Renewables operates or plans to develop and operate renewable energy facilities.

On December 20, 2019, the Setting Every Community up for Retirement Enhancement Act of 2019 was signed into law that extended the PTC and investment tax credit, or ITC, options for wind facilities to 60% of the full credit for facilities commencing construction in 2020, leaving in place phased down credits for projects commencing in years prior to 2020.

The 2020 Consolidated Appropriations Act provides favorable extensions to renewable income tax incentives. Onshore and offshore wind projects may now claim a 60% PTC for projects commencing construction in 2020 and 2021. In addition, offshore wind may now elect to claim a 30% ITC for projects commencing construction through 2025. Onshore wind can claim an 18% ITC for projects commencing construction in 2020 or 2021, with no ITC thereafter.

Solar projects commencing construction before 2020 may claim a 30% ITC. Solar projects that commence construction from 2020-2022 may claim a 26% ITC, projects commencing construction in 2023 may claim a 22% ITC and projects commencing thereafter may claim a 10% ITC. The ITC statutes require solar projects to be completed by the end of 2025 in order to claim the applicable ITCs.

The Internal Revenue Service, or IRS, provided continuity safe harbor guidance that requires renewable projects to be completed within four years of the year construction commences. Any projects that do not meet this requirement will fall

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outside of the safe harbor and be subject to IRS scrutiny with regard to the date construction commenced. In 2020, the IRS allowed projects beginning construction in 2016 or 2017 an additional year (five years total) to complete construction. In late December 2020, the IRS issued a notice giving onshore wind projects on federal lands, with transmission permit requirements, and offshore wind projects 10 years to complete construction.

Vineyard Wind 1 Federal Approval

On May 11, 2021, the U.S. Bureau of Ocean Energy Management, or BOEM, issued its Record of Decision, or ROD, approving Vineyard Wind 1, an 800 MW offshore wind project that is part of our joint venture Vineyard Wind, LLC.

Lawsuits were filed in July 2021, August 2021, September 2021 and January 2022 against BOEM, the U.S. Fish and Wildlife Service, NOAA Fisheries Directorate, U.S. Army Corps of Engineers and the U.S. Department of the Interior challenging the approval of the proposed Vineyard Wind 1 Project. We cannot predict the outcome of these proceedings.

Results of Operations

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

	Year Ended December 31, 2021
	Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	6,974	$	5,754	$	1,220	$	—
Operating Expenses
Purchased power, natural gas and fuel used	1,719		1,489		230		—
Operations and maintenance	2,706		2,198		495		13
Depreciation and amortization	1,014		616		397		1
Taxes other than income taxes	640		575		72		(7)
Total Operating Expenses	6,079		4,878		1,194		7
Operating Income	895		876		26		(7)
Other Income (Expense)
Other income (expense)	60		66		(4)		(2)
Losses (earnings) from equity method investments	7		12		(5)		—
Interest expense, net of capitalization	(298)		(217)		(1)		(80)
Income Before Income Tax	664		737		16		(89)
Income tax expense (benefit)	21		98		(48)		(29)
Net Income	643		639		64		(60)
Net loss (income) attributable to noncontrolling interests	64		(3)		67		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	707	$	636	$	131	$	(60)

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	Year Ended December 31, 2020
	Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	6,320	$	5,188	$	1,132	$	—
Operating Expenses
Purchased power, natural gas and fuel used	1,379		1,125		254		—
Operations and maintenance	2,466		2,038		429		(1)
Depreciation and amortization	987		592		394		1
Taxes other than income taxes	619		556		71		(8)
Total Operating Expenses	5,451		4,311		1,148		(8)
Operating Income	869		877		(16)		8
Other Income (Expense)
Other income (expense)	18		15		15		(12)
Earnings (losses) from equity method investments	(3)		10		(13)		—
Interest expense, net of capitalization	(316)		(234)		(7)		(75)
Income Before Income Tax	568		668		(21)		(79)
Income tax expense (benefit)	29		120		(80)		(11)
Net Income (Loss)	539		548		59		(68)
Net loss (income) attributable to noncontrolling interests	42		(2)		44		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	581	$	546	$	103	$	(68)

	Year Ended December 31, 2019
	Total		Networks		Renewables		Other(1)
	(in millions)
Operating Revenues	$	6,336	$	5,164	$	1,184	$	(12)
Operating Expenses
Purchased power, natural gas and fuel used	1,509		1,249		260		—
Operations and maintenance	2,305		1,932		392		(19)
Depreciation and amortization	933		549		383		1
Taxes other than income taxes	591		544		56		(9)
Total Operating Expenses	5,338		4,274		1,091		(27)
Operating Income (Loss)	998		890		93		15
Other Income (Expense)
Other (expense) income	121		(15)		155		(19)
Earnings (losses) from equity method investments	3		11		(8)		—
Interest expense, net of capitalization	(310)		(269)		(14)		(27)
Income Before Income Tax	812		617		226		(31)
Income tax expense (benefit)	169		152		28		(11)
Net Income (Loss)	643		465		198		(20)
Net loss (income) attributable to noncontrolling interests	24		(2)		26		—
Net Income (Loss) Attributable to Avangrid, Inc.	$	667	$	463	$	224	$	(20)

(1)Other amounts represent Corporate and intersegment eliminations.

Comparison of Period to Period Results of Operations

Operating revenues increased by 10%, from $6,320 million for the year ended December 31, 2020, to $6,974 million for the year ended December 31, 2021.

Purchased power, natural gas and fuel used increased by 25%, from $1,379 million for the year ended December 31, 2020, to $1,719 million for the year ended December 31, 2021.

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Operations and maintenance increased by 10%, from $2,466 million for the year ended December 31, 2020, to $2,706 million for the year ended December 31, 2021.

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

Year Ended December 31, 2021 Compared to the Year Ended December 31, 2020

Networks

Operating revenues for the year ended December 31, 2021 increased by $566 million, or 11%, from $5,188 million for the year ended December 31, 2020, to $5,754 million. Electricity and gas revenues increased by $125 million, primarily due to the New York rate plan that was approved November 19, 2020, and rate increases in Maine, $19 million favorable impact from a COVID-19 deferral during the period in New York and Connecticut (in Connecticut this is included in the revenue decoupling mechanism), and $11 million favorable impact from transmission. These were offset by a $8 million unfavorable impact from negative revenue adjustments and $1 million of other decreases. Electricity and gas revenues changed due to the following items that have offsets within the income statement: an increase of $364 million in purchased power and purchased gas (offset in purchased power), an increase of $109 million in flow-through amortizations (offset in operating expenses), offset by a decrease of $54 million in flow-through amortizations ($32 million offset in income tax expense and $21 million offset in other income).

Purchased power, natural gas and fuel used for the year ended December 31, 2021 increased by $364 million, or 32%, from $1,125 million for the year ended December 31, 2020, to $1,489 million. The increase is primarily driven by a $364 million increase in average commodity prices and an overall increase in electricity and gas units procured due to higher degree days in the period.

Operations and maintenance during the year ended December 31, 2021 increased by $160 million, or 8%, from $2,038 million for the year ended December 31, 2020, to $2,198 million. The increase is driven by $34 million of increased personnel expenses primarily driven by an increase in headcount, increased business costs of $10 million, a $4 million increase in uncollectible expenses and $3 million unfavorable other. In addition, there were increases of $109 million in flow-through amortizations (which is offset in revenue).

Renewables

Operating revenues for the year ended December 31, 2021 increased by $88 million, or 8% from $1,132 million for the year ended December 31, 2020, to $1,220 million. The increase in operating revenues was primarily due to a $159 million increase in merchant prices driven mainly by higher demand during the Texas storm in the first quarter of 2021, $58 million in favorable thermal and power trading driven by higher average prices in the period, $23 million from curtailment payments, and $15 million from the sale of assets, offset by unfavorable MtM changes of $132 million on energy derivative transactions entered for economic hedging purposes, and a decrease of $35 million driven by 997 GWh lower wind generation output in the current period.

Purchased power, natural gas and fuel used for the year ended December 31, 2021 decreased by $24 million, or 9%, from $254 million for the year ended December 31, 2020, to $230 million. The decrease is primarily due to favorable MtM changes on derivatives of $43 million due to market price changes in the period, offset by an increase of $21 million in power and thermal purchases in the period driven by higher average prices in the period.

Operations and maintenance for the year ended December 31, 2021 increased by $66 million, or 15%, from $429 million for the year ended December 31, 2020, to $495 million. The increase is primarily due to a $6 million increase in the bad debt provision driven mainly by provisions during the Texas storm in the first quarter of 2021, $16 million of higher land rents driven by new sites, $19 million increase driven by higher personnel costs primarily attributable to new capacity, $40 million due to the write-off of certain development projects and casualty losses in the period, offset by a $15 million decrease driven mainly by settlement of liquidated damage claims in the period.

Depreciation, Amortization and Impairment

Depreciation, amortization and impairment expenses for the year ended December 31, 2021 increased by $27 million, or 3%, from $987 million for the year ended December 31, 2020, to $1,014 million. The increase is driven by $42 million from plant additions in Networks and Renewables in the period, offset by a $9 million decrease driven by accelerated depreciation from the repowering of wind farms recorded in the same period of 2020 and $6 million decrease driven by amortization of a deferred gain.

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Other Income and (Expense) and Equity Earnings

Other income and (expense) and equity earnings for the year ended December 31, 2021 increased by $52 million, or 347%, from $15 million for the year ended December 31, 2020, to $67 million. The change is primarily due to a $31 million favorable increase in allowance for equity funds used during construction, a $24 million favorable change in the non-service component of pension expense driven by revised actuarial studies in Networks (which is partially offset within revenue), and $10 million of favorable equity earnings in the period, offset by $11 million of unfavorable carrying charges and $2 million other decreases.

Interest Expense, Net of Capitalization

Interest expense for the year ended December 31, 2021 decreased by $18 million or 6% from $316 million for the year ended December 31, 2020, to $298 million. The change is primarily due to a decrease of $23 million of interest expense at Networks ($16 million of favorable carrying charges and $12 million favorable regulatory amortizations primarily driven by lower regulatory deferrals from the rate case in New York that was approved November 19, 2020, offset by unfavorable $5 million interest expense from increased debt), offset by a $5 million increase in Other due to increased debt.

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the year ended December 31, 2021 was 3.2%, 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 year ended December 31, 2020, was 5.1%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act.

Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019

Networks

Operating revenues for the year ended December 31, 2020 increased by $24 million, or less than 1%, from $5,164 million for the year ended December 31, 2019, to $5,188 million. Electricity and gas revenues increased by $60 million, primarily due to the impact of increased customer rates for the year ended December 31, 2020 compared to the same period of 2019 and increased by $26 million primarily due to make whole period revenue adjustment from new rate case activity in NY. Electricity and gas revenues also increased by $24 million due to higher transmission revenues, negative revenues adjustments in 2019 totaling $16 million related to earnings sharing, net plant reconciliation and other regulatory deferrals and $3 million of other increases. These were offset by a decrease of $10 million from a pension deferral write-off and a $10 million decrease from the inability to charge late payment fees due to regulatory orders. Electricity and gas revenues changed due to the following items that have offsets within the income statement: a decrease of $124 million in purchased power and purchased gas (offset in purchased power), a decrease of $42 million which is offset in income taxes. These were offset by an increase of $69 million of amortizations that are offset in operating expenses and an increase of $12 million in taxes other than income taxes.

Purchased power, natural gas and fuel used for the year ended December 31, 2020 decreased by $124 million, or 10%, from $1,249 million for the year ended December 31, 2019, to $1,125 million. The decrease is primarily driven by a $131 million decrease in average commodity prices and an overall decrease in electricity and gas units procured due to a decline in degree days offset by a $7 million increase in other power supply purchases in the period.

Operations and maintenance during the year ended December 31, 2020 increased by $106 million, or 5%, from $1,932 million for the year ended December 31, 2019, to $2,038 million. The increase is driven by $22 million in increased salaries due to additional headcount offset by favorable capitalized labor, a $10 million increase in outage restoration costs, a $7 million increase in uncollectible expenses, a $6 million increase due to additional cleaning and personal protective equipment resulting from COVID-19, an increase of $69 million in amortizations (which are offset in revenue) and a $2 million increase in Other. These were offset by a decrease of $5 million in unfavorable write-off of deferred storm costs in the year ended December 31, 2019, which did not recur in 2020 and a decrease of $5 million in favorable overhead.

Renewables

Operating revenues for the year ended December 31, 2020 decreased by $52 million, or 4% from $1,184 million for the year ended December 31, 2019, to $1,132 million. The decrease in operating revenues was primarily due to unfavorable MtM changes of $69 million on energy derivative transactions entered for economic hedging purposes, a decrease of $26 million in

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merchant pricing, a $34 million decrease in thermal revenue driven by lower volumes and average prices in the period, and a $7 million decrease in other revenues (offset in operating expenses). These were offset by an increase of $85 million driven by wind generation output increase of 1,790 GWh from existing and new capacity in the current period.

Purchased power, natural gas and fuel used for the year ended December 31, 2020 decreased by $6 million, or 2%, from $260 million for the year ended December 31, 2019, to $254 million. The decrease is primarily driven by a decrease of $28 million in thermal purchases driven by the decrease in volume and unit cost in the period, offset by an increase of $5 million in power purchases, $5 million in RECs and unfavorable MtM changes on derivatives of $11 million due to market price changes in the period.

Operations and maintenance for the year ended December 31, 2020 increased by $37 million or 9% from $392 million for the year ended December 31, 2019, to $429 million. The increase is primarily due to $36 million of increased costs resulting from higher personnel and maintenance costs, which are primarily attributed to new capacity. Additionally, operations and maintenance expense increased by $11 million driven by a favorable asset retirement obligation adjustment in 2019, offset by a $3 million decrease due to a favorable provision release in the year ended December 31, 2020, and $7 million in lower other expenses (offset in operating revenues).

Depreciation, Amortization and Impairment

Depreciation, amortization and impairment expenses for the year ended December 31, 2020 increased by $54 million or 6% from $933 million for the year ended December 31, 2019, to $987 million. The increase is driven by $71 million from plant additions in Networks and Renewables in the period, an increase in lease amortizations of $3 million and a $4 million increase due to a favorable asset retirement obligation adjustment for the year ended December 31, 2019, offset by a $24 million decrease of accelerated depreciation from the repowering of wind farms in Renewables.

Other Income and (Expense) and Equity Earnings

Other income and (expense) and equity earnings for the year ended December 31, 2020 decreased by $109 million, or 88%, from $124 million for the year ended December 31, 2019, to $15 million. The decrease is primarily due to a $134 million gain from the sale of assets in Renewables recorded in 2019 and $6 million of unfavorable equity earnings in the period, offset by a $20 million gain from the sale of assets in the year ended December 31, 2020 in Renewables and Networks and an $11 million penalty incurred in the same period of 2019 in Networks.

Interest Expense, Net of Capitalization

Interest expense for the year ended December 31, 2020 increased by $6 million or 2% from $310 million for the year ended December 31, 2019, to $316 million. Networks had an $18 million decrease in carrying costs on regulatory deferrals during the period. Renewables interest expense decreased by $5 million due to lower average debt balances in the current period. This is offset by an interest expense increase in Other of $28 million primarily from new debt issued in 2020 and 2019.

Income Tax Expense

The effective tax rate, inclusive of federal and state income tax, for the year ended December 31, 2020 was 5.1%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and the effect of the excess deferred tax amortization resulting from the Tax Act. The effective tax rate, inclusive of federal and state income tax, for the year ended December 31, 2019, was 20.8%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits associated with wind production and favorable discrete tax adjustments.

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.

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We define adjusted net income as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments, accelerated depreciation derived from repowering of wind farms, costs incurred related to the PNMR Merger, a legal settlement 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 years ended December 31, 2021, 2020 and 2019, respectively:

	Year Ended December 31, 2021
	Total		Networks		Renewables		Corporate *
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	707	$	636	$	131	$	(60)
Adjustments:
Mark-to-market adjustments - Renewables	53		—		53		—
Restructuring charges	—		—		—		—
Impact of COVID-19	34		34		—		—
Merger costs	12		—		—		12
Income tax impact of adjustments (1)	(26)		(9)		(14)		(3)
Adjusted Net Income (2)	$	780	$	661	$	170	$	(51)
Net (loss) income attributable to noncontrolling interests	(64)		3		(67)		—
Income tax (benefit) expense	47		107		(34)		(26)
Depreciation and amortization	1,014		616		397		1
Interest expense, net of capitalization	298		217		1		80
Other (income) expense	(60)		(66)		4		2
Losses (earnings) from equity method investments	(7)		(12)		5		—
Adjusted EBITDA (3)	$	2,008	$	1,526	$	476	$	7
Retained PTCs and ITCs	175		—		175		—
PTCs allocated to tax equity investors	80		—		80		—
Adjusted EBITDA with Tax Credits (3)	$	2,263	$	1,526	$	731	$	7

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	Year Ended December 31, 2020
	Total		Networks		Renewables		Corporate *
	(in millions)
Net Income Attributable to Avangrid, Inc.	$	581	$	546	$	103	$	(67)
Adjustments:
Mark-to-market adjustments - Renewables	5		—		5		—
Restructuring charges	6		5		1		—
Accelerated depreciation from repowering	9		—		9		—
Impact of COVID-19	29		26		1		2
Merger costs	6		—		—		6
Legal settlement - Gas storage	5		—		—		5
Income tax impact of adjustments (1)	(16)		(8)		(4)		(3)
Adjusted Net Income (2)	$	625	$	568	$	115	$	(58)
Net (loss) income attributable to noncontrolling interests	(42)		2		(44)		—
Income tax (benefit) expense	45		128		(76)		(8)
Depreciation and amortization	978		592		385		1
Interest expense, net of capitalization	316		234		7		75
Other (income) expense	(18)		(15)		(15)		12
Losses (earnings) from equity method investments	3		(10)		13		—
Adjusted EBITDA (3)	$	1,907	$	1,499	$	385	$	23
Retained PTCs and ITCs	153		—		153		—
PTCs allocated to tax equity investors	63		—		63		—
Adjusted EBITDA with Tax Credits (3)	$	2,123	$	1,499	$	601	$	23

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	Year Ended December 31, 2019
	Total		Networks		Renewables		Corporate *
	(in millions)
Net Income (Loss) Attributable to Avangrid, Inc.	$	667	$	463	$	224	$	(20)
Adjustments:
Mark-to-market adjustments - Renewables	(76)		—		(76)		—
Restructuring charges	6		3		1		3
Accelerated depreciation from repowering	33		—		33		—
Income tax impact of adjustments (1)	10		(1)		11		(1)
Adjusted Net Income (2)	$	640	$	465	$	193	$	(17)
Net (loss) income attributable to noncontrolling interests	(24)		2		(26)		—
Income tax (benefit) expense	159		153		17		(10)
Depreciation and amortization	900		549		350		1
Interest expense, net of capitalization	310		269		14		27
Other (income) expense	(121)		15		(155)		19
Losses (earnings) from equity method investments	(3)		(11)		8		—
Adjusted EBITDA (3)	$	1,861	$	1,442	$	400	$	19
Retained PTCs and ITCs	125		—		125		—
PTCs allocated to tax equity investors	33		—		33		—
Adjusted EBITDA with Tax Credits (3)	$	2,020	$	1,442	$	559	$	19

(1)Income tax impact of adjustments: For the year ended December 31, 2021, $14 million from MtM adjustment, $9 million from COVID-19 impacts and $3 million from merger costs. For the year ended December 31, 2020, $(1) million from MtM adjustment, $(2) million from accelerated depreciation, $(2) million from restructuring charges, $(8) million from COVID-19 impacts, $(1) million from legal settlement - gas storage and $(2) million from merger costs. For the year ended December 31, 2019, $20 million from MtM adjustment, $(9) million from accelerated depreciation, $(2) million from restructuring charges.

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

(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.

Comparison of Period to Period Results of Operations

Year Ended December 31, 2021 Compared to the Year Ended December 31, 2020

Adjusted net income

Adjusted net income increased by $155 million, or 25%, from $625 million for the year ended December 31, 2020 to $780 million for the year ended December 31, 2021. The increase is primarily due to a $93 million increase in Networks driven primarily by a new rate plan in New York that was approved on November 19, 2020, a $55 million increase in Renewables driven by higher merchant pricing mainly from the Texas weather event and a $7 million increase in Corporate mainly driven by favorable tax expense in the period.

Year Ended December 31, 2020 Compared to the Year Ended December 31, 2019

Adjusted net income

Adjusted net income decreased by $15 million, or 2%, from $640 million for the year ended December 31, 2019 to $625 million for the year ended December 31, 2020. The decrease is primarily due to a $77 million decrease in Renewables as a result of gain from the sale of assets in 2019 that did not recur in 2020, a $41 million decrease in Corporate mainly driven by higher interest expenses in the period, offset by $103 million increase in Networks driven primarily by approved rate cases in the period.

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The following tables reconcile Net Income attributable to AVANGRID to Adjusted Net Income (non-GAAP), and EPS attributable to AVANGRID to adjusted EPS (non-GAAP) for the years ended December 31, 2021, 2020 and 2019, respectively:

	Year Ended December 31,
	2021		2020		2019
	(in millions)
Networks	$	636	$	546	$	463
Renewables	131		103		224
Corporate (1)	(60)		(67)		(20)
Net Income	707		581		667
Adjustments:
Mark-to-market adjustments - Renewables (2)	53		5		(76)
Restructuring charges (3)	—		6		6
Accelerated depreciation from repowering (4)	—		9		33
Impact of COVID-19 (5)	34		29		—
Merger costs (6)	12		6		—
Legal settlement - Gas storage (7)	—		5		—
Income tax impact of adjustments	(26)		(16)		10
Adjusted Net Income (8)	$	780	$	625	$	640

	Year Ended December 31,
	2021		2020		2019
Networks	$	1.78	$	1.76	$	1.50
Renewables	0.37		0.33		0.72
Corporate (1)	(0.17)		(0.22)		(0.06)
Earnings Per Share	1.97		1.88		2.16
Adjustments:
Mark-to-market adjustments - Renewables (2)	0.15		0.02		(0.25)
Restructuring charges (3)	—		0.02		0.02
Accelerated depreciation from repowering (4)	—		0.03		0.11
Impact of COVID-19 (5)	0.10		0.09		—
Merger costs (6)	0.03		0.02		—
Legal settlement - Gas storage (7)	—		0.01		—
Income tax impact of adjustments	(0.07)		(0.05)		0.03
Adjusted Earnings Per Share (8)	$	2.18	$	2.02	$	2.07

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

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

(3)Restructuring and severance related charges relate to costs resulting from restructuring actions involving initial targeted voluntary workforce reductions and related costs in our plan to vacate a lease, predominantly within the Networks segment and costs to implement an initiative to mitigate costs and achieve sustainable growth.

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

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

(6)Pre-merger costs incurred.

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

(8)Adjusted Net Income and Adjusted Earnings Per Share are non-GAAP financial measures and are presented after excluding restructuring charges, accelerated depreciation derived from the repowering wind farms, MtM activities in Renewables, costs incurred related to the PNMR Merger, a legal settlement and costs incurred in connection with the COVID-19 pandemic.

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, equity issuances and borrowings in the investment grade debt capital markets. Continued access to these

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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.

Liquidity

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. At December 31, 2021, we had cash and cash equivalents of $1,474 million, as compared to $1,463 million at December 31, 2020. 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.

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 December 31, 2021 and February 22, 2022, there was $0 and $287 million, respectively, of outstanding amount under the commercial paper program.

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 contains a commitment from lenders, which will expire on April 20, 2022 if not terminated by AVANGRID at an earlier date 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 December 31, 2021, we had no borrowings outstanding under this credit facility.

Since the AVANGRID credit facility is also a backstop to the AVANGRID commercial paper program, the total amount available under the facility as of December 31, 2021 and February 22, 2022, was $3,575 million and $3,288 million, respectively.

2020 Credit Facility

During 2020, we entered into a revolving credit agreement with several lenders, or the 2020 Credit Facility, that provides maximum borrowings up to $500 million. We terminated this facility on April 28, 2021.

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 December 31, 2021 and February 22, 2022, there was no outstanding amount under this credit facility.

Supplier Financing Arrangements

To manage cash flow and related liquidity, we operate a supplier financing arrangement under which certain suppliers can obtain accelerated settlement on invoices from the banking provider. This is a form of reverse factoring which has the objective of serving the group's suppliers by giving them early access to funding. This supplier financing program allows participating suppliers the ability to voluntarily elect to sell our payment obligations to a designated third-party financial institution. We have no economic interest in a supplier’s decision to enter into the arrangements. Our obligations to our suppliers, including amounts due and scheduled payment terms, are not impacted by our suppliers’ decisions to sell amounts under these arrangements. As of December 31, 2021, $161 million of these arrangements are classified as notes payable on our consolidated balance sheet.

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Group Cash Pool

We are a party to a liquidity agreement with Bank of America, N.A. along with certain members of the Iberdrola Group. The liquidity agreement aids the Iberdrola Group in efficient cash management and reduces the need for external borrowing by the pool participants. Parties to the agreement, including us, may deposit funds with or borrow from the financial institution, provided that the net balance of funds deposited or borrowed by all pool participants in the aggregate is not less than zero. As of both December 31, 2021 and 2020, the balance was $0. Any deposit amounts would be reflected in our consolidated balance sheets under cash and cash equivalents because our deposited surplus funds under the cash pooling agreement are highly-liquid short-term investments.

Off-Balance Sheet Arrangements

At December 31, 2021, we had approximately $4,820 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, which includes guarantees of our own performance. These instruments provide financial assurance to the business and trading partners of AVANGRID and its subsidiaries in their normal course of business. The instruments only represent liabilities if AVANGRID or its subsidiaries fail to deliver on contractual obligations. We therefore believe it is unlikely that any material liabilities associated with these instruments will be incurred and, accordingly, as of December 31, 2021, neither we nor our subsidiaries have any liabilities recorded for these instruments.

Long-Term Capital Resources

We expect to meet our long-term capital requirements through the use of our cash balances, credit facilities, cash from operations, long-term borrowings and new equity capital. We have investment grade ratings from Standard and Poor’s, Moody’s and Fitch and we believe that we can raise capital on competitive terms in the investment grade debt capital and/or bank markets.

Iberdrola Loan

On December 14, 2020, AVANGRID and Iberdrola entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid with the proceeds of the common share issuance described in Note 1 - Background and Nature of Operations.

Our other long-term debt issuances during 2021 were as follows:

Company	Issue Date	Type	Amount (Millions)		Interest rate		Maturity
NYSEG	9/24/2021	Unsecured Notes	$	350	2.15	%	2031
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.91%		2051
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.10	%	2031
CMP	12/15/2021	First Mortgage Bonds	$	200	2.05	%	2031
SCG	12/15/2021	First Mortgage Bonds	$	40	2.05	%	2031

At December 31, 2021, Networks had $6,229 million of debt, including the current portion thereof, consisting of first mortgage bonds, senior unsecured notes, tax-exempt bonds and various other forms of debt. Networks' regulated utilities are required by regulatory order to maintain a minimum ratio of common equity to total capital that is tied to the capital structure used in the establishment of their revenue requirements. Pursuant to these requirements, each of NYSEG, RG&E, CMP and MNG must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis, each utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. UI, SCG, CNG and BGC are restricted from paying dividends if paying such dividend would result in their respective common equity ratio being lower than 300 basis points below the equity percentage used to set rates in the most recent distribution rate proceeding as measured using a trailing 13-month average calculated as of the most recent quarter end. The regulated utilities periodically pay dividends to, or receive capital contributions from, AVANGRID in order to maintain the minimum equity ratio requirement. They each independently incur indebtedness by issuing investment grade debt securities. Networks’ regulated utilities were in compliance with these regulatory orders as of December 31, 2021.

At December 31, 2021, we had a $45 million finance lease liability outstanding in the Renewables segment relating to a sale-leaseback arrangement on a solar generation facility. Renewables has also sourced capital through tax equity financing arrangements associated with certain wind farm projects. The arrangements allocate substantially all of the projects' taxable income and PTCs to the tax equity investor, along with a percentage of cash generated by the projects, in exchange for investor contributions. On September 9, 2021, we sold an additional TEF interest in Aeolus VII for $131 million. The $8 million

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difference between the amount received and the $139 million noncontrolling interest recognized was recorded as an adjustment to equity because there was no change in control as a result of the transaction. On November 4, 2021, we sold a TEF interest in Aeolus Wind Power VIII, LLC (Aeolus VIII) for $199 million, of which $8 million is held in escrow until certain conditions are met.

At December 31, 2021, corporate had $2,065 million of long-term debt, including the current portion thereof, outstanding. Long-term debt in corporate consists mainly of $600 million of 3.15% notes due in 2024, $750 million of 3.20% notes due in 2025 and $750 million of 3.80% notes due in 2029.

In our credit facilities, long-term borrowings, financing leases and tax-equity partnerships, we and our affiliates that are parties to the agreements are subject to covenants that are standard for such agreements. Affirmative covenants impose certain obligations on the borrower and negative covenants limit certain activities by the borrower. The agreements also define certain events of default, including but not limited to non-compliance with the covenants that may automatically in some circumstances, or at the option of the lenders in other circumstances, trigger acceleration of the obligations. We and our affiliates were in compliance with all such covenants at December 31, 2021 and throughout 2021.

Capital Requirements

Funding Future Common Dividend Payments

Funding of our dividend payments is considered in the context of our overall operating and investment cash flows and our long-term funding. 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 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.

Capital Expenditures

The regulated utilities’ capital expenditures over the last three years have been as follows:

	2021		2020		2019
	(in millions)
NYSEG	$	743	$	689	$	574
RG&E	394		387		379
CMP*	682		389		299
MNG	4		3		7
UI	186		204		192
SCG	86		88		83
CNG	63		60		60
BGC	17		17		19
Corporate	55		23		10
Total	$	2,230	$	1,860	$	1,623

*Includes NECEC Transmission LLC’s capital expenditures in the NECEC project.

Networks increased its capital expenditures during the period from 2019 to 2021 to upgrade and expand electricity and natural gas transmission and distribution infrastructure. In 2021, we continued capital investments in a number of programs in Maine, including NECEC, substation modernization and new transmission investments. NYSEG and RG&E continued their capital investments in a number of programs, including the grid automation project, pole replace program, distribution line project, Binghamton Area Brightline, or BES, program. In 2020, NYSEG and RG&E continued their capital investments in a

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number of programs, including the grid automation project, distribution line project, FERC compliance programs, Rochester Area Reliability Project, or RARP, and Gas Distribution Mains and Leak Prone Main replacement project.

Renewables’ capital expenditures for the years set forth below were as follows:

	2021		2020		2019
	(in millions)
Wind & solar	$	928	$	822	$	1,281
Thermal	18		8		7
Corporate (1)	12		15		13
Other capitalized costs (2)	106		39		54
Total capital expenditures	$	1,064	$	884	$	1,355

(1)Includes information technology and facilities and safety (security).

(2)Includes capitalized interests, labor and other costs.

In 2021, Renewables made capital expenditures of $928 million on construction of Lundhill Solar, Bakeoven Solar, Montague Solar, La Joya, Golden Hills, Midland and other wind and solar assets and $18 million in capital expenditures on the Klamath gas-fired cogeneration facility, or the Klamath Plant.

In 2020, Renewables made capital expenditures of $822 million on construction of La Joya, Tatanka Ridge, Roaring Brook, Golden Hills and other wind and solar assets and $8 million in capital expenditures on the Klamath gas-fired cogeneration facility, or the Klamath Plant.

In 2019, Renewables made capital expenditures of $1.2 billion on construction of Otter Creek, Karankawa, Montague, Tatanka Ridge and other wind and solar assets as well as the acquisition of Patriot Wind, $7 million in capital expenditures on the Klamath Plant, $15 million on improvements to operating wind assets and $31 million in development costs.

Capital Projects

An important part of our business strategy involves capital projects. Networks plans to invest a total of approximately $10.3 billion from 2022 to 2026 to upgrade and expand electricity and natural gas transmission and distribution infrastructure. In the next 12 months, Networks plans to invest $285 million in Maine, including Distribution Line Inspection Repairs Program, Transmission Line Asset Condition Replacements Program, Substation Modernization Program, Storm Resiliency Program and Grid Automation. MEPCO plans to invest $13 million in the next 12 months primarily on the Strategic Rebuild of Transmission Structures. NYSEG plans to invest $776 million in the next 12 months, including Advanced Meter Infrastructure Project, BES Program, Distribution Line Inspection Repairs Program, Grid Automation Program, Transmission Line Asset Condition Replacements Program, Storm Resiliency Program, Make Ready, Pole Replacement Program and Gas Distribution Mains and Leak Prone Main replacements. RG&E plans to invest $379 million in the next 12 months, including Advanced Meter Infrastructure Project, BES Program, Webster Area Reliability Program, Pole Replacement Program, Grid Automation Program, Storm Resiliency Program, Gas Distribution Mains and Leak Prone Main Replacement programs. UIL plans to invest $425 million in the next 12 months, including a number of programs and projects related to improvement of system operations, reliability and resiliency, replacement of aging infrastructure, and new customer connections. For gas operations, the most notable investments include distribution main replacements, leak prone replacements, the connection of new customers, and infrastructure improvements.

Renewables plans to invest at least a total of approximately $16.9 billion from 2022 to 2026 and add at least approximately 7,800 MW of onshore and offshore generation capacity.

We expect to fund these capital projects through a combination of cash provided by operations and access to the capital markets, including debt borrowings at either the subsidiary or holding company level and equity issuances as needed. Additionally, we have revolving credit facilities, as described above, to fund short-term liquidity needs.

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.

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The following is a summary of the cash flows by activity for the years ended December 31, 2021, 2020 and 2019, respectively:

	Year Ended December 31,
	2021		2020		2019
	(in millions)
Cash Flows
Net cash provided by operating activities	$	1,561	$	1,288	$	1,588
Net cash used in investing activities	(2,440)		(2,858)		(2,708)
Net cash provided by financing activities	889		2,853		1,261
Net increase in cash, cash equivalents and restricted cash	$	10	$	1,283	$	141

Operating Activities

Our primary sources of operating cash inflows are proceeds from transmission and distribution of electricity and natural gas and sales of wholesale energy and energy related products and services. Our primary operating cash outflows are power and natural gas purchases and transmission operating and maintenance expenses, as well as personnel costs and other employee-related expenditures. As our business has expanded, our working capital requirements have grown. We expect our working capital to grow as we continue to grow our business.

The cash from operating activities for the year ended December 31, 2021 compared to the year ended December 31, 2020 increased by $273 million, primarily attributable to higher operating revenues in the period.

The cash from operating activities for the year ended December 31, 2020 compared to the year ended December 31, 2019 decreased by $300 million, primarily attributable to higher operations and maintenance expenses including from storm and other activities, delays in the timing of the approval of the 2020 Joint Proposal and increased overdue receivables as a result of COVID-19 in Networks.

The cash from operating activities for the year ended December 31, 2019 compared to the year ended December 31, 2018 decreased by $193 million, primarily attributable to higher operations and maintenance expenses and cash interest paid in the period.

Investing Activities

Our investing activities have primarily focused on enhancing, automating and reinforcing our asset base to support safety, reliability and customer growth in accordance with the regulatory markets within which we operate, as well as constructing solar and wind assets.

In 2021, net cash used in investing activities was $2,440 million, which was comprised of $2,976 million of capital expenditures, partially offset by $222 million of other investments and equity method investments, $155 million of distributions received from equity method investments, $130 million of contributions in aid of construction and $24 million of proceeds from the sale of assets.

In 2020, net cash used in investing activities was $2,858 million, which was comprised of $2,781 million of capital expenditures and $370 million of other investments and equity method investments, partially offset by $48 million of contributions in aid of construction and $238 million of proceeds from the sale of assets.

In 2019, net cash used in investing activities was $2,708 million, which was comprised of $2,735 million of capital expenditures and $176 million of other investments and equity method investments, partially offset by $74 million of contributions in aid of construction and $126 million of proceeds from the sale of assets.

Financing Activities

Our financing activities have consisted of raising equity, using our credit facilities and long-term debt issued or redeemed by AVANGRID and our regulated Networks subsidiaries.

In 2021, financing activities provided $889 million in cash reflecting primarily $4 billion in proceeds from private placements of equity in connection with share issuance, an issuance of non-current debt at our regulated subsidiaries with the net proceeds of $833 million and contribution from non-controlling interests, principally related to TEFs, of $330 million in the period, offset by a net decrease in non-current debt, including with affiliate, and current notes payable of $3.6 billion, dividends of $613 million and distributions to non-controlling interests of $10 million.

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In 2020, financing activities provided $2,853 million in cash reflecting primarily an issuance of non-current debt at AVANGRID and our regulated subsidiaries with the net proceeds of $1,367 million, receipt of the Iberdrola Loan of $3,000 million and tax equity financing contributions from non-controlling interests, principally related to TEFs, of $312 million, offset by a net decrease in non-current debt and current notes payable of $1,264 million, distributions to non-controlling interests of $5 million, payments on capital leases of $9 million and dividends of $545 million.

In 2019, financing activities used $1,261 million in cash reflecting primarily an issuance of non-current debt at AVANGRID and our regulated subsidiaries with the net proceeds of $2,137 million and tax equity financing contributions from non-controlling interests, principally related to TEFs, of $133 million, offset by a net decrease in non-current debt and current notes payable of $374 million, distributions to non-controlling interests of $63 million, payments on capital leases of $27 million and dividends of $545 million.

Contractual Obligations

As of December 31, 2021, our contractual obligations (excluding any tax reserves) were as follows:

	Total		2022		2023		2024		2025		2026		Thereafter
	(in millions)
Leases (1)	$	475	$	19	$	67	$	35	$	13	$	13	$	327
Easements (2)	1,063		29		27		29		31		30		917
Projected future pension benefit plan contributions (3)	76		34		31		4		3		4		—
Long-term debt (including current maturities) (4)	8,294		372		439		612		1,107		660		5,104
Interest payments (5)	3,216		296		279		287		246		247		1,861
Material purchase commitments (6)	1,369		1,039		141		82		34		19		54
Total Contractual Obligations	$	14,493	$	1,789	$	984	$	1,049	$	1,434	$	973	$	8,263

(1)Represents lease contracts relating to operational facilities, office building leases and vehicle and equipment leases. These amounts represent our expected unadjusted portion of the costs to pay as amounts related to contingent payments are predominantly linked to electricity generation at the respective facilities.

(2)Represents easement contracts which are not classified as leases.

(3)The qualified pension plans’ contributions are generally based on the estimated minimum pension contributions required under the Employee Retirement Income Sensitivity Act of 1974, as amended, and the Pension Protection Act of 2006, as well as contributions necessary to avoid benefit restrictions and at-risk status and agreements with state regulatory agencies. These amounts represent estimates that are based on assumptions that are subject to change. The minimum required contributions for years after 2026 are not included as projections beyond 2026 are not available.

(4)See debt payment discussion in “Long-term Capital Resources.”

(5)Interest payments are estimated based on final maturity dates of debt securities outstanding at December 31, 2021, and do not reflect anticipated future refinancing, early redemptions or debt issuances. Variable rate interest obligations are estimated based on rates as of December 31, 2021.

(6)Represents forward purchase commitments under power, gas and other arrangements and contractual obligations for material and services on order but not yet delivered at December 31, 2021.

Critical Accounting Policies and Estimates

We have prepared the financial statements provided herein in accordance with U.S. GAAP and they include the accounts of AVANGRID and its consolidated subsidiaries. We describe our significant accounting policies in Note 3 to the consolidated financial statements.

In preparing the accompanying financial statements, our management has made certain estimates and assumptions that affect the reported amounts of assets, liabilities, shareholder’s equity, revenues and expenses and the disclosures thereof. The following accounting policies represent those that management believes are particularly important to the consolidated financial statements and that require the use of estimates, assumptions and judgments to determine matters that are inherently uncertain.

Accounting for Regulated Public Utilities

U.S. GAAP allows regulated entities to give accounting recognition to the actions of regulatory authorities. We must meet certain criteria in order to apply such regulatory accounting treatment and record regulatory assets and liabilities. In determining whether we meet the criteria for our operations, our management makes significant judgments, which involve (i) determining whether rates for services provided to customers are subject to approval by an independent, third-party regulator, (ii) determining whether the regulated rates are designed to recover specific costs of providing the regulated service, (iii) considering relevant historical precedents and recent decisions of the regulatory authorities and (iv) considering the fact that decisions made by regulatory commissions or legislative changes at a later date could vary from earlier interpretations made by management and that the impact of such variations could be material. Our regulated subsidiaries have deferred

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recognition of costs (a regulatory asset) or have recognized obligations (a regulatory liability) if it is probable that such costs will be recovered or obligations relieved in the future through the ratemaking process. Management regularly reviews our regulatory assets and liabilities to determine whether we need to make adjustments to our previous conclusions based on the current regulatory environment as well as recent rate orders. If our regulated subsidiaries, or a portion of their assets or operations, were to cease meeting the criteria for application of these accounting rules, accounting standards for unregulated businesses in general would become applicable and immediate recognition of any previously deferred costs would be required in the year in which such criteria are no longer met.

Accounting for Pensions and Other Post-Retirement Benefits

We provide pensions and other post-retirement benefits for a significant number of employees, former employees and retirees. We account for those benefits in accordance with the accounting rules for retirement benefits. In accounting for our pension and other post-retirement benefit plans, or the AVANGRID plans, we make assumptions regarding the valuation of benefit obligations and the performance of plan assets. The primary assumptions include the discount rate, the expected long-term return on plan assets, health care cost trend rates, mortality assumptions, demographic assumptions and other factors. We apply consistent estimation techniques regarding our actuarial assumptions, where appropriate, across the AVANGRID plans of our operating subsidiaries. The estimation technique we use to develop the discount rate for the AVANGRID plans is based upon the settlement of such liabilities as of December 31, 2021, using a hypothetical portfolio of actual, high quality bonds, that would generate cash flows required to settle the liabilities. We believe such an estimate of the discount rate accurately reflects the settlement value for plan obligations and results in cash flows that closely match the expected payments to participants. The estimation technique we use to develop the long-term rate of return on plan assets is based on a projection of the long-term rates of return on plan assets that will be earned over the life of the plan, including considerations of investment strategy, historical experience and expectations for long-term rates of return.

The weighted-average discount rates used in accounting for qualified pension obligations in 2021 was 2.34%, representing a decrease of 67 basis points from 2020. The expected rate of return on plan assets for qualified pension benefits in 2021 was 7.30%, consistent with 2020. The following table reflects the estimated sensitivity associated with a change in certain significant actuarial assumptions (each assumption change is presented mutually exclusive of the other assumption changes):

		Impact on 2021 Pension Expense Increase (Decrease)
	Change in Assumption	Pension Benefits		Post Retirement Benefits
		(in millions)
Increase in discount rate	50 basis points	$	(19)	$	(2)
Decrease in discount rate	50 basis points	$	19	$	2
Increase in return on plan assets	50 basis points	$	(15)	$	(1)
Decrease in return on plan assets	50 basis points	$	15	$	1

We reflect unrecognized prior service costs and credits and unrecognized actuarial gains and losses for the regulated utilities of Networks as regulatory assets or liabilities if it is probable that such items will be recovered through the ratemaking process in future periods. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss.

Business Combinations and Assets Acquisitions

We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. For material transactions where valuations require significant assumptions and judgements, we utilize independent third-party valuation specialists and review their work prior to recording the transaction.

In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. Similar to business combinations, we may utilize third-party valuation specialists for material asset transactions that require significant judgement in the valuation process.

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Goodwill

Goodwill is not amortized, but is subject to an assessment for impairment performed in the fourth quarter or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit to which goodwill is assigned below its carrying amount. A reporting unit is an operating segment or one level below an operating segment and is the level at which we test goodwill for impairment.

In assessing goodwill for impairment, we have the option to first perform a qualitative assessment to determine whether a quantitative assessment is necessary. If we determine, based on qualitative factors, that the fair value of the reporting unit is more likely than not greater than the carrying amount, no further testing is required. If we bypass the qualitative assessment, or perform the qualitative assessment but determine it is more likely than not that its fair value is less than its carrying amount, we perform a quantitative test to compare the fair value of the reporting unit to its carrying amount, including goodwill. If the carrying amount of the reporting unit exceeds its fair value, we record an impairment loss as a reduction to goodwill and a charge to operating expenses, but the loss recognized would not exceed the total amount of goodwill allocated to the reporting unit. For 2021, we utilized a qualitative assessment for the Networks reporting units and a quantitative assessment for the Renewables reporting unit.

Our qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events, and events affecting a reporting unit.

Our quantitative assessment utilizes a discounted cash flow model under the income approach and includes critical assumptions, primarily the discount rate and internal estimates of forecasted cash flows. We use a discount rate that is developed using market participant assumptions, which consider the risk and nature of the respective reporting unit’s cash flows and the rates of return market participants would require in order to invest their capital in our reporting units. We test the reasonableness of the conclusions of our quantitative impairment testing using a range of discount rates and a range of assumptions for long-term cash flows.

Impairment of Long-Lived Assets

We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. If indicators of impairment are present, a recoverability test is performed based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. An impairment loss is required to be recognized if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset. The impairment loss to be recognized is the amount by which the carrying value of the long-lived asset exceeds the asset’s fair value.

We determine the fair value of a long-lived asset by applying the income approach prescribed under the fair value measurement accounting framework. We develop the underlying assumptions consistent with a market participant’s view of the exit price of our assets. We use an internal discounted cash flow, or DCF, valuation model based on the principles of present value techniques to estimate the fair value of our long-lived assets under the income approach. The DCF model estimates fair value by discounting AVANGRID’s cash flow forecasts at an appropriate market discount rate. Management applies a considerable amount of judgment in the estimation of the discount rate used in the DCF model and in selecting several input assumptions during the development of our cash flow forecasts. Examples of the input assumptions that our forecasts are sensitive to include macroeconomic factors such as growth rates, industry demand, inflation, power prices and commodity prices. Many of these input assumptions are dependent on other economic assumptions, which are often derived from statistical economic models with inherent limitations such as estimation differences. Further, several input assumptions are based on historical trends which often do not recur. The input assumptions that include significant unobservable inputs most significant to our cash flows are based on expectations of macroeconomic factors, which may be volatile. The use of a different set of input assumptions could produce significantly different cash flow forecasts.

The fair value of a long-lived asset is sensitive to both input assumptions related to our cash flow forecasts and the market discount rate. Further, estimates of long-term growth and terminal value are often critical to the fair value determination. As part of the impairment evaluation process, management analyzes the sensitivity of fair value to various underlying assumptions. The level of scrutiny increases as the gap between fair value and carrying amount decreases. Changes in any of these assumptions could result in management reaching a different conclusion regarding the potential impairment, which could be material. Our impairment evaluations inherently involve uncertainties from uncontrollable events that could positively or negatively impact the anticipated future economic and operating conditions.

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Income Taxes

AVANGRID files a consolidated federal income tax return and various state income tax returns, some of which are unitary as required or permitted.

Our income tax expense and related balance sheet amounts involve management judgment and use of estimates. Amounts of deferred income tax assets and liabilities, current and noncurrent accruals, and determination of uncertain tax positions involve judgements and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In making these judgements, we consider the status of any income tax examinations that are in progress, historical resolutions of tax issues, positions taken by the taxing authorities on similar issues with other taxpayers, among other criteria. Our actual income taxes could vary from estimated amounts because of the actual resolution of tax issues, forecasts of financial condition and changes in tax laws and regulations.

Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. The term more-likely-than-not means a likelihood of more than 50%. We use judgement to determine when a tax position reaches this threshold.

Our assessment regarding the realizability of deferred tax assets involves judgements and estimates including the impact of forecasted taxable income and tax planning strategies to utilize tax attributes before they expire.

New Accounting Standards

For discussion of new accounting pronouncements that affect AVANGRID, refer to Note 3 to our consolidated financial statements contained in this Annual Report on Form 10-K.

Item 7A. Quantitative and Qualitative Disclosures About Market Risk.

We are exposed to risks associated with adverse changes in commodity prices, interest rates and equity prices. Financial instruments and positions affecting our financial statements described below are held primarily for purposes other than trading. Market risk is measured as the potential loss in fair value resulting from hypothetical reasonably possible changes in commodity prices, interest rates or equity prices over the next year. Management has established risk management policies to monitor and manage such market risks, as well as credit risks.

Commodity Price Risk

Renewables faces a number of energy market risk exposures, including fixed price, basis (both location and time) and heat rate risk.

Long-term supply contracts reduce our exposure to market fluctuations. We have electricity commodity purchases and sales contracts for energy (physical contracts) that have been designated and qualify for the normal purchase normal sale exemption in accordance with the accounting requirements concerning derivative instruments and hedging activities.

Renewables merchant wind facilities are subject to price risk, which is hedged with fixed price power trades. Our combined cycle power plant is subject to heat rate risk, which is hedged with fixed price power and fixed price gas and basis positions. Those measures mitigate our commodity price exposure, but do not completely eliminate it. Some long-term hedges do not qualify for hedge accounting. This introduces some MtM volatility into yearly profit and loss accounts.

Renewables uses a Monte Carlo simulation value-at-risk, or VaR, technique to measure and control the level of risk it undertakes. VaR is a statistical technique used to measure and quantify the level of risk within a portfolio over a given timeframe and within a specified level of confidence. VaR is primarily composed of three variables: the measured amount of potential loss, the probability of not exceeding the amount of potential loss and the portfolio holding period.

Renewables uses a 95% probability level over a one-day holding period, indicating that it can be 95% confident that losses over one day would not exceed that value. The average VaR for 2021 was $11.3 million compared to a 2020 average of $7.5 million.

As noted above, VaR is a statistical technique and is not intended to be a guarantee of the maximum loss Renewables may incur.

Networks also experiences commodity price risk, due to volatility in the wholesale energy markets. Networks manages that risk through a combination of regulatory mechanisms, such as the pass-through of the market price of electricity and natural gas to customers, and through comprehensive risk management processes. Those measures mitigate our commodity price exposure, but do not completely eliminate it. Networks also uses electricity contracts as deemed appropriate, both physical

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and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. It also uses natural gas futures and forwards to manage fluctuations in natural gas commodity prices in order to provide price stability to customers. It includes the cost or benefit of those contracts in the amount expensed for electricity or natural gas purchased when the related electricity is sold.

Because all gains or losses on Networks’ commodity contracts will ultimately be passed on to retail customers, no sensitivity analysis is performed for Networks. Further information regarding the derivative financial instruments and sensitivity analysis is provided in Notes 11 and 12 of our consolidated financial statements contained in this Annual Report on Form 10-K.

Interest Rate Risk

Total debt outstanding was $8,294 million at December 31, 2021, of which $750 million had a floating interest rate via an interest rate derivative contract. A change of 25 basis points in this interest rate would result in an interest expense or income fluctuation of approximately $2 million annually. The estimated fair value of our long-term debt at December 31, 2021 was $9,155 million, in comparison to a book value of $8,294 million.

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. Further information regarding our interest rate derivative financial instruments is provided in Note 12 of our consolidated financial statements contained in this Annual Report on Form 10-K. There was one interest rate derivative contract outstanding at December 31, 2021.

Credit Risk

This risk is defined as the risk that a third party will not fulfill its contractual obligations and, therefore, generate losses for AVANGRID. Networks is exposed to nonpayment of customer bills. Standard debt recovery procedures are in place, in accordance with best practices and in compliance with applicable state regulations and embedded tariff mechanisms to manage uncollectible expense. Our credit department, based on guidelines approved by our board, establishes and manages its counterparty credit limits. We have developed a matrix of unsecured credit thresholds that are dependent on a counterparty’s or the counterparty guarantor’s applicable credit rating. Credit risk is mitigated by contracting with multiple counterparties and limiting exposure to individual counterparties or counterparty families to clearly defined limits based upon the risk of counterparty default. At the counterparty level, we employ specific eligibility criteria in determining appropriate limits for each prospective counterparty and supplement this with netting and collateral agreements, including margining, guarantees, letters of credit and cash deposits, where appropriate.

Renewables is also exposed to credit risk through its energy management operations. Counterparty credit risk is managed through established credit policies by a credit department that is independent of the energy management function. Prospective and existing customers are reviewed for creditworthiness based upon established criteria. Credit limits are set in accordance with board approved guidelines, with counterparties not meeting minimum standards providing various credit enhancements such as cash prepayments, letters of credit, cash and other collateral and guarantees. Master netting agreements are used, where appropriate, to offset cash and non-cash gains and losses arising from derivative instruments with the same counterparty. Trade receivables and other financial instruments are predominately with energy, utility and financial services-related companies, as well as municipalities, cooperatives and other trading companies in the U.S., although there is a growing segment of long-term power sales (PPAs) signed with commercial and industrial customers of high credit quality.

Based on our policies and risk exposures related to credit risk from its management in Renewables, we do not anticipate a material adverse effect on our financial statements as a result of counterparty nonperformance. As of December 31, 2021, approximately 99% of our energy management counterparty credit risk exposure is associated with companies that have investment grade credit ratings.

Treasury Management (including Liquidity Risk)

We optimize our liquidity through a series of arms-length intercompany lending arrangements with our subsidiaries and among the regulated utilities to provide for lending of surplus cash to subsidiaries with liquidity needs, subject to the limitation that the regulated utilities may not lend to unregulated affiliates. These arrangements minimize overall short-term funding costs and maximize returns on the temporary cash investments of the subsidiaries. We have the capacity to borrow from third parties through a $2 billion commercial paper program, the $3.575 million AVANGRID Credit Facility, which backstops the commercial paper program, and $500 million from an Iberdrola Group Credit Facility. For more information, see the section entitled “—Liquidity and Capital Resources—Liquidity Resources” of this Annual Report on Form 10-K.

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Networks

Networks’ regulated utilities fund their operations independently, except to the extent that they borrow on a short-term basis from AVANGRID and from each other when circumstances warrant in order to minimize short-term funding costs and maximize returns on temporary cash investments. The regulated utilities are prohibited by regulatory order from lending to unregulated affiliates. Networks’ regulated utilities each independently accesses the investment grade debt capital markets for long-term funding and each are borrowers under the AVANGRID Credit Facility described in “—Liquidity and Capital Resources—Liquidity Resources” of this Annual Report on Form 10-K.

Networks’ regulated utilities are subjected by regulatory order to certain credit quality maintenance measures, including minimum equity ratios, that are linked to the level of equity assumed in the establishment of revenue requirements. The companies maintain their equity ratios at or above the minimum through dividend declarations or, when necessary, capital contributions from AVANGRID.

Renewables

Renewables historically has been financed through equity contributions, intercompany loans during construction, tax equity partnerships and, to a lesser extent, sale-leaseback arrangements. The outstanding balance of its financing lease was $45 million at December 31, 2021.

Renewables is a party to a cash pooling arrangement with Avangrid, Inc. All Renewables revenues are concentrated in and all Renewables disbursements are made from Avangrid, Inc. Net cash surpluses or deficits at Renewables are recorded as intercompany receivables or payables and these balances are periodically reduced to zero through dividends or capital contributions. In March 2021, Renewables recorded a net non-cash dividend of $1,287 million to Avangrid, Inc. to zero out account balances that had principally accumulated prior to January 2021.

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Item 8. Financial Statements and Supplementary Data

Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Avangrid, Inc.:

Opinion on the Consolidated Financial Statements

We have audited the accompanying consolidated balance sheets of Avangrid, Inc. and subsidiaries (the Company) as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes and financial statement schedules I (collectively, the consolidated financial statements). In our opinion, the consolidated financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2021 and 2020, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2021, in conformity with U.S. generally accepted accounting principles.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company’s internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission, and our report dated February 23, 2022 expressed an unqualified opinion on the effectiveness of the Company’s internal control over financial reporting.

Basis for Opinion

These consolidated financial statements are the responsibility of the Company’s management. Our responsibility is to express an opinion on these consolidated financial statements based on our audits. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audits in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether the consolidated financial statements are free of material misstatement, whether due to error or fraud. Our audits included performing procedures to assess the risks of material misstatement of the consolidated financial statements, whether due to error or fraud, and performing procedures that respond to those risks. Such procedures included examining, on a test basis, evidence regarding the amounts and disclosures in the consolidated financial statements. Our audits also included evaluating the accounting principles used and significant estimates made by management, as well as evaluating the overall presentation of the consolidated financial statements. We believe that our audits provide a reasonable basis for our opinion.

Critical Audit Matters

The critical audit matters communicated below are matters arising from the current period audit of the consolidated financial statements that were communicated or required to be communicated to the audit committee and that: (1) relate to accounts or disclosures that are material to the consolidated financial statements and (2) involved our especially challenging, subjective, or complex judgments. The communication of critical audit matters does not alter in any way our opinion on the consolidated financial statements, taken as a whole, and we are not, by communicating the critical audit matters below, providing separate opinions on the critical audit matters or on the accounts or disclosures to which they relate.

Evaluation of the impairment of the carrying value of goodwill in the Renewables reporting unit

As discussed in Notes 3(g) and 7 to the consolidated financial statements, the goodwill balance as of December 31, 2021 was $3,119 million, of which $372 million related to the Renewables reporting unit. The Company performs goodwill impairment testing on an annual basis or more frequently if events occur or circumstances change that would more likely than not reduce the fair value of a reporting unit below its carrying amount.

We identified the evaluation of the impairment of the carrying value of goodwill in the Renewables reporting unit as a critical audit matter due to certain estimates and assumptions the Company made to determine the fair value of the Renewables reporting unit. As a result, a higher degree of auditor judgment was required to evaluate certain assumptions used in the Company’s estimate of the fair value of the Renewables reporting unit. Specifically, the Company’s determination of the forecasted power production and forecasted market prices, which are used to develop the revenue forecast, and the determination of the discount rates, required subjective and challenging auditor judgment.

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The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s goodwill impairment assessment process, including controls related to the determination of the forecasted power production, forecasted market prices and discount rates used to estimate the fair value of the Renewables reporting unit. To assess the Company’s ability to forecast revenues, we compared the Renewables reporting unit’s historical revenue forecasts to actual revenues. We compared the Renewables reporting unit’s forecasted power production to historical power production. We also evaluated the forecasted market prices by comparing them to third-party published reports by industry analysts. In addition, we involved valuation professionals with specialized skills and knowledge, who assisted in testing the selected discount rates by independently developing discount rates using publicly available market data for comparable entities and comparing them to the Company’s discount rates.

Evaluation of regulatory assets and liabilities

As discussed in Notes 3(c) and 6 to the consolidated financial statements, the Company accounts for their regulated operations in accordance with Financial Accounting Standards Board Accounting Standard Codification Topic 980, Regulated Operations (ASC Topic 980). Pursuant to the requirements of ASC Topic 980, the financial statements of a rate-regulated enterprise reflect the actions of regulators. The Company capitalizes, as regulatory assets, incurred and accrued costs that are probable of recovery in future electric and natural gas rates. In addition, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs are recorded as regulatory liabilities. The Company’s regulated utilities are subject to complex and comprehensive federal, state and local regulation and legislation, including regulations promulgated by state utility commissions and the Federal Energy Regulatory Commission.

We have identified the evaluation of regulatory assets and liabilities as a critical audit matter. This was due to the extent of audit effort required in the evaluation of regulatory assets and liabilities in each of the relevant jurisdictions. The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s regulatory accounting process, including controls related to the Company’s application of ASC Topic 980 in each jurisdiction and the Company’s calculation and review of regulatory assets and liabilities. We selected regulatory assets and liabilities and assessed the Company’s application of ASC Topic 980 in the relevant jurisdiction by evaluating the underlying orders, statutes, rulings, memorandums, filings or publications issued by the respective regulators. We selected a sample of the regulatory assets and liabilities activity and using the methodologies approved by the relevant regulatory commissions, recalculated the activity and agreed the data used in the calculations to the Company’s underlying books and records. We compared the amounts calculated by the Company to the amounts recorded in the consolidated financial statements.

Evaluation of tax equity financing arrangements

As discussed in Notes 3(e), 3(p) and 20 to the consolidated financial statements, the Company participates in certain tax equity financing arrangements (TEFs) that qualify as variable interest entities (VIEs). For TEFs where the economic allocations of income are not based on pro rata ownership percentages, a balance sheet-oriented hypothetical liquidation at book value (HLBV) method is used to reflect the substantive profit sharing arrangement. Under the HLBV method, the amounts reported as noncontrolling interests and net income (loss) attributable to noncontrolling interests in the consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet date under the liquidation provisions of each partnership’s ownership agreement assuming the net assets of the projects were liquidated at recorded amounts and distributed to the equity holders. Noncontrolling interests and net loss attributable to noncontrolling interests as of and for the year ended December 31, 2021 were $885 and $64 million, respectively.

We identified the evaluation of tax equity financing arrangements as a critical audit matter. This was due to the nature and extent of audit effort required to evaluate the HLBV methodology, which included specialized skills and knowledge to evaluate that the HLBV methodology used was consistent with the liquidation provisions of the underlying operating and partnership agreements, which can be based on complex income tax rules and regulations.

The following are the primary procedures we performed to address this critical audit matter. We evaluated the design and tested the operating effectiveness of certain internal controls over the Company’s review of the HLBV model, including controls related to review of the setup and accounting of the partnership liquidation model in relation to the operating and partnership agreement provisions, as well as the applicable tax regulations. We read the operating and partnership agreements and compared them against the Company’s partnership liquidation model for the corresponding tax equity financing arrangement. We involved tax professionals with specialized skills and knowledge, who assisted in:

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•analyzing the tax status of the entities and the requirements of the operating and partnership agreement provisions, as well as the partnership tax regulations

•evaluating the Company’s methodology for calculating the hypothetical liquidation amounts for a partnership in accordance with the operating and partnership agreement provisions, as well as the partnership tax regulations.

/s/ KPMG LLP 

We have served as the Company’s auditor since 2017.

New York, New York

February 23, 2022

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Report of Independent Registered Public Accounting Firm

To the Stockholders and Board of Directors

Avangrid, Inc.:

Opinion on Internal Control Over Financial Reporting

We have audited Avangrid, Inc. and subsidiaries' (the Company) internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission. In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2021, based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission.

We also have audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated balance sheets of the Company as of December 31, 2021 and 2020, the related consolidated statements of income, comprehensive income, changes in equity, and cash flows for each of the years in the three-year period ended December 31, 2021, and the related notes and financial statement schedule I (collectively, the consolidated financial statements), and our report dated February 23, 2022 expressed an unqualified opinion on those consolidated financial statements.

Basis for Opinion

The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying Report of Management on Internal Control Over Financial Reporting. Our responsibility is to express an opinion on the Company’s internal control over financial reporting based on our audit. We are a public accounting firm registered with the PCAOB and are required to be independent with respect to the Company in accordance with the U.S. federal securities laws and the applicable rules and regulations of the Securities and Exchange Commission and the PCAOB.

We conducted our audit in accordance with the standards of the PCAOB. Those standards require that we plan and perform the audit to obtain reasonable assurance about whether effective internal control over financial reporting was maintained in all material respects. Our audit of internal control over financial reporting included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, and testing and evaluating the design and operating effectiveness of internal control based on the assessed risk. Our audit also included performing such other procedures as we considered necessary in the circumstances. We believe that our audit provides a reasonable basis for our opinion.

Definition and Limitations of Internal Control Over Financial Reporting

A company’s internal control over financial reporting is a process designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with generally accepted accounting principles. A company’s internal control over financial reporting includes those policies and procedures that (1) pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company; (2) provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and (3) provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use, or disposition of the company’s assets that could have a material effect on the financial statements.

Because of its inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Also, projections of any evaluation of effectiveness to future periods are subject to the risk that controls may become inadequate because of changes in conditions, or that the degree of compliance with the policies or procedures may deteriorate.

/s/ KPMG LLP 

New York, New York

February 23, 2022

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Avangrid, Inc. and Subsidiaries

Consolidated Statements of Income

Years Ended December 31,	2021		2020		2019
(Millions, except for number of shares and per share data)
Operating Revenues	$	6,974	$	6,320	$	6,336
Operating Expenses
Purchased power, natural gas and fuel used	1,719		1,379		1,509
Operations and maintenance	2,706		2,466		2,305
Depreciation and amortization	1,014		987		933
Taxes other than income taxes, net	640		619		591
Total Operating Expenses	6,079		5,451		5,338
Operating Income	895		869		998
Other Income and (Expense)
Other income (expense)	60		18		121
(Losses) earnings from equity method investments	7		(3)		3
Interest expense, net of capitalization	(298)		(316)		(310)
Income Before Income Tax	664		568		812
Income tax expense	21		29		169
Net Income	643		539		643
Net loss attributable to noncontrolling interests	64		42		24
Net Income Attributable to Avangrid, Inc.	$	707	$	581	$	667
Earnings Per Common Share, Basic:	$	1.97	$	1.88	$	2.16
Earnings Per Common Share, Diluted:	$	1.97	$	1.88	$	2.16
Weighted-average Number of Common Shares Outstanding:
Basic	358,086,621		309,494,939		309,491,082
Diluted	358,578,608		309,559,387		309,514,910

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

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Avangrid, Inc. and Subsidiaries

Consolidated Statements of Comprehensive Income

Years Ended December 31,	2021		2020		2019
(Millions)
Net Income	$	643	$	539	$	643
Other Comprehensive Income
Gain on defined benefit plans, net of income taxes of $0, $0 and $0, respectively	2		—		1
Amortization of pension cost for nonqualified plans, net of income taxes of $(1), $3 and $(1), respectively	(8)		(13)		(1)
Unrealized loss from equity method investment, net of income taxes of $(3), $0 and $0, respectively	(9)		—		—
Unrealized loss during the year on derivatives qualifying as cash flow hedges, net of income taxes of $(44), $(7) and $(9), respectively	(159)		(22)		(22)
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $(3), $2 and $3, respectively	12		19		11
Other Comprehensive Loss	(162)		(16)		(11)
Comprehensive Income	481		523		632
Net loss attributable to noncontrolling interests	64		42		24
Comprehensive Income Attributable to Avangrid, Inc.	$	545	$	565	$	656

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

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Avangrid, Inc. and Subsidiaries

Consolidated Balance Sheets

As of December 31,	2021		2020
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	1,474	$	1,463
Accounts receivable and unbilled revenues, net	1,269		1,187
Accounts receivable from affiliates	11		12
Derivative assets	35		18
Fuel and gas in storage	139		93
Materials and supplies	204		169
Prepayments and other current assets	245		525
Regulatory assets	400		310
Total Current Assets	3,777		3,777
Total Property, Plant and Equipment ($1,959 and $1,637 related to VIEs, respectively)	28,866		26,751
Operating lease right-of-use assets	148		153
Equity method investments	560		668
Other investments	61		68
Regulatory assets	2,247		2,572
Other Assets
Goodwill	3,119		3,119
Intangible assets	293		305
Derivative assets	59		79
Other	374		331
Total Other Assets	3,845		3,834
Total Assets	$	39,504	$	37,823

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

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Avangrid, Inc. and Subsidiaries

Consolidated Balance Sheets

As of December 31,	2021		2020
(Millions, except share information)
Liabilities
Current Liabilities
Current portion of debt	$	372	$	313
Notes payable	159		307
Notes payable to affiliate	2		—
Interest accrued	69		70
Accounts payable and accrued liabilities	1,586		1,453
Accounts payable to affiliates	61		50
Dividends payable	170		136
Taxes accrued	43		73
Operating lease liabilities	12		8
Derivative liabilities	64		17
Other current liabilities	484		368
Regulatory liabilities	307		274
Total Current Liabilities	3,329		3,069
Regulatory liabilities	3,022		3,137
Other Non-current Liabilities
Deferred income taxes	2,016		1,919
Deferred income	1,130		1,204
Pension and other postretirement	684		1,007
Operating lease liabilities	149		154
Derivative liabilities	160		79
Asset retirement obligations	253		210
Environmental remediation costs	298		292
Other	580		448
Total Other Non-current Liabilities	5,270		5,313
Non-current debt	7,922		7,478
Non-current debt to affiliate	—		3,000
Total Non-current Liabilities	16,214		18,928
Total Liabilities	19,543		21,997
Commitments and Contingencies	—		—
Equity
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,678,630 and 309,794,917 shares issued; 386,568,104 and 309,077,300 shares outstanding, respectively	3		3
Additional paid-in capital	17,679		13,665
Treasury stock	(47)		(14)
Retained earnings	1,714		1,666
Accumulated other comprehensive loss	(273)		(111)
Total Stockholders’ Equity	19,076		15,209
Noncontrolling interests	885		617
Total Equity	19,961		15,826
Total Liabilities and Equity	$	39,504	$	37,823

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

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Avangrid, Inc. and Subsidiaries

Consolidated Statements of Cash Flows

Years Ended December 31,	2021		2020		2019
(Millions)
Cash Flow from Operating Activities
Net income	$	643	$	539	$	643
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	1,014		987		933
Accretion expenses	12		11		12
Regulatory assets/liabilities amortization and carrying cost	(72)		(13)		64
Pension cost	52		82		91
Earnings from equity method investments	(7)		3		(3)
Distribution of earnings from equity method investments	17		19		12
Unrealized losses (gains) on marked to market derivative contracts	86		5		(76)
Gain from divestment and disposal of property	24		(10)		(135)
Deferred taxes	11		17		164
Other non-cash items	(82)		(83)		(51)
Changes in operating assets and liabilities:
Current assets	(275)		(173)		126
Noncurrent assets	(45)		(170)		(152)
Current liabilities	286		160		(2)
Noncurrent liabilities	(103)		(86)		(38)
Net Cash Provided by Operating Activities	1,561		1,288		1,588
Cash Flow from Investing Activities
Capital expenditures	(2,976)		(2,781)		(2,735)
Contributions in aid of construction	130		48		74
Proceeds from sale of equity method and other investment	—		238		108
Proceeds from sale of property, plant and equipment	24		7		18
Payments to affiliates	5		(3)		(2)
Cash distribution from equity method investments	155		3		5
Other investments and equity method investments, net	222		(370)		(176)
Net Cash Used in Investing Activities	(2,440)		(2,858)		(2,708)
Cash Flow from Financing Activities
Non-current debt issuances	833		1,367		2,137
Non-current debt issuance with affiliate	—		3,000		—
Repayments of non-current debt	(304)		(1,011)		(346)
Repayment of non-current debt with affiliate	(3,000)		—		—
Repayments of other short-term debt, net	(306)		(253)		(28)
Repayments of financing leases	(6)		(9)		(27)
Repurchase of common stock	(33)		(2)		—
Issuance of common stock	3,998		(1)		—
Distributions to noncontrolling interests	(10)		(5)		(63)
Contributions from noncontrolling interests	330		312		133
Dividends paid	(613)		(545)		(545)
Net Cash Provided by Financing Activities	889		2,853		1,261
Net Increase in Cash, Cash Equivalents and Restricted Cash	10		1,283		141
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,467		184		43
Cash, Cash Equivalents and Restricted Cash, End of Year	$	1,477	$	1,467	$	184
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	$	279	$	278	$	270
Cash paid for income taxes	$	2	$	8	$	2

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

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Avangrid, Inc. and Subsidiaries

Consolidated Statements of Changes in Equity

	Avangrid, Inc. Stockholders
(Millions, except for number of shares)	Number of shares (*)	Common Stock		Additional paid-in capital		Treasury Stock		Retained Earnings		Accumulated Other Comprehensive Income (Loss)		Total Stockholders' Equity		Non-controlling Interests		Total Equity
Balances, December 31, 2018	309,005,272	$	3	$	13,657	$	(12)	$	1,514	$	(72)	$	15,090	$	299	$	15,389
Adoption of accounting standards	—	—		—		—		11		(12)		(1)		—		(1)
Net income	—	—		—		—		667		—		667		(24)		643
Other comprehensive income, net of tax of $(7)	—	—		—		—		—		(11)		(11)		—		(11)
Comprehensive income																632
Dividends declared, $1.76/share	—	—		—		—		(545)		—		(545)		—		(545)
Stock-based compensation	—	—		3		—		—		—		3		—		3
Distributions to noncontrolling interests	—	—		—		—		(4)		—		(4)		(59)		(63)
Contributions from noncontrolling interests	—	—		—		—		(9)		—		(9)		133		124
Balances, December 31, 2019	309,005,272	3		13,660		(12)		1,634		(95)		15,190		349		15,539
Adoption of accounting standards	—	—		—		—		(1)		—		(1)		—		(1)
Net income	—	—		—		—		581		—		581		(42)		539
Other comprehensive income, net of tax of $(2)	—	—		—		—		—		(16)		(16)		—		(16)
Comprehensive income																523
Dividends declared, $1.76/share	—	—		—		—		(545)		—		(545)		—		(545)
Release of common stock held in trust	72,028	—		—		—		—		—		—		—		—
Issuance of common stock	42,777	—		(1)		—		—		—		(1)		—		(1)
Repurchase of common stock	(42,777)	—		—		(2)		—		—		(2)		—		(2)
Stock-based compensation	—	—		6		—		—		—		6		—		6
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(5)		(5)
Contributions from noncontrolling interests	—	—		—		—		(3)		—		(3)		315		312
Balances, December 31, 2020	309,077,300	3		13,665		(14)		1,666		(111)		15,209		617		15,826
Net income	—	—		—		—		707		—		707		(64)		643
Other comprehensive income, net of tax of $(51)	—	—		—		—		—		(162)		(162)		—		(162)
Comprehensive income																481
Dividends declared, $1.76/share	—	—		—		—		(647)		—		(647)		—		(647)
Release of common stock held in trust	301,239	—		—		—		—		—		—		—		—
Issuance of common stock	77,883,713	—		3,998		—		—		—		3,998		—		3,998
Repurchase of common stock	(694,148)	—		—		(33)		—		—		(33)		—		(33)
Stock-based compensation	—	—		16		—		—		—		16		—		16
Distributions to noncontrolling interests	—	—		—		—		—		—		—		(10)		(10)
Contributions from noncontrolling interests	—	—		—		—		(12)		—		(12)		342		330
Balances, December 31, 2021	386,568,104	$	3	$	17,679	$	(47)	$	1,714	$	(273)	$	19,076	$	885	$	19,961

(*) Par value of share amounts is $.01

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

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AVANGRID, Inc. and Subsidiaries

Notes to Consolidated Financial Statements

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 14.8% of AVANGRID's outstanding shares publicly-traded on the New York Stock Exchange (NYSE).

Proposed Merger with PNMR

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

Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, Avangrid, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals.

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

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The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before April 20, 2023, as amended (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii) AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee).

In connection with the Merger, Iberdrola has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration.

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

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

Note 2. Basis of Presentation

The accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation in all periods presented.

Note 3. Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates

Significant Accounting Policies

We consider the following policies to be the most significant in understanding the judgments that are involved in preparing our consolidated financial statements:

(a) Principles of consolidation

We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting.

(b) Revenue recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Refer to Note 4 for further details.

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(c) Regulatory accounting

We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs.

We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.

(d) Business combinations and assets acquisitions (disposals)

We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred.

In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed.

(e) Noncontrolling interests

Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement.

Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets.

(f) Equity method investments

We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary.

(g) Goodwill and other intangible assets

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

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

Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite.

Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in our consolidated statements of income within the expense category that is consistent with the function of the intangible assets.

(h) Property, plant and equipment

We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset.

Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment.

We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service.

We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation.

We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives:

Major class	Asset Category	Estimated Useful Life (years)
Plant	Combined cycle plants	35-75
	Hydroelectric power stations	45-90
	Wind power stations	25-40
	Solar power stations	25
	Transmission and transport facilities	41-80
	Distribution facilities	4-80
Equipment	Conventional meters and measuring devices	7-85
	Computer software	3-37
Other	Buildings	30-82
	Operations offices	3-75

Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated

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depreciation. Networks' composite rate of depreciation were 2.8% and 2.9% of average depreciable property for 2021 and 2020, respectively.

We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs.

Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income.

(i) Leases

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

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

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

(j) Impairment of long-lived assets

We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset.

The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset.

(k) Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability.

The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use.

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We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date.

The three input levels of the fair value hierarchy are as follows:

•Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract.

•Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data.

Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair value.

(l) Equity investments with readily determinable fair values

We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.

(m) Derivatives and hedge accounting

Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met.

Certain derivatives hedge specific cash flows that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. Certain interest rate derivatives hedge a liability (i.e. debt) that qualify and are designated for hedge accounting are classified as fair value hedges. Changes in the fair value of interest rate derivatives designated as a fair value hedge and the offsetting changes in the fair value of the underlying hedged exposure (i.e. debt) are recorded in Interest expense. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI.

Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities.

We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.

(n) Cash and cash equivalents

Cash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued

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liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows.

(o) Trade receivable and unbilled revenue, net of allowance for credit losses

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

Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. Due to COVID-19, the UIL companies’ regulators require them to offer to customers, through early February 2022, a 24-month repayment plan.

We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. We consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts.

(p) Variable interest entities

An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20).

We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors.

(q) Debentures, bonds and bank borrowings

We record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets.

(r) Inventory

Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.”

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We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.”

In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.”

(s) Government grants

Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting.

In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses.

(t) Deferred income

Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.

(u) Asset retirement obligations

We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability.

The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred.

Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations.

(v) Environmental remediation liability

In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis.

(w) Post-employment and other employee benefits

We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees.

We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management.

We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking

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process. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss. We use a December 31st measurement date for our benefits plans.

We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period.

(x) Income taxes

We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs.

Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets.

We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements.

Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” in our consolidated statements of income.

Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income.

Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities.

Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.

(y) Stock-based compensation

Stock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier. 

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Adoption of New Accounting Pronouncements

(a) Simplifying the accounting for income taxes

In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes, eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. We adopted the amendments effective January 1, 2021, with no material effect to our consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement.

(b) Improvements to lessor accounting for certain leases with variable lease payments

In July 2021, the FASB issued amendments to make targeted improvements to ASC 842 for lessor’s accounting for certain leases with variable lease payments, which affect lease classification. The amendments require a lessor to classify and account for a lease with variable lease payments as an operating lease if (a) the lease would have been classified as a sales-type lease or a direct financing lease and (b) the lessor would have otherwise recognized a day-one loss. The amendments are effective for fiscal years beginning after December 15, 2021, for all entities, and interim periods within those fiscal years for public business entities, with early application permitted. We have elected to early apply the amendments effective October 1, 2021, and apply the amendments prospectively to leases that commence or are modified on or after that date. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows.

(c) Accounting for revenue contracts with customers acquired in a business combination

In October 2021, the FASB issued amendments related to the accounting for revenue contracts acquired in a business combination. The amendments require an entity (acquirer) to recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with ASC 606, Revenue from Contracts with Customers. At the acquisition date, an acquirer should account for the related revenue contract in accordance with ASC 606 as if it had originated the contracts. Generally, this should result in an acquirer recognizing and measuring the acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s financial statements. The amendments also provide certain practical expedients for acquirers when recognizing and measuring acquired contract assets and contract liabilities from revenue contracts in a business combination. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively to business combinations occurring on or after the effective date of the amendments. Early adoption is permitted. We have elected to early apply the amendments effective October 1, 2021. Our adoption did not materially affect our consolidated results of operations, financial position and cash flows.

Accounting Pronouncements Issued But Not Yet Adopted

The following are new accounting pronouncements not yet adopted that we have evaluated or are evaluating to determine their effect on our consolidated financial statements.

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

In March 2020, the FASB issued amendments and created ASC 848 to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension.

In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate

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reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments were effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.

Our prospective adoption of ASC 848 on January 1, 2022 will not materially affect our consolidated results of operations, financial position and cash flows.

(b) Disclosures by business entities about government assistance

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

Use of Estimates and Assumptions

The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for credit losses and unbilled revenues; (2) asset impairments, including goodwill; (3) investments in equity instruments; (4) depreciable lives of assets; (5) income tax valuation allowances; (6) uncertain tax positions; (7) reserves for professional, workers’ compensation and comprehensive general insurance liability risks; (8) contingency and litigation reserves; (9) fair value measurements; (10) earnings sharing mechanisms; (11) environmental remediation liabilities; (12) AROs; (13) pension and other postretirement employee benefits and (14) noncontrolling interest balances. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates we use in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates.

We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from COVID-19 has made such estimates and assumptions more difficult to assess and calculate. Affected estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While we have not yet had material effects of COVID-19 on our financial results, actual results could differ from those estimates, which could result in material effects to our consolidated financial statements in future reporting periods.

Union collective bargaining agreements

We have approximately 47.7% of our employees covered by a collective bargaining agreement. Agreements expiring in the coming year apply to approximately 18.8% of our employees.

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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 24.

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.

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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 including intersegment eliminations.

Contract Costs, Contract Liabilities and Practical Expedient

We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2022 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2021 and 2020, and are presented in "Other non-current assets" on our 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 $9 million at December 31, 2021 and 2020, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $22 million for the year ended December 31, 2021, and $21 million for both of the years ended December 31, 2020 and 2019 as revenue related to contract liabilities.

We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

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Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2021, 2020 and 2019 are as follows:

	Year Ended December 31, 2021
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	4,015	$	—	$	—	$	4,015
Regulated operations – natural gas	1,516		—		—		1,516
Nonregulated operations – wind	—		1,028		—		1028
Nonregulated operations – solar	—		20		—		20
Nonregulated operations – thermal	—		63		—		63
Other (a)	67		84		—		151
Revenue from contracts with customers	5,598		1,195		—		6,793
Leasing revenue	7		—		—		7
Derivative revenue	—		3		—		3
Alternative revenue programs	115		—		—		115
Other revenue	34		22		—		56
Total operating revenues	$	5,754	$	1,220	$	—	$	6,974

	Year Ended December 31, 2020
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	3,642	$	—	$	—	$	3,642
Regulated operations – natural gas	1,311		—		—		1,311
Nonregulated operations – wind	—		822		—		822
Nonregulated operations – solar	—		19		—		19
Nonregulated operations – thermal	—		39		—		39
Other (a)	58		101		—		159
Revenue from contracts with customers	5,011		981		—		5,992
Leasing revenue	6		—		—		6
Derivative revenue	—		136		—		136
Alternative revenue programs	157		—		—		157
Other revenue	14		15		—		29
Total operating revenues	$	5,188	$	1,132	$	—	$	6,320

	Year Ended December 31, 2019
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	3,485	$	—	$	—	$	3,485
Regulated operations – natural gas	1,479		—		—		1,479
Nonregulated operations – wind	—		803		—		803
Nonregulated operations – solar	—		26		—		26
Nonregulated operations – thermal	—		29		—		29
Other (a)	91		62		(12)		141
Revenue from contracts with customers	5,055		920		(12)		5,963
Leasing revenue	6		—		—		6
Derivative revenue	—		244		—		244
Alternative revenue programs	75		—		—		75
Other revenue	28		20		—		48
Total operating revenues	$	5,164	$	1,184	$	(12)	$	6,336

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(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 December 31, 2021 and 2020, accounts receivable balances related to contracts with customers were approximately $1,220 million and $1,151 million, respectively, including unbilled revenues of $405 million and $341 million, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets.

As of December 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of December 31, 2021	2022		2023		2024		2025		2026		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	6	$	1	$	1	$	—	$	—	$	—	$	8
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	39		24		9		2		3		2		79
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	26		18		14		12		10		65		145
Total operating revenues	$	71	$	43	$	24	$	14	$	13	$	67	$	232

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. Industry Regulation

Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts

Each of Networks’ eight regulated utility companies must comply with regulatory procedures that differ in form but in all cases conform to the basic framework outlined below. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection from, and automatic adjustments for, exceptional costs incurred and efficiency incentives. The distribution rates and allowed ROEs for Networks’ regulated utilities in New York are subject to regulation by the New York Public Service Commission (NYPSC), in Maine by the Maine Public Utilities Commission (MPUC), in Connecticut by the Connecticut Public Utilities Regulatory Authority (PURA) and in Massachusetts by the Department of Public Utilities (DPU).

The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to the Networks companies are approved by the regulatory commissions of the different states and are based on the cost of providing service. The revenues of each of the Networks companies are set to be sufficient to cover its operating costs, including energy costs, finance costs and the costs of equity, the last of which reflects our capital ratio and a reasonable ROE.

Energy costs that are incurred in the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York and Connecticut revenues that allow a utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting in future tariff reductions.

The NYSEG and RG&E rate plans, the Maine distribution rate plan and associated proceedings, the Federal Energy Regulatory Commission (FERC) Transmission Return on Equity (ROE) case, the Connecticut rate plans, Reforming Energy Vision (REV), the storm proceedings in New York and the Tax Act are some of the most important specific regulatory processes that currently affect Networks.

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. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency

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adjustment was ordered to remain in effect until CMP demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment starting from September 1, 2021. The MPUC approved CMP's request for removal of the management efficiency adjustment effective as of its February 18, 2022 order.

The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. We cannot predict the outcome of this investigation.

NYSEG and RG&E Rate Plans

2016 Joint Proposal

On June 15, 2016, the NYPSC approved NYSEG's and RG&E's 2016 Joint Proposal for a three-year rate plan for electric and gas service which balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The 2016 Joint Proposal reflected many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows:

	May 1, 2018
	Rate Increase		Delivery Rate Increase
Utility	(Millions)		%
NYSEG Electric	$	30	4.10	%
NYSEG Gas	$	15	7.30	%
RG&E Electric	$	26	5.70	%
RG&E Gas	$	10	5.20	%

The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas was 9.00%. The equity ratio for each company was 48%; however, the equity ratio was set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increased as the ROE increased, with customers receiving 50%, 75% and 90% of earnings in rate year three (May 1, 2018 – April 30, 2019) above 9.75%, 10.25% and 10.75% ROE, respectively. The rate plans also included the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates and continuation of the existing RDM for each business. The 2016 Joint Proposal reflected the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($26 million annually for NYSEG Electric and $3 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds.

The 2016 Joint Proposal maintained NYSEG’s and RG&E’s current electric reliability performance measures (and associated potential negative revenue adjustments for failing to meet established performance levels) which include the system average interruption frequency index (SAIFI) and the customer average interruption duration index (CAIDI). The 2016 Joint Proposal also modified certain gas safety performance measures at the companies, including those relating to the replacement of leak prone mains, leak backlog management, emergency response and damage prevention. The proposal established threshold performance levels for designated aspects of customer service quality and continued and expanded NYSEG’s and RG&E’s bill reduction and arrears forgiveness Low Income Programs with increased funding levels. The 2016 Joint Proposal provided for the implementation of NYSEG’s Energy Smart Community (ESC) Project in the Ithaca region which serves as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project is supported by NYSEG’s planned Distribution Automation upgrades and Advanced Metering Infrastructure (AMI) implementation for customers on

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circuits in the Ithaca region. The companies also are pursuing Non-Wires Alternative projects as described in the proposal. Other REV-related incremental costs and fees were included in the RAM to the extent cost recovery is not provided for elsewhere. Under the proposal, the RAM was applicable to all customers and serves to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG Electric Pole Attachment revenues. RG&E implemented a RAM in July 2018 since certain eligibility thresholds were exceeded.

The 2016 Joint Proposal provided for partial or full reconciliation of certain expenses including, but not limited to: pensions and other postretirement benefits; property taxes; variable rate debt and new fixed rate debt; gas research and development; environmental remediation costs; major storms; nuclear electric insurance limited credits; economic development; and low income programs. The 2016 Joint Proposal also included a downward-only Net Plant reconciliation. In addition, the 2016 Joint Proposal included downward-only reconciliations for the costs of electric distribution and gas vegetation management, pipeline integrity and incremental maintenance. The 2016 Joint Proposal provided that NYSEG and RG&E continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis.

2020 Joint Proposal

On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan (2020 Joint Proposal). On November 19, 2020, the NYPSC approved the 2020 Joint Proposal, with modifications to the rate increases at the two electric businesses. The modifications were made to limit the overall bill impacts, to a level at or below 2.00% per year, in consideration of the current impacts of COVID-19 on the economic climate. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The new rates help to 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 ESM, 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 Increase		Rate Increase		Delivery Rate Increase		Rate Increase		Delivery Rate Increase
Utility	(Millions)		%		(Millions)		%		(Millions)		%
NYSEG Electric	$	34	4.6	%	$	46	5.9	%	$	36	4.2	%
NYSEG Gas	$	—	—	%	$	2	0.8	%	$	3	1.6	%
RG&E Electric	$	17	3.8	%	$	14	3.2	%	$	16	3.3	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2	1.3	%

UI, CNG, SCG and BGC Rate Plans

Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills.

UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2022, 60% of its standard service load for the second half of 2022. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first quarter of 2022. However, from time to time, there are no bidders in the procurement process for supplier of last resort service and UI manages the load directly.

In 2016, PURA approved new distribution rate schedules for 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 ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist.

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In 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 approximately 52.00% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.

In December 2018, PURA approved new tariffs for 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 January 18, 2019, the DPU approved new distribution rates for BGC. The distribution rate increase is based on an ROE 9.70% and 54.00% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021. BGC expects to file an application to amend its distribution rates in the first half of 2022. We cannot predict the outcome of this proceeding.

REV

In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide-ranging initiative to reform New York State’s energy industry and regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources (DER), such as micro grids, on-site power supplies and storage.

REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this initiative involves a collaborative process to examine the role of distribution utilities in enabling market-based deployment of DER to promote load management and greater system efficiency, including peak load reductions. NYSEG is participating in the initiative with other New York utilities. The NYPSC issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016, followed by bi-annual updates. The companies filed the initial DSIP, which also included information regarding the potential deployment of Automated Metering Infrastructure (AMI) across its entire service territory. In December 2016, the companies filed a petition to the NYPSC requesting approval for cost recovery associated with the full deployment of AMI. A collaborative associated with this petition began in the first quarter of 2017, was suspended in the second quarter of 2017, subsequently resumed in the first quarter of 2018 and then further suspended and was been included in the companies’ May 20, 2019 rate filing. The companies also filed their first bi-annual update of the DSIP on July 31, 2018 and filed their next bi-annual update on June 30, 2020.

Other various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include the Clean Energy Standard, Value of DER and Net Energy Metering, Demand Response Tariffs and Community Choice Aggregation. As part of the Clean Energy Standard proceeding, all electric utilities were ordered to begin payments to New York State Energy Research and Development Authority (NYSERDA) for RECs and Zero Emissions Credits beginning in 2017.

Track 2 of the REV initiative is also underway, and through a NYPSC staff whitepaper review process, is examining potential changes in current regulatory, tariff, market design and incentive structures that could better align utility interests with achieving New York state and NYPSC’s policy objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in May 2016, and includes guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs and data utilization and security. The companies, in December 2016, filed a proposal for the implementation of EAMs in the areas of System Efficiency, Energy Efficiency, Interconnections and Clean Air. A collaborative process to review the companies’ petition was suspended in 2017. The approved 2020 Joint Proposal includes EAMs.

In March 2017, the NYPSC issued three separate REV-related orders. These orders created a series of filing requirements for NYSEG and RG&E beginning in March 2017 and extending through the end of 2018. The three orders involve: 1) modifications to the electric utilities’ proposed interconnection EAM framework; 2) further DSIP requirements, including filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at each company by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of the Value of DER. In September 2017, the NYPSC issued another order related to the Value of DER, requiring tariff filings, changes to Standard Interconnection

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Requirements and planning for the implementation of automated consolidated billing. As of the end of 2018, both NYSEG and RG&E had deployed two energy storage projects each, consistent with the March 2017 NYPSC order requirements. In December 2018, the NYPSC staff submitted whitepapers on standby and buyback service rate design, future value stack compensation and capacity value compensation. The NYPSC ruled on the proposals set forth in the whitepapers on May 16, 2019. NYSEG and RG&E filed proposed standby and buyback rates with the NYPSC in September 2019. On November 25, 2020, DPS Staff, jointly with NYSERDA, issued a whitepaper on further recommendations regarding standby and buyback rates that were based on the electric utilities’ September 23, 2019 filings. Comments on the recommendations in the whitepaper are due February 22, 2021, and reply comments are due March 8, 2021. A final Commission Order is expected in 2022.

On April 18, 2019, the NYPSC issued an order on future value stack compensation and capacity value compensation. The order established a new Community Credit in place of the Market Transition Credit for certain CDG projects in NYSEG’s and RGE’s territories and expanded eligibility for Phase One Net Metering for projects that have a rated capacity of 750 kW AC or lower. The changes became effective on June 1, 2019. The NYPSC also issued an order on value stack compensation for high-capacity-factor Resources on December 12, 2019, modifying the treatment of certain high-capacity-factor DER in the Value Stack compensation framework. The modification per the December 12, 2019 Order became effective February 1, 2020. On March 19, 2020, the Commission issued an additional Order regarding Value Stack Compensation. The Order directs National Grid, NYSEG and RGE to reallocate capacity from closed tranches where available capacity remained due to projects being canceled since the issuance of the VDER Compensation Order, and to assign that capacity to a new Community Credit Tranche with compensation at 2 cents per kWh. The utilities must also continue to reallocate capacity to this new Tranche for the next six months when there are cancellations of projects that have received a Market Transition Credit (MTC) or Community Credit allocation. The new provisions per the March 19, 2020 Order became effective May 1, 2020.

On May 14, 2020, the Commission issued an Order extending and expanding distributed solar incentives. In addition to authorizing the extension of and additional funding for the NY-Sun program, the Commission modified certain program rules related to the NY-Sun program and the VDER policy. As part of the ordered modifications, the Commission directed the electric utilities with VDER tariffs to add tariff language for a Remote Crediting program that will allow Value-Stack-eligible generation resources to distribute the credits they receive for generation injected into the utility system to the utility bills of multiple, separately sited, non-residential customers. The Commission ordered the utilities to submit tariff leaves that implement the modifications associated with the Remote Crediting program to become effective November 1, 2020. Given the complexity of the program changes, the utilities have petitioned the Commission for an extension. Tariffs were filed on August 16, 2021, becoming effective on September 1, 2021.

On July 16, 2020, the Commission issued an Order establishing a net metering successor tariff. The Order continues Phase One NEM for all eligible mass market and commercial projects under 750 kW interconnected after January 1, 2022 and implements a modest customer benefit contribution (CBC) for onsite DERs to address cost recovery of certain public benefit programs. Customers that install DERs interconnected after January 1, 2022 shall be charged a monthly per kW fee based on the nameplate rating of the DER. Draft tariff leaves implementing the Commission’s Order and proposed CBC calculations were filed on November 1, 2020. A final Commission Order was issued on August 13, 2021, implementing the CBC effective January 1, 2022 for new mass market net metering customers.

On April 24, 2018, the NYPSC instituted a proceeding to consider the role of utilities in providing infrastructure and rate design to encourage the expansion electric vehicles and electric vehicle supply equipment. The Commission issued an Order on February 2, 2019 to establish a Direct Current Fast Charger incentive program, with subsequent clarifications provided in Orders issued on July 12, 2019 and March 3, 2020. On July 16, 2020, the NYPSC issued an Order approving a $700 million statewide program (NYSEG and RG&E combined share is approximately $118 million). The make-ready program will be funded by investor-owned utilities in New York State and creates a cost-sharing program that incentivizes utilities and charging station developers to site electric vehicle charging infrastructure in places that will provide a maximal benefit to consumers.

CMP Customer Billing System Investigation

On March 1, 2018, the MPUC issued a Notice of Investigation initiating a summary investigation into CMP’s metering, billing and customer communications practices. Due to the highly technical nature of CMP’s customer billing system the MPUC ordered a forensic audit of CMP’s customer billing system to identify any errors that have, or continue to result in billing inaccuracies, and to review CMP’s customer communication practices. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 9, 2020, the hearing examiners issued their report whereby they recommended that the Commission find that the evidence in the record shows that there is no systemic problem within CMP’s metering and billing systems that has caused erroneous high usage on customers’ bills. Instead, the evidence-including the detailed forensic audit conducted by an independent third-party auditor-demonstrates that CMP’s metering and billing systems have been, and continue to be, recording and transmitting customer usage data accurately, and, with the exception of discrete billing calculation and presentation issues, customers’ billed amounts have been

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accurate. On January 30, 2020, the MPUC Commissioners deliberated and based on the verbal discussion, the Commissioners indicated that CMP’s Metering and Billing system is accurately reporting data; there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The Commissioners were critical of CMP finding that CMP failed to implement proper testing of the SmartCare system prior to go-live; CMP’s implementation of SmartCare was imprudent; CMP’s SmartCare implementation experienced an unacceptable number of billing errors, delayed or estimated bills, bill presentment issues and unreasonable time required to address these issues; and the implementation issues were compounded by inadequate staffing, resulting in the inability of customers to contact a CMP representative. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above the MPUC imposed a reduction of 100 basis points in ROE, as a management efficiency adjustment, to address concerns with CMP’s customer service performance following the implementation of its new billing system in 2017 and on February 24, 2020 issued an order in the metering and billing investigation. Each order reflected the MPUC’s conclusion that CMP’s Metering and Billing system is accurately reporting data, there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The management efficiency adjustment was ordered to remain in effect until CMP demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment starting from September 1, 2021. The MPUC approved CMP's request for removal of the management efficiency adjustment as of its February 18, 2022 order.

Tax Cuts and Jobs Act

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Tax Act) was signed into law. The Tax Act significantly changed the federal taxation of business entities including, among other things, implementing a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates 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, to review and address the implications of the Tax Act on the utilities.

In New York, the NYPSC issued an order requiring sur-credits to return benefits reflecting the lower effective tax rate of 21% to customers effective October 1, 2018. For NYSEG Gas, RG&E Electric and RG&E Gas the NYPSC also required the sur-credit to include the return to customers of the January - September 2018 Tax Act savings over three years. The remaining deferred amounts associated with the recognition of the effects of the Tax Act are being used as rate moderators in the approved 2020 Joint Proposal. In Connecticut, with regard to UI, the PURA approved a multi-docket settlement proposal on June 28, 2021, which required UI to flow accumulated Tax Act savings back to customers over a 22-month period, commencing on July 1, 2021 through April 30, 2023. With regard to SCG, we expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case, unless PURA determines otherwise. CNG and BGC include Tax Act savings in their current rate plans. In Maine, CMP adjusted rates beginning July 1, 2018 to pass back to customers the Tax Act savings after offsetting for recovery of deferred 2017 storm costs. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above, the MPUC approved CMP’s distribution related accumulated deferred income tax balances associated with the Tax Act as well as the authorized amortization periods for the return of regulatory liabilities and the recovery regulatory assets. At the FERC, CMP transmission and UI transmission adjusted their tariffs in June 2018 to reflect the income statement value of Tax Act savings. On December 22, 2021, the FERC issued an order finding that the New England Transmission Owners (NETOs) Regional Network Service proposed revisions partially comply with the requirements of Order 864 and directed the NETOs to submit a further compliance filing within 60 days of the date of the order. The compliance is effective January 27, 2020, consistent with Order 864 and January 1, 2022, to reflect the fact that the NETOs existing transmission formula rates under the ISO-NE Tariff will be replaced by a settled formula rate effective January 1, 2022.

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 $142 million and $148 million, respectively for this item at December 31, 2021 and 2020.

In 2017, audits of the power tax regulatory assets were commenced by the NYPSC and MPUC. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax

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accounting. The NYPSC audit report is expected to be completed during 2022. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which indicated the auditor was unable to verify the asset “acquisition value” used to calculate the Power Tax regulatory asset. The audit report requires that CMP must provide support for the beginning balance of the regulatory assets or it will be unable to recover the value of the assets, which is approximately $11 million, excluding carrying costs. CMP responded to the audit report in its rate case filing by providing additional acquisition value support and, therefore, requested full recovery of the Power Tax regulatory asset. MPUC staff expressed concerns about the value CMP has attributed to this issue. The MPUC had an outside firm conduct an audit of CMP's filing and acquisition values, and the auditor found CMP's information was reasonable. In September 2019, CMP filed a report in response to the audit report and addressed MPUC staff concerns. On December 17, 2019, CMP filed a stipulation with the MPUC providing for recovery of the Power Tax regulatory asset and adjusting the carrying costs values for the period of July 1, 2017 through June 30, 2019. The MPUC approved the stipulation on January 21, 2020, which allowed CMP to start collecting the Power Tax Regulatory asset over the next 32.5 years beginning in July 2020.

Minimum Equity Requirements for Regulated Subsidiaries

Our regulated utility subsidiaries of Maine and New York (NYSEG, RG&E, CMP and MNG) are each subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements, each of NYSEG, RG&E, CMP and MNG must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis, each utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that may be paid and may, under certain circumstances, require that the parent contribute equity capital. In addition, NYSEG and RG&E equity distributions that would result in a 13-month average common equity less than the maximum equity ratio utilized for the earnings sharing mechanism, or ESM, are prohibited if the credit rating of NYSEG, RG&E, AVANGRID or Iberdrola are downgraded by a nationally recognized rating agency to the lowest investment grade with a negative watch or downgraded to non-investment grade. These regulated utility subsidiaries are prohibited by regulation from lending to unregulated affiliates. These regulated utility subsidiaries have also agreed to minimum equity ratio requirements in certain borrowing agreements. These requirements are lower than the regulatory requirements.

Pursuant to agreements with the relevant utility commission, UI, SCG, CNG and BGC are restricted from paying dividends if paying such dividend would result in a common equity ratio lower than 300 basis points below the equity percentage used to set rates in the most recent distribution rate proceeding as measured using a trailing 13-month average calculated as of the most recent quarter end. In addition, UI, SCG, CNG and BGC are prohibited from paying dividends to their parent if the utility’s credit rating, as rated by any of the three major credit rating agencies, falls below investment grade, or if the utility’s credit rating, as determined by two of the three major credit rating agencies, falls to the lowest investment grade and there is a negative watch or review downgrade notice.

We had restricted net assets of approximately $5,808 million associated with the minimum equity requirements as of December 31, 2021.

Movement of capital from our wholly owned unregulated subsidiaries is unrestricted.

New Renewable Source Generation

Under Connecticut Public Act (PA) 11-80, Connecticut electric utilities are required to enter into long-term contracts to purchase Connecticut Class I RECs from renewable generators located on customer premises. Under this program, UI was initially required to enter into contracts totaling approximately $200 million in commitments over an approximate 21-year period. The obligations were initially expected to phase in over a six-year solicitation period and peak at an annual commitment level of about $14 million per year after all selected projects are online. PA 17-144, PA 18-50 and PA 19-35 extended the original six-year solicitation period of the program by adding seventh, eighth, ninth, and tenth years, and increased the original funding level of this program by adding up to $64 million in additional commitments by UI. Upon purchase, UI accounts for the RECs as inventory. UI expects to partially mitigate the cost of these contracts through the resale of the RECs. PA 11-80 provides that the remaining costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable from (or credited to) customers through electric rates.

In October of 2018, UI entered into five PPAs totaling approximately 50 MW from developers of offshore wind and fuel cell generation pursuant to state law that provides the net costs of the PPAs are recoverable through electric rates. On December 19, 2018, PURA approved the PPAs, and approved UI’s use of the non-bypassable federally mandated congestion charges for all customers to recover the net costs of the PPAs.

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In 2019, UI entered into PPAs with 11 projects, totaling approximately 12 million MWh, pursuant to state law that provides that the net costs of the PPAs are recoverable through electric rates.

In 2020, pursuant to Connecticut Act Concerning the Procurement of Energy Derived From Offshore Wind, UI entered into a PPA with Vineyard Wind, an affiliate of UI, to provide 804 MW of offshore wind through the development of its Park City Wind Project. Similar to the case with the zero carbon PPAs discussed above, the net costs of the PPAs are recoverable through electric rates.

Pursuant to Maine law, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of energy, capacity or RECs, from qualifying resources. The MPUC is further authorized to order Maine transmission and distribution utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreen’s 60 Megawatt (MW) Rollins wind farm. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. Pursuant to a MPUC Order dated December 18, 2017, CMP entered into a 20-year agreement with Dirigo Solar, LLC on September 10, 2018, to purchase capacity and energy from multiple Dirigo solar facilities throughout CMP’s service territory. CMP’s purchase obligations under the Dirigo contract will increase as additional solar facilities are brought on line, eventually reaching a level of approximately $4 million per year. Pursuant to a MPUC Order dated November 6, 2019, CMP entered into a 20-year agreement with Maine Aqua Ventus I GP LLC on December 9, 2019, to purchase capacity and energy from an off-shore wind farm under development near Monhegan Island, Maine. CMP’s purchase obligations under the Maine Aqua Ventus contract will be approximately $12 million per year once the facility begins commercial operation. Pursuant to Maine law, the MPUC conducted two competitive solicitation processes to procure, in the aggregate, an amount of energy or RECs from Class 1A resources that is equal to 14% of retail electricity sales in the State during calendar year 2018, or 1.715 million MWh. Of that 14% total, the MPUC must acquire at least 7%, but not more than 10%. Through contracts approved in December 2020 (Tranche 1), CMP was ordered to execute 13 contracts. In October 2021 CMP executed contracts with 6 additional facilities (Tranche 2). Each of the Tranche 1 and Tranche 2 are for 20-year terms. In accordance with MPUC orders, CMP either sells the purchased energy, or in one case the RECs, from these facilities in the ISO New England markets, through periodic auctions of the purchased output to wholesale buyers in the New England regional market, or through a sale to a third party for the RECs. Under Maine law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under Maine law, and has tentatively accepted long-term proposals from other sellers, these selections have not yet resulted in additional currently effective contracts with CMP.

Connecticut Energy Legislation

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

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

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

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

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

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

On August 6, 2020, the PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. 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 Storm Isaias Docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. We cannot predict the outcome of these appeals.

Note 6. Regulatory Assets and Liabilities

Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize as regulatory assets incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,136 million.

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

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Regulatory assets as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Pension and other post-retirement benefits	$	545	$	927
Pension and other post-retirement benefits cost deferrals	95		105
Storm costs	448		451
Rate adjustment mechanism	68		33
Revenue decoupling mechanism	68		58
Transmission revenue reconciliation mechanism	15		31
Contracts for differences	73		86
Hardship programs	24		20
Plant decommissioning	2		3
Deferred purchased gas	52		30
Deferred transmission expense	13		26
Environmental remediation costs	256		247
Debt premium	71		83
Unamortized losses on reacquired debt	23		26
Unfunded future income taxes	424		373
Federal tax depreciation normalization adjustment	142		148
Asset retirement obligation	20		21
Deferred meter replacement costs	46		33
COVID-19 cost recovery	21		1
Other	241		180
Total regulatory assets	2,647		2,882
Less: current portion	400		310
Total non-current regulatory assets	$	2,247	$	2,572

“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

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rates.

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

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

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

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

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

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

“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of forty-six years and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances.

“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020.

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

“Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by AMI meters. This amount is being amortized over the initial depreciation period of related retired meters.

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

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

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Regulatory liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Energy efficiency portfolio standard	$	45	$	58
Gas supply charge and deferred natural gas cost	7		3
Pension and other post-retirement benefits cost deferrals	73		59
Carrying costs on deferred income tax bonus depreciation	23		34
Carrying costs on deferred income tax - Mixed Services 263(a)	7		11
2017 Tax Act	1,327		1,435
Rate change levelization	99		55
Revenue decoupling mechanism	13		9
Accrued removal obligations	1,192		1,184
Asset sale gain account	2		7
Economic development	26		28
Positive benefit adjustment	22		30
Theoretical reserve flow thru impact	6		10
Deferred property tax	22		31
Net plant reconciliation	16		20
Debt rate reconciliation	49		63
Rate refund – FERC ROE proceeding	35		33
Transmission congestion contracts	23		22
Merger-related rate credits	12		14
Accumulated deferred investment tax credits	24		25
Asset retirement obligation	18		18
Earnings sharing provisions	13		17
Middletown/Norwalk local transmission network service collections	17		18
Low income programs	25		28
Non-firm margin sharing credits	15		14
New York 2018 winter storm settlement	5		9
Hedges gains	19		—
Other	194		176
Total regulatory liabilities	3,329		3,411
Less: current portion	307		274
Total non-current regulatory liabilities	$	3,022	$	3,137

“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

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

"Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

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

"Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020.

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

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

“Asset sale gain account” represents the net gain on the sale of certain assets that will be used for the future benefit of customers. The amortization period in current rates is three years for NYSEG and two years for RG&E and began in 2020.

“Economic development” represents the economic development program, which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three to five 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 14 for more details.

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"Transmission congestion contracts" represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RGE. 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. In both of the years ended December 31, 2021 and 2020, $2 million of rate credits were applied against customer bills.

“Accumulated deferred investment tax credits” represents investment tax credits related to plant investments that are deferred when earned and amortized over the estimated lives of the related assets.

“Asset retirement obligation” represents fair value of the liability for an asset retirement the company is legally committed to removing (PCB transformers, bare steel).

"Earning sharing provisions" represents the annual earnings over the earning 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 NYSPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. This 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 7. Goodwill and Intangible assets

Goodwill by reportable segment as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Networks	$	2,747	$	2,747
Renewables	372		372
Total	$	3,119	$	3,119

During 2021, there were no changes in gross amounts and accumulated losses of goodwill for the Networks and Renewables reportable segments.

Goodwill Impairment Assessment

For impairment testing purposes, our reporting units are the same as operating segments, except for Networks, which contains three reporting units, Maine, New York and UIL. Goodwill for the Maine reporting unit is $325 million from the purchase of CMP by Energy East Corporation in 2000. Goodwill for the New York reporting unit is $654 million primarily from the purchase of RG&E by Energy East in 2002. Goodwill for the UIL reporting unit is $1,768 million from the 2015 acquisition of UIL.

We perform our annual impairment testing in the fourth quarter, as of October 1. Our qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events and events affecting a reporting unit.

Our quantitative assessment utilizes a discounted cash flow model under the income approach and includes critical assumptions, primarily the discount rate and internal estimates of forecasted cash flows. We use a discount rate that is developed using market participant assumptions, which consider the risk and nature of the respective reporting unit’s cash flows and the rates of return market participants would require in order to invest their capital in our reporting units. We test the reasonableness of the conclusions of our quantitative impairment testing using a range of discount rates and a range of assumptions for long-term cash flows.

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For 2021, we utilized a qualitative assessment for the Networks reporting units and a quantitative assessment for the Renewables reporting unit. For 2020, we utilized a quantitative assessment for the Networks and Renewables reporting units. We had no impairment of goodwill in 2021 and 2020 as a result of our impairment testing.

Intangible assets

Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2021 and 2020:

As of December 31, 2021	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
(Millions)
Wind development	$	592	$	(301)	$	291
Other	18		(16)		2
Total Intangible Assets	$	610	$	(317)	$	293

As of December 31, 2020	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
(Millions)
Wind development	$	593	$	(290)	$	303
Other	31		(29)		2
Total Intangible Assets	$	624	$	(319)	$	305

Wind development costs, with the exception of future ‘pipeline’ development costs, are amortized on a straight-line basis in accordance with the life of the related assets once placed in service. Amortization expense was $13 million, $14 million and $15 million for the years ended December 31, 2021, 2020 and 2019, respectively. We believe our future cash flows will support the recoverability of our intangible assets.

We expect amortization expense for the five years subsequent to December 31, 2021, to be as follows:

Year ending December 31,	Amount
(Millions)
2022	$	14
2023	$	13
2024	$	13
2025	$	12
2026	$	12

Note 8. Property, Plant and Equipment

Property, plant and equipment as of December 31, 2021, consisted of:

As of December 31, 2021	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	17,392	$	13,446	$	30,838
Natural gas transportation, distribution and other	5,032		13		5,045
Other common operating property	—		286		286
Total Property, Plant and Equipment in Service	22,424		13,745		36,169
Total accumulated depreciation	(5,806)		(4,783)		(10,589)
Total Net Property, Plant and Equipment in Service	16,618		8,962		25,580
Construction work in progress	2,064		1,222		3,286
Total Property, Plant and Equipment	$	18,682	$	10,184	$	28,866

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Property, plant and equipment as of December 31, 2020, consisted of:

As of December 31, 2020	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	16,364	$	12,854	$	29,218
Natural gas transportation, distribution and other	4,637		13		4,650
Other common operating property	—		274		274
Total Property, Plant and Equipment in Service	21,001		13,141		34,142
Total accumulated depreciation	(5,363)		(4,436)		(9,799)
Total Net Property, Plant and Equipment in Service	15,638		8,705		24,343
Construction work in progress	1,384		1,024		2,408
Total Property, Plant and Equipment	$	17,022	$	9,729	$	26,751

Capitalized interest costs were $33 million, $51 million and $51 million for the years ended December 31, 2021, 2020 and 2019, respectively. Accrued liabilities for property, plant and equipment additions were $297 million, $285 million and $357 million as of December 31, 2021, 2020 and 2019, respectively.

We impaired or wrote off amounts of $20 million, $7 million and $11 million for the years ended December 31, 2021, 2020 and 2019, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction.

Depreciation expense for the years ended December 31, 2021, 2020 and 2019, amounted to $1,001 million, $973 million and $918 million, respectively.

In 2021, an indicator of impairment was identified for the New England Clean Energy Connect (NECEC) project resulting from a Maine referendum decision and we performed a test of recoverability in which no impairment loss was recognized. As of December 31, 2021 and 2020, we have capitalized approximately $546 million and $180 million, respectively, for the NECEC project.

Note 9. Asset retirement obligations

AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities.

The reconciliation of ARO carrying amounts for the years ended December 31, 2021 and 2020 consisted of:

(Millions)
As of December 31, 2019	$	190
Liabilities settled during the year	(2)
Liabilities incurred during the year	9
Accretion expense	11
Revisions in estimated cash flows (a)	2
As of December 31, 2020	$	210
Liabilities settled during the year	(2)
Liabilities incurred during the year	7
Accretion expense	12
Revisions in estimated cash flows (a)	26
As of December 31, 2021	$	253

(a)Represents an increase in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities.

Several of the wind generation facilities have restricted cash for purposes of settling AROs. As of both December 31, 2021 and 2020, restricted cash related to AROs was $3 million. These amounts have been included in “Other Assets” on our consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in our consolidated statements of income.

We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for

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decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains.

Note 10. Debt

Long-term debt as of December 31, 2021 and 2020 consisted of:

As of December 31,		2021			2020
	Maturity Dates	Balances		Interest Rates	Balances		Interest Rates
(Millions)
First mortgage bonds - fixed (a)	2022-2051	$	2,759	1.85%-8.00%	$	2,575	1.85%-8.00%
Unsecured pollution control notes - fixed	2023-2029	478		1.40%-3.50%	478		1.40%-3.50%
Other various non-current debt - fixed	2022-2050	5,110		1.95%-6.66%	4,785		1.95%-7.80%
Unamortized debt issuance costs and discount		(53)			(47)
Total Debt		8,294			7,791
Less: debt due within one year, included in current liabilities		372			313
Total Non-current Debt		$	7,922		$	7,478

(a)The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $7,871 million.

Iberdrola Loan

On December 14, 2020, AVANGRID and Iberdrola entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid with the proceeds of the common share issuance described in Note 1.

Other 2021 Long-Term Debt Issuances

Company	Issue Date	Type	Amount (Millions)		Interest rate		Maturity
NYSEG	9/24/2021	Unsecured Notes	$	350	2.15	%	2031
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.91	%	2051
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.10	%	2031
CMP	12/15/2021	First Mortgage Bonds	$	200	2.05	%	2031
SCG	12/15/2021	First Mortgage Bonds	$	40	2.05	%	2031

Long-term debt maturities, including sinking fund obligations, due over the next five years consist of:

2022		2023		2024		2025		2026		Total
(Millions)
$	372	$	439	$	612	$	1,107	$	660	$	3,190

We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were in breach of covenants or of any obligation that could trigger the early redemption of our debt as of both December 31, 2021 and 2020 and throughout 2021 and 2020.

Fair Value of Debt

As of December 31, 2021 and 2020, the estimated fair value of long-term debt, including the Iberdrola Loan as of December 31, 2020, was $9,155 million and $12,166 million, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy.

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Short-term Debt

AVANGRID had $159 million and $307 million of notes payable as of December 31, 2021 and 2020, respectively.

AVANGRID has a commercial paper program with a limit of $2 billion which is backstopped by the AVANGRID credit facilities described below. As of December 31, 2021 and 2020, the amount of notes payable under the commercial paper program was $0 and $309 million, respectively, presented net of discounts on the balance sheet. As of December 31, 2020, the weighted-average interest rate on outstanding commercial paper was 0.32%.

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 contains a commitment from lenders, which will expire on April 20, 2022 if not terminated by AVANGRID at an earlier date 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 December 31, 2021, we had no borrowings outstanding under this credit facility.

Since the AVANGRID Credit Facility is also a backstop to the AVANGRID commercial paper program, the total amount available under the facility as of December 31, 2021 was $3,575 million.

2020 Credit Facility

During 2020, we entered into a revolving credit agreement with several lenders, or the 2020 Credit Facility, that provides maximum borrowings up to $500 million. We terminated this facility on April 28, 2021.

Iberdrola Group Credit Facility

AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both December 31, 2021 and 2020, there was no outstanding amount under this credit facility.

Supplier Financing Arrangements

We operate a supplier financing arrangement. During 2021, we arranged for the extension of payment terms with some suppliers, which could elect to be paid by a financial institution earlier than maturity under supplier financing arrangements. Due to the interest cost associated with these arrangements, the balances are classified as "Notes payable" on our consolidated balance sheets. The balance relates to capital expenditures and, therefore, is treated as non-cash activity. As of December 31, 2021 and 2020, the amount of notes payable under supplier financing arrangements was $161 million and $0, respectively. As of December 31, 2021, the weighted average interest rate on the balance was 0.82%.

Note 11. Fair Value of Financial Instruments and Fair Value Measurements

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

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

•NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based

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upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1.

•NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the 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 12 for further discussion of CfDs).

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

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

We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2.

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

Restricted cash was $3 million and $4 million as of December 31, 2021 and 2020, respectively and is included in “Other Assets” on our consolidated balance sheets.

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The financial instruments measured at fair value as of December 31, 2021 and 2020 consisted of:

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

As of December 31, 2020	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity and other investments with readily determinable fair values	$	49	$	14	$	—	$	—	$	63
Derivative assets
Derivative financial instruments - power	$	5	$	31	$	105	$	(54)	$	87
Derivative financial instruments - gas	—		24		19		(35)		8
Contracts for differences	—		—		2		—		2
Total	$	5	$	55	$	126	$	(89)	$	97
Derivative liabilities
Derivative financial instruments - power	$	(23)	$	(31)	$	(23)	$	72	$	(5)
Derivative financial instruments - gas	(1)		(9)		(2)		9		(3)
Contracts for differences	—		—		(88)		—		(88)
Derivative financial instruments – Other	—		—		—		—		—
Total	$	(24)	$	(40)	$	(113)	$	81	$	(96)

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The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2021, 2020 and 2019 consisted of:

(Millions)	2021		2020		2019
Fair value as of January 1,	$	13	$	25	$	(15)
Gains for the year recognized in operating revenues	21		8		53
Losses for the year recognized in operating revenues	(34)		(2)		(2)
Total gains or losses for the period recognized in operating revenues	(13)		6		51
Gains recognized in OCI	2		1		2
Losses recognized in OCI	(52)		(3)		(3)
Total gains or losses recognized in OCI	(50)		(2)		(1)
Net change recognized in regulatory assets and liabilities	13		6		5
Purchases	(17)		(2)		(22)
Settlements	(13)		(15)		4
Transfers out of Level 3 (a)	(2)		(5)		3
Fair value as of December 31,	$	(69)	$	13	$	25
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$	(13)	$	6	$	51

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

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 December 31, 2021.

Index	Avg.		Max.		Min.
NYMEX ($/MMBtu)	$	3.18	$	6.52	$	2.27
AECO ($/MMBtu)	$	2.41	$	5.69	$	1.53
Ameren ($/MWh)	$	32.23	$	93.59	$	18.01
COB ($/MWh)	$	46.83	$	231.90	$	9.15
ComEd ($/MWh)	$	29.60	$	86.32	$	14.98
ERCOT N hub ($/MWh)	$	35.05	$	140.00	$	13.66
ERCOT S hub ($/MWh)	$	34.24	$	140.00	$	13.88
Indiana hub ($/MWh)	$	34.20	$	93.81	$	20.74
Mid C ($/MWh)	$	43.53	$	229.90	$	5.15
Minn hub ($/MWh)	$	28.82	$	90.99	$	15.23
NoIL hub ($/MWh)	$	29.35	$	84.00	$	14.64
PJM W hub ($/MWh)	$	33.49	$	113.93	$	17.78

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

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

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

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

The determination of fair value of the CfDs (see Note 12 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	December 31, 2021
Risk of non-performance	0.39% - 0.51%
Discount rate	0.97% - 1.26%
Forward pricing ($ per KW-month)	$2.00 - $4.80

Note 12. 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 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 December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets:

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

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As of December 31, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	3	$	5	$	3	$	3
Derivative liabilities	(3)		(4)		(34)		(78)
	—		1		(31)		(75)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		—
	—		—		(1)		—
Total derivatives before offset of cash collateral	—		1		(32)		(75)
Cash collateral receivable	—		—		18		1
Total derivatives as presented in the balance sheet	$	—	$	1	$	(14)	$	(74)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021	2020
(Millions)
Wholesale electricity purchase contracts (MWh)	5.7	5.6
Natural gas purchase contracts (Dth)	9.4	9.5
Fleet fuel purchase contracts (Gallons)	2.0	2.5

Derivatives not designated as hedging instruments

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

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

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The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of December 31, 2021 and 2020 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2021, 2020 and 2019 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						For the Year Ended December 31,
December 31, 2021	Electricity		Natural Gas		2021	Electricity		Natural Gas
Regulatory assets	$	—	$	—	Purchased power, natural gas and fuel used	$	(23)	$	(11)
Regulatory liabilities	$	(16)	$	(3)
December 31, 2020					2020
Regulatory assets	$	17	$	1	Purchased power, natural gas and fuel used	$	55	$	4
Regulatory liabilities	$	—	$	—
					2019
					Purchased power, natural gas and fuel used	$	25	$	1

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 December 31, 2021, UI has recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $73 million, a gross derivative liability of $75 million ($72 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2020, UI has recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $86 million, a gross derivative liability of $88 million ($85 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 years ended December 31, 2021, 2020 and 2019, respectively, were as follows:

	Years Ended December 31,
	2021		2020		2019
(Millions)
Derivative Assets	$	—	$	—	$	(3)
Derivative Liabilities	$	13	$	6	$	8

Certain foreign currency exchange contracts are not designated as hedging instruments. For the years ended December 31, 2021 and 2020, we recorded a gain of $0 and $4 million, respectively, related to our foreign currency contracts not designated as hedging instruments, included in "Other income" in our consolidated statements of income. No amounts were recorded for the year ended December 31, 2019.

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Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Year Ended December 31,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss (Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2021
Interest rate contracts	$	—	Interest expense	$	4	$	298
Commodity contracts	2		Purchased power, natural gas and fuel used	(1)		1,719
Foreign currency exchange contracts	(5)			—
Total	$	(3)		$	3
2020
Interest rate contracts	$	—	Interest expense	$	4	$	316
Commodity contracts	(1)		Purchased power, natural gas and fuel used	1		1,379
Foreign currency exchange contracts	1			—
Total	$	—		$	5
2019
Interest rate contracts	$	—	Interest expense	$	6	$	310
Commodity contracts	—		Purchased power, natural gas and fuel used	1		1,509
Foreign currency exchange contracts	(1)			—
Total	$	(1)		$	7

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

On June 20, 2019, Networks entered into a forward contract to hedge the foreign currency exchange risk of approximately $100 million in forecasted capital expenditures through June 2023. The forward foreign currency contracts, which were designated and qualified as cash flow hedges, were settled in December 2021. The net loss of $5 million in accumulated OCI on the foreign exchange derivative will be reclassified into earnings over the useful life of the underlying capital expenditures.

The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $47 million and $51 million as of December 31, 2021 and 2020, respectively. We recorded $4 million, $4 million and $6 million in net derivative losses related to discontinued cash flow hedges during the years ended December 31, 2021, 2020 and 2019, respectively. We will amortize approximately $4 million of discontinued cash flow hedges in 2022.

Unrealized losses of $1 million on hedge derivatives are reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2021. We expect that immaterial amounts of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months.

(b) Renewables activities

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

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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 December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021	2020
(MWh/Dth in Millions)
Wholesale electricity purchase contracts	4	3
Wholesale electricity sales contracts	10	7
Natural gas and other fuel purchase contracts	20	24
Financial power contracts	9	12
Basis swaps - purchases	30	35
Basis swaps - sales	—	2

The fair values of derivative contracts associated with Renewables' activities as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021		2020
(Millions)
Wholesale electricity purchase contracts	$	36	$	4
Wholesale electricity sales contracts	(77)		11
Natural gas and other fuel purchase contracts	6		—
Financial power contracts	35		66
Basis swaps - purchases	—		7
Total	$	—	$	88

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 22, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of December 31, 2021, the fair value of the interest rate swap was a $58 million non-current liability. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred.

The tables below present Renewables' derivative positions as of December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets:

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

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As of December 31, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	47	$	89	$	2	$	9
Derivative liabilities	(23)		(2)		(4)		(11)
	24		87		(2)		(2)
Designated as hedging instruments
Derivative assets	8		15		2		7
Derivative liabilities	(5)		(6)		(3)		(10)
	3		9		(1)		(3)
Total derivatives before offset of cash collateral	27		96		(3)		(5)
Cash collateral (payable) receivable	(9)		(18)		—		—
Total derivatives as presented in the balance sheet	$	18	$	78	$	(3)	$	(5)

Derivatives not designated as hedging instruments

The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Year Ended December 31, 2021
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	1	$	(1)
Wholesale electricity sales contracts	(2)		(33)
Financial power contracts	4		(42)
Financial and natural gas contracts	(1)		(25)
Total loss included in operating revenues	$	2	$	(101)	$	6,974
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	32
Financial and natural gas contracts	—		12
Total gain included in purchased power, natural gas and fuel used	$	—	$	44	$	1,719
Total Gain (Loss)	$	2	$	(57)

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	Year Ended December 31, 2020
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	—
Wholesale electricity sales contracts	(1)		6
Financial power contracts	2		—
Financial and natural gas contracts	—		(13)
Total (loss) gain included in operating revenues	$	—	$	(7)	$	6,320
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(4)
Financial and natural gas contracts	—		6
Total gain included in purchased power, natural gas and fuel used	$	—	$	2	$	1,379
Total Loss	$	—	$	(5)

	Year Ended December 31, 2019
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	—
Wholesale electricity sales contracts	3		40
Financial power contracts	(3)		23
Financial and natural gas contracts	(1)		1
Total (loss) gain included in operating revenues	$	(2)	$	64	$	6,336
Purchased power, natural gas and fuel used
Financial power contracts	—		(1)
Financial and natural gas contracts	—		15
Total gain included in purchased power, natural gas and fuel used	$	—	$	14	$	1,509
Total (Loss) Gain	$	(2)	$	78

During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the year ended December 31, 2019.

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Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 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)
2021
Interest rate contracts	$	(58)	Interest Expense	$	—	$	298
Commodity contracts	$	(142)	Operating revenues	$	(3)	$	6,974
Total	$	(200)		$	(3)
2020
Commodity contracts	$	1	Operating revenues	$	6	$	6,320
2019
Commodity contracts	$	(5)	Operating revenues	$	3	$	6,336

(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 $59 million of gain included in accumulated OCI at December 31, 2021 is expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2021, 2020 and 2019.

(c) Corporate activities

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.

The net loss in accumulated OCI related to previously settled interest rate contracts is $48 million and $57 million as of December 31, 2021 and 2020, respectively. We amortized into income $9 million, $8 million and $2 million of the loss related to the settled interest rate contracts for the years ended December 31, 2021, 2020 and 2019, respectively. We will amortize approximately $9 million of the net loss on the interest rate contracts during 2022.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 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)
2021
Interest rate contracts	$	—	Interest expense	$	9	$	298
2020
Interest rate contracts	$	(27)	Interest expense	$	8	$	316
2019
Interest rate contracts	$	(24)	Interest expense	$	2	$	310

(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."

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The effects on our consolidated financial statements as of and for the year ended December 31, 2021 are as follows:

(millions)	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
As of December 31, 2021				Year Ended December 31, 2021
Current Assets	$	—	Interest Expense	$	(3)	$	298
Non-current liabilities	$	(19)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	19

(d) Counterparty credit risk management

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

The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit ratings on senior debt were to fall below investment grade. If such an event had occurred as of December 31, 2021, UI would have had to post an aggregate of approximately $19 million in collateral.

We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $67 million and $18 million as of December 31, 2021 and 2020, respectively. Derivative instruments settlements and collateral payments are included throughout the "Changes in operating assets and liabilities" section of operating activities in the 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 December 31, 2021 is $0, for which we have posted collateral.

Note 13. Leases

We have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 62 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option.

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The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Lease cost
Finance lease cost
Amortization of right-of-use assets	$	8	$	17	$	12
Interest on lease liabilities	3		4		3
Total finance lease cost	11		21		15
Operating lease cost	14		16		18
Short-term lease cost	4		3		5
Variable lease cost	4		—		2
Sublease income	—		—		—
Total lease cost	$	33	$	40	$	40

Balance sheet and other information as of December 31, 2021 and 2020 was as follows:

As of December 31,	2021			2020
(Millions, except lease term and discount rate)
Operating Leases
Operating lease right-of-use assets	$	148		$	153
Operating lease liabilities, current	12			8
Operating lease liabilities, long-term	149			154
Total operating lease liabilities	$	161		$	162
Finance Leases
Other assets	$	156		$	162
Other current liabilities	4			8
Other non-current liabilities	91			91
Total finance lease liabilities	$	95		$	99
Weighted-average Remaining Lease Term (years)
Finance leases	7.3			8.12
Operating leases	20.5			21.38
Weighted-average Discount Rate
Finance leases	3.49		%	3.71		%
Operating leases	3.06		%	3.21		%

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For the years ended December 31, 2021, 2020 and 2019 supplemental cash flow information related to leases was as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	16	$	13	$	13
Operating cash flows from finance leases	$	3	$	3	$	3
Financing cash flows from finance leases	$	6	$	9	$	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	$	—	$	46	$	1
Operating leases	$	10	$	94	$	3

As of December 31, 2021, maturities of lease liabilities were as follows:

	Finance Leases		Operating Leases
(Millions)
Year ending December 31,
2022	$	5	$	14
2023	53		14
2024	23		12
2025	2		11
2026	2		11
Thereafter	19		160
Total lease payments	104		223
Less: imputed interest	(9)		(62)
Total	$	95	161

Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $45 million and $47 million at December 31, 2021 and December 31, 2020, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility.

Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.

Note 14. Commitments and Contingent Liabilities

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

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project specific basis and not on a transmission owner’s total average transmission return. The complaints were consolidated and the administrative law judge issued an initial decision on March 22, 2016. The initial decision determined that, (1) for the fifteen month refund period in Complaint II, the base ROE should be 9.59% and that the ROE Cap (base ROE plus incentive ROEs) should be 10.42% and (2) for the fifteen month refund period in Complaint III and prospectively, the base ROE should be 10.90% and that the ROE Cap should be 12.19%. The initial decision in Complaints II and III is the administrative law judge’s recommendation to the FERC Commissioners.

CMP and UI reserved for refunds for Complaints I, II and III consistent with the FERC’s March 3, 2015 decision in Complaint I. Refunds were provided to customers for Complaint I. The CMP and UI total reserve associated with Complaints II and III is $27 million and $8 million, respectively, as of December 31, 2021, which has not changed since December 31, 2020, 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 of this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. On November 19, 2020, FERC issued an order addressing arguments raised on rehearing of its May 21, 2020 order, making minor adjustments to certain typographical errors with regard to some of the case inputs it included in its Risk Premium model analysis. However, those minor adjustments did not affect the outcome of the case, leaving the 10.02% ROE established by the May 21, 2020 order in place. Parties to these orders affecting the MISO transmission owners’ base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO’s submitted an amici curia brief in support of the MISO transmission owners’ on March 17, 2021. We cannot predict the outcome of these proceedings, including the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for our pending four Complaints.

On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (Supplemental NOPR) that proposes to eliminate the 50 basis-point ROE incentive for utilities who join Regional Transmission Organizations after 3 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 PPA entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the PPA 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 PPAs unjust and

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unreasonable. However, the proposed ruling did conclude that the price of the PPAs imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. On June 17, 2021, the FERC issued an Order Establishing Limited Remand remanding the case to the administrative law judge for additional detailed findings and legal analysis with respect to the impact of the conduct of one of the parties other than Renewables on their long-term contracts. The order did not address any of the other findings, including all of the findings with respect to Renewables, which remain pending. There is no specific timetable for the administrative law judge’s ruling. On July 9, 2021, Renewables filed a motion requesting that the FERC expeditiously issue a final decision with respect to the Renewables long-term contract rather than waiting for the administrative law judge’s ruling. We cannot predict the outcome of this proceeding.

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

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

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

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

On January 8, 2021, the Beatrice Corwin Living Irrevocable Trust, by and through its Authorized Trustee, Robert Corwin filed a complaint in the Supreme Court of the State of New York Westchester County against Iberdrola and the members of the Company’s Board of Directors, as defendants, and the Company, as a nominal defendant with respect to certain counts contained in the complaint. The complaint alleges certain violations of fiduciary duties by Iberdrola and the members of the Company’s Board of Directors related to the existence of certain pre-emptive rights provided to Iberdrola in the Shareholder Agreement between the Company and Iberdrola, dated December 16, 2015, and the binding nature of such rights. On March 29, 2021, the parties stipulated to and requested, and the Supreme Court of the State of New York Westchester County issued an Order providing for, the transfer of the venue of the complaint to the Supreme Court, County of New York. On May 20, 2021, the matter was transferred to New York County and assigned to the Commercial Division of the Supreme Court, County of New York. On September 3, 2021, the plaintiffs filed an amended verified complaint (i) dropping claims concerning the purported breach of AVANGRID’s articles of incorporation and New York’s statute concerning equal treatment among shareholders, (ii) adding and modifying their claims related to the duty of good faith and loyalty and (iii) adding allegations concerning the Iberdrola Loan and the May 2021 private placement of our common shares to Iberdrola and Hyde Partners, LLC. In addition, the plaintiffs are now purporting to bring a class action lawsuit. On October 22, 2021, we and our board of directors filed a motion to dismiss and Iberdrola filed a motion to dismiss and an application to stay discovery pending resolution of dispositive motions. On December 8, 2021, the plaintiffs filed an omnibus opposition to the motions to dismiss and the defendants' filed a reply to such motion on January 14, 2022. Oral arguments are scheduled March 17, 2022. We cannot predict the outcome of this matter.

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Power, Gas and Other Arrangements

Power and Gas Supply Arrangements – Networks

NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and the New York Power Authority, are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation.

NYSEG, RG&E, SCG, CNG and BGC (collectively, the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review.

The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the U.S. Gulf of Mexico region, in the Appalachia region and in Canada.

The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system.

The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months.

Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system.

Other arrangements include contractual obligations for property, plant and equipment, material and services on order but not yet delivered at December 31, 2021.

Power, Gas and Other Arrangements – Renewables

Gas purchase commitments consist of firm transport capacity to fuel the Klamath Cogen and Peaking gas generators. Power purchase commitments include the following: (i) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers (ii) a 95.6 MW (average) three-year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2022 and expiring in 2024) and (iii) a five-year purchase of 52 MW (average) hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2023). Power sales commitments include: (i) winter capacity sale of 150 MW through 2042, (ii) fixed price, fixed volume hydro energy sales through 2024, (iii) fixed price, fixed volume power sales off the Klamath Cogen facility, (iv) a seasonal tolling arrangement off the Klamath peaking facility with fixed capacity charges through 2024; (v) fixed price, fixed volume renewable energy credit sales off merchant wind facilities, (vi) sales of merchant wind farm capacity to various ISOs and (vii) sales of ancillary services (e.g., regulation and frequency response, generator imbalance, etc.) to third parties from Renewables’ Balancing Authority.

In June 2020, Renewables entered into a Payment In Lieu of Taxes (PILOT) agreement related to two of its projects with Torrance County, New Mexico. The agreement requires PILOT payments to Torrance County through 2049. The total amount of PILOT payments related to the two projects in 2021 was $1 million.

Renewables also has easement contracts which are included in the table below.

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Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2021 consisted of:

Year	Purchases		Sales
	(Millions)
2022	$	1,069	$	227
2023	168		122
2024	111		75
2025	65		28
2026	49		37
Thereafter	971		72
Totals	$	2,433	$	561

Guarantee Commitments to Third Parties

As of December 31, 2021, we had approximately $483 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including approximately $21 million related to Vineyard Wind. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind as described in Note 22, 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 December 31, 2021, neither we nor our subsidiaries have any liabilities recorded for these instruments.

NECEC Commitments

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. 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 during 2021.

Note 15. Environmental Liabilities

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

Waste sites

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

We have recorded an estimated liability of $7 million related to eleven of the twenty-six sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of December 31, 2021, our estimate for costs to remediate these sites ranges from $14 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the allocation of the clean-up costs.

Manufactured Gas Plants

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

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not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.

As of December 31, 2021, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $162 million to $276 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 December 31, 2021, 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 December 31, 2021 and 2020, the liability associated with our MGP sites in Connecticut was $113 million and $96 million, respectively, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates.

As of December 31, 2021 and 2020, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $303 million and $300 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 2082.

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 December 31, 2021, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $14 million and $7 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable.

English Station

In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was stayed in 2014 pending resolutions of other proceedings before the DEEP concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party.

In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs have appealed the court's decision to strike and oral arguments have taken place. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. The plaintiffs filed a petition to appeal to the Connecticut Supreme Court, which was denied, leaving only the claim against UI for unjust enrichment. We cannot predict the outcome of this matter.

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

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

As of both December 31, 2021 and 2020, the amount reserved related to English Station was $22 million. 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 16. Income Taxes

The Taxpayer Certainty and Disaster Tax Relief Act of 2019 (Division Q of the Further Consolidated Appropriations Act of 2020) was signed into law in 2019 that extended the PTC and ITC options for wind facilities to 60% of the full credit for facilities commencing construction in 2020, leaving in place phased down credits for projects commencing in years prior to 2020.

The Consolidated Appropriations Act, 2021, signed into law on December 27, 2020 provides extensions to renewable income tax incentives. Onshore and offshore wind projects may now claim a 60% PTC for projects commencing construction in 2020 and 2021. In addition, offshore wind may now elect to claim a 30% ITC for projects commencing construction through 2025. Onshore wind can claim an 18% ITC for projects commencing construction in 2020 or 2021, with no ITC thereafter.

Solar projects commencing construction before 2020 may claim a 30% ITC. Solar projects that commence construction from 2020-2022 may claim a 26% ITC, projects commencing construction in 2023 may claim a 22% ITC and projects commencing thereafter may claim a 10% ITC. The ITC statutes require solar projects be completed by the end of 2025 in order to claim the applicable ITCs except for projects under the 10% credit.

The Internal Revenue Service (IRS) previously provided continuity safe harbor guidance that requires renewable projects to be completed within four years of the year construction commences. Any projects that do not meet this requirement will fall outside of the safe harbor and be subject to IRS scrutiny with regard to the date construction commenced. In 2021, the IRS provided new guidance for an extension to a period of 6 years for the Continuity Safe Harbor for projects for which construction began in 2016 through 2019 and 5 years for the Continuity Safe Harbor for projects in which construction begin in 2020. Most importantly, this new guidance for the continuity requirement is satisfied if the taxpayer demonstrates satisfaction of either the Continuous Construction or the Continuous Efforts Tests, regardless of the method that the taxpayer used to begin construction. In late December 2020, the IRS issued a notice giving onshore wind projects on federal lands, with transmission permit requirements, and offshore wind projects 10 years to complete construction.

Since early 2020, and in response to regulatory orders received in most but not all of our operating jurisdictions, we began returning to customers both protected and unprotected excess accumulated deferred income tax (ADIT) from the 2017 Tax Act. Such amounts are subject to the terms of those orders while meeting the requirements of normalization for both ARAM and RSG methodologies.

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Current and deferred taxes charged to expense for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 31,	2021		2020		2019
(Millions)
Current
Federal	$	6	$	3	$	11
State	4		9		(6)
Current taxes charged to expense	10		12		5
Deferred
Federal	49		67		164
State	72		38		58
Deferred taxes charged to expense	121		105		222
Production tax credits	(109)		(87)		(57)
Investment tax credits	(1)		(1)		(1)
Total Income Tax Expense	$	21	$	29	$	169

The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 31,	2021		2020		2019
(Millions)
Tax expense at federal statutory rate	$	140	$	119	$	170
Depreciation and amortization not normalized	(19)		(13)		(23)
Investment tax credit amortization	(1)		(1)		(1)
Tax return related adjustments	—		1		(2)
Production tax credits	(109)		(87)		(57)
Tax equity financing arrangements	14		1		8
State tax expense (benefit), net of federal benefit	61		37		41
Excess ADIT amortization	(65)		(42)		—
Valuation allowance	21		12		4
Other, net	(21)		2		29
Total Income Tax Expense	$	21	$	29	$	169

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Deferred tax assets and liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Deferred Income Tax Liabilities (Assets)
Property related	$	4,257	$	4,147
Unfunded future income taxes	104		100
Federal and state tax credits	(844)		(731)
Federal and state NOL’s	(998)		(1,047)
Joint ventures/partnerships	188		167
Nontaxable grant revenue	(292)		(311)
Pension and other post-retirement benefits	1		22
Tax Act - tax on regulatory remeasurement	(352)		(382)
Valuation allowance	110		81
Other	(158)		(127)
Deferred Income Tax Liabilities	$	2,016	$	1,919
Deferred tax assets	$	2,644	$	2,598
Deferred tax liabilities	4,660		4,517
Net Accumulated Deferred Income Tax Liabilities	$	2,016	$	1,919

As of December 31, 2021, we had gross federal tax net operating losses of $3.6 billion, federal PTCs and ITCs, federal R&D tax credits and other federal credits of $805 million, state tax effected net operating losses of $314 million in several jurisdictions and miscellaneous state tax credits of $146 million available to carry forward and reduce future income tax liabilities. For federal purposes, we recognized a valuation allowance of $37 million, and for state purposes, we recognized a valuation allowance of $73 million. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2023. The more significant state net operating losses begin to expire in 2024.

Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. The valuation allowance for deferred tax assets as of December 31, 2021 and 2020 was $110 million and $81 million, respectively. Valuation allowances have been established on various federal tax credits, state net operating losses and state tax credit carryforwards. The Company has recorded a federal valuation allowance on its federal tax credit carryforwards of $37 million and has recorded a state valuation allowance on its state net operating losses and state tax credit carryforwards of $73 million. The $29 million increase in valuation allowance from 2020 to 2021 includes an increase of $21 million for additional valuation allowance on Federal tax credit carryforwards and an increase of $8 million on state net operating losses and state tax credits.

The reconciliation of unrecognized income tax benefits for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years ended December 31,	2021		2020		2019
(Millions)
Beginning Balance	$	127	$	148	$	153
Increases for tax positions related to prior years	3		11		14
Increases for tax positions related to current year	—		—		16
Decreases for tax positions related to prior years	(3)		(32)		(18)
Reduction for tax position related to settlements with taxing authorities	—		—		(17)
Ending Balance	$	127	$	127	$	148

Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information.

Accruals for interest and penalties on tax reserves were immaterial for the years ended December 31, 2021, 2020 and 2019. If recognized, $107 million of the total gross unrecognized tax benefits would affect the effective tax rate.

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As of December 31, 2021, unrecognized tax benefits are primarily attributed to state tax matters in New York, in which a decrease could occur upon settlement of an outstanding audit during 2022.

AVANGRID and its subsidiaries, without ARHI, have been audited for the federal tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. Tax years 2010 and forward are open for potential federal adjustments. All New York state returns, which were filed without ARHI, are closed through 2011 and Maine state returns are closed through 2015.

All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. All New York combined state returns are closed for adjustment through 2011. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period.

As of December 31, 2021, UIL is subject to audit of its federal tax return for years 2014 through its short period 2015. UIL's short period ending in 2015 is open and subject to Connecticut audit.

Note 17. Post-retirement and Similar Obligations

AVANGRID and its subsidiaries sponsor a number of retirement benefit plans. The plans include qualified defined benefit pension plans, supplemental non-qualified pension plans, defined contribution plans and other postretirement benefit plans for eligible employees and retirees. Eligibility and benefits vary depending on each plan's design. For example, certain benefits are based on years of service and final average compensation while others may use a cash balance formula that calculates benefits using a percentage of annual compensation.

Qualified Retirement Benefit Plans

As of December 31, 2021 and 2020, our obligations and funded status consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
(Millions)
Change in benefit obligation
Benefit Obligation as of January 1,	$	3,819	$	3,669	$	452	$	439
Service cost	40		47		3		3
Interest cost	87		107		10		13
Plan amendments	2		7		—		—
Actuarial loss (gain)	(184)		236		(23)		29
Curtailments	(38)		(21)		—		—
Benefits paid	(239)		(226)		(34)		(32)
Benefit Obligation as of December 31,	3,487		3,819		408		452
Change in plan assets
Fair Value of Plan Assets as of January 1,	3,092		2,848		167		155
Actual return on plan assets	237		388		15		26
Employer contributions	27		84		12		18
Curtailments	(38)		(2)		—		—
Benefits paid	(239)		(226)		(67)		(32)
Fair Value of Plan Assets as of December 31,	3,079		3,092		127		167
Funded Status as of December 31,	$	(408)	$	(727)	$	(281)	$	(285)

During 2021, the pension benefit obligation had an actuarial gain of $184 million, primarily due to a $205 million gain from increases in discount rates. There were no significant gains or losses relating to the postretirement benefit obligations.

During 2020, the pension benefit obligation had an actuarial loss of $236 million, primarily due to a $276 million loss from decreases in discount rates. The only significant plan change in 2020 was an agreement to freeze the UI union pension plan. There were no significant gains or losses relating to the postretirement benefit obligations.

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As of December 31, 2021 and 2020, funded status amounts recognized on our consolidated balance sheets consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
(Millions)
Current liabilities	$	—	$	—	$	(5)	$	(5)
Non-current liabilities	(408)		(727)		(276)		(280)
Total	$	(408)	$	(727)	$	(281)	$	(285)

We have determined that Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans.

Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2021 and 2020 consisted of:

	Pension Benefits				Postretirement Benefits
Years Ended December 31,	2021		2020		2021		2020
(Millions)
Net loss (gain)	$	271	$	610	$	(18)	$	14
Prior service cost (credit)	$	10	$	10	$	(1)	$	(8)

Amounts recognized in OCI for ARHI for the years ended December 31, 2021 and 2020, consisted of:

	Pension Benefits				Postretirement Benefits
Years Ended December 31,	2021		2020		2021		2020
(Millions)
Net loss (gain)	$	16	$	21	$	(5)	$	(7)

As of December 31, 2021 and 2020, the projected benefit obligation (PBO) exceeded the fair value of pension plan assets for all qualified plans. The accumulated benefit obligation (ABO) exceeded the fair value of pension plan assets for all but one plan, as of December 31, 2021, and for all of our qualified plans, as of December 31, 2020. The aggregate PBO and ABO and the fair value of plan assets for our underfunded qualified plans consisted of: 

	PBO in excess of plan assets
As of December 31,	2021		2020
(Millions)
Projected benefit obligation	$	3,487	$	3,819
Fair value of plan assets	$	3,079	$	3,092
	ABO in excess of plan assets
As of December 31,	2021		2020
(Millions)
Accumulated benefit obligation	$	1,790	$	3,629
Fair value of plan assets	$	1,536	$	3,092

As of December 31, 2021 and 2020, the accumulated postretirement benefits obligation for all qualified plans exceeded the fair value of plan assets.

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Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
For the years ended December 31,	2021		2020		2019		2021		2020		2019
(Millions)
Net Periodic Benefit Cost:
Service cost	$	39	$	46	$	41	$	3	$	3	$	3
Interest cost	86		106		128		10		13		16
Expected return on plan assets	(199)		(198)		(190)		(7)		(8)		(7)
Amortization of prior service cost (benefit)	2		1		(1)		(5)		(9)		(10)
Amortization of net loss	115		124		113		2		2		1
Settlement charge	6						—
Net Periodic Benefit Cost	49		79		91		3		1		3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	—		(18)		—		—		—		—
Settlement charge	(6)		—		—		—		—		—
Net loss (gain)	(218)		46		80		(31)		11		13
Amortization of net loss	(115)		(124)		(113)		(2)		(2)		(1)
Current year prior service cost (credit)	2		7		(2)		1		—		—
Amortization of prior service (cost) benefit	(2)		(1)		1		5		9		10
Total Other Changes	(339)		(90)		(34)		(27)		18		22
Total Recognized	$	(290)	$	(11)	$	57	$	(24)	$	19	$	25

Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
For the years ended December 31,	2021		2020		2019		2021		2020		2019
(Millions)
Net Periodic Benefit Cost:
Service cost	$	1	$	1	$	1	$	—	$	—	$	—
Interest cost	1		1		2		—		—		—
Expected return on plan assets	(2)		(2)		(2)		—		—		—
Amortization of net loss (gain)	2		2		1		(1)		(1)		(1)
Settlement charge	1		1		—		—		—		—
Net Periodic Benefit Cost	3		3		2		(1)		(1)		(1)
Other Changes in plan assets and benefit obligations recognized in OCI:
Settlement charge	(1)		—		—		(1)		—		—
Net loss (gain)	(3)		1		—		1		—		—
Amortization of net (loss) gain	(2)		(2)		(1)		1		1		1
Amortization of prior service cost	—		—		—		—		—		(2)
Total Other Changes	(6)		(1)		(1)		1		1		(1)
Total Recognized	$	(3)	$	2	$	1	$	—	$	—	$	(2)

The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the service cost component in other operating expenses net of capitalized portion and include the components of net periodic benefit cost other than the service cost component in other expense. 

148

The weighted-average assumptions used to determine our benefit obligations as of December 31, 2021 and 2020 consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
Discount rate	2.85	%	2.34	%	2.66	%	2.19	%
Rate of compensation increase	3.53	%	3.52	%	3.50	%	3.50	%
Interest crediting rate	2.87	%	2.87	%	N/A		N/A

The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit obligations.

The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
Years Ended December 31,	2021		2020		2019		2021		2020		2019
Discount rate	2.34	%	3.01	%	3.98	%	2.19	%	2.99	%	3.97	%
Expected long-term return on plan assets	7.30	%	7.30	%	7.30	%	4.05	%	5.09	%	5.08	%
Rate of compensation increase	3.52	%	3.66	%	3.79	%	3.50	%	3.48	%	3.50	%

We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement.

Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
Health care cost trend rate assumed for next year	5.00%/7.00%		5.25%/7.25%
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2029 / 2025		2029 / 2025

Contributions

We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. We expect to contribute $22 million and $11 million, respectively, to our pension and other postretirement benefit plans during 2022.

Estimated Future Benefit Payments

Expected benefit payments as of December 31, 2021 consisted of:

(Millions)	Pension Benefits		Postretirement Benefits
2022	$	217	$	30
2023	$	212	$	29
2024	$	214	$	29
2025	$	213	$	28
2026	$	215	$	27
2027 - 2031	$	1,057	$	122

Non-Qualified Retirement Benefit Plans

We also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for these plans, which is included in Other current and Other non-current liabilities on our consolidated balance sheets, was $63 million and $59 million at December 31, 2021 and 2020, respectively.

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Plan Assets

Our pension plan assets are consolidated in one master trust. A consolidated master trust provides for a uniform investment manager lineup and an efficient, cost effective means of allocating income and expenses to each plan. Our primary investment objective is to have a diversified asset allocation policy that mitigates risk and volatility while meeting or exceeding our projected expected return to ensure that current and future benefit obligations are adequately funded. Further diversification and risk mitigation is achieved within each asset class by avoiding significant concentrations in certain markets, utilizing a combination or passive and active investment managers with unique skill and expertise, a systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income and alternative investment markets.

Networks and ARHI have established target asset allocation policies with allowable ranges for their pension plan assets within broad categories of asset classes made up of Return-Seeking investments and Liability-Hedging/Fixed Income investments. In 2020, a streamlined investment policy was implemented, which aligned Networks target allocations to the estimated funded status of each specific plan. Return-Seeking assets range from 25%-60% and Liability-Hedging assets range from 40%-75%. Return-Seeking assets include investments in domestic, international and emerging equity real estate, global asset allocation strategies and hedge funds. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges.

The fair values of pension plan assets, by asset category, as of December 31, 2021, consisted of:

As of December 31, 2021			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	69	$	20	$	49	$	—
U.S. government securities	298		298		—		—
Common stocks	138		138		—		—
Registered investment companies	276		276		—		—
Corporate bonds	837		—		837		—
Preferred stocks	1		1		—		—
Common collective trusts	862		—		862		—
Other, principally annuity, fixed income	51		—		51		—
	$	2,532	$	733	$	1,799	$	—
Other investments measured at net asset value	547
Total	$	3,079

The fair values of pension plan assets, by asset category, as of December 31, 2020, consisted of:

As of December 31, 2020			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	120	$	—	$	120	$	—
U.S. government securities	177		177		—		—
Common stocks	107		107		—		—
Registered investment companies	301		301		—		—
Corporate bonds	710		—		710		—
Preferred stocks	1		1		—		—
Common collective trusts	1,018		—		1,018		—
Other, principally annuity, fixed income	50		6		44		—
	$	2,484	$	592	$	1,892	$	—
Other investments measured at net asset value	608
Total	$	3,092

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Valuation Techniques

We value our pension plan assets as follows:

•Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings.

•U.S. government securities – at the closing price reported in the active market in which the security is traded.

•Common stocks – at the closing price reported in the active market in which the individual investment is traded.

•Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Preferred stocks – at the closing price reported in the active market in which the individual investment is traded.

•Common collective trusts/Registered investment companies – Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2: the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

•Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient.

Our postretirement plan assets are consolidated with one trustee in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements. The assets are invested in various asset classes to achieve sufficient diversification and mitigate risk. This is achieved for our VEBA assets by utilizing multiple institutional mutual and money market funds, which provide exposure to different segments of the securities markets. The 401(h) assets are invested alongside the Pension assets they are tied to and share the same asset allocation policy. Approximately 54% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes.

In 2020, a streamlined investment policy was implemented for Networks and ARHI that aligned target allocations. Equities range from 49%-69% and Fixed Income assets range from 31-51%. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed Income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. We primarily minimize the risk of large losses through diversification, but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews. Systematic rebalancing within target ranges increases the probability of increasing the projected expected return, while mitigating risk, should any asset categories drift outside their specified ranges.

The fair values of other postretirement plan assets, by asset category, as of December 31, 2021 consisted of:

As of December 31, 2021			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	5	$	—	$	5	$	—
U.S. government securities	1		1		—		—
Common stocks	1		1		—		—
Registered investment companies	101		101		—		—
Corporate bonds	3		—		3		—
Preferred stocks	—		—		—		—
Common collective trusts	5		—		5		—
Other, principally annuity, fixed income	9		—		9		—
	$	125	$	103	$	22	$	—
Other investments measured at net asset value	2
Total	$	127

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The fair values of other postretirement plan assets, by asset category, as of December 31, 2020 consisted of:

As of December 31, 2020			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	6	$	—	$	6	$	—
U.S. government securities	1		1		—		—
Registered investment companies	141		141		—		—
Corporate bonds	3		—		3		—
Common collective trusts	4		—		4		—
Other, principally annuity, fixed income	9		—		9		—
	$	164	$	142	$	22	$	—
Other investments measured at net asset value	3
Total	$	167

Valuation Techniques

We value our postretirement plan assets as follows:

•Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings.

•U.S. government securities – at the closing price reported in the active market in which the security is traded.

•Common stocks and registered investment companies – at the closing price reported in the active market in which the individual investment is traded.

•Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Common collective trusts – the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

•Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient.

Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2021 and 2020.

Defined contribution plans

We also have defined contribution plans defined as 401(k)s for all eligible AVANGRID employees. There are various match formulas depending on years of service, age and pension plan closure/freeze date. For the years ended December 31, 2021, 2020 and 2019, the annual contributions we made to these plans was $58 million, $49 million and $40 million, respectively.

Note 18. Equity

As of December 31, 2021 and 2020, we had 112,543 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2021 and 2020, we issued 77,883,713 and 42,777 shares of common stock, respectively, and released 301,239 and 72,028 shares of common stock held in trust, respectively, each having a par value of $0.01. See Note 1 for information on our May 2021 equity issuance.

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 target relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2021, 694,148 shares were repurchased pursuant to the stock repurchase program primarily as an advanced re-purchase to hedge a portion of the anticipated payouts under AVANGRID stock based compensation plans. As of December 31, 2021, a total of 997,983 shares have been repurchased in the open market,

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all of which are included as AVANGRID treasury shares. As of December 31, 2021, the total cost of all repurchases, including commissions, was $47 million.

Accumulated OCI (Loss)

Accumulated OCI (Loss) for the years ended December 31, 2021, 2020 and 2019 consisted of:

Accumulated Other Comprehensive Income (Loss)	As of December 31, 2018		Adoption of new accounting standard		2019 Change		As of December 31, 2019		2020 Change		As of December 31, 2020		2021 Change		As of December 31, 2021
(Millions)
Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $0 for 2019, $0 for 2020 and $0 for 2021	$	(11)	$	(2)	$	1	$	(12)	$	—	$	(12)	$	2	$	(10)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $(1) for 2019, $3 for 2020 and $(1) for 2021	(6)		—		(1)		(7)		(13)		(20)		(8)		(28)
Unrealized loss from equity method investment, net of income tax benefit of $(3) for 2021 (a)	$	—	$	—	$	—	$	—	$	—	$	—	$	(9)	$	(9)
Unrealized (loss) gain on derivatives qualifying as cash flow hedges:
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $(9) for 2019, $(7) for 2020 and $(44) for 2021	9		—		(22)		(13)		(22)		(35)		(159)		(194)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $3 for 2019, $2 for 2020 and $(3) for 2021 (b)	(64)		(10)		11		(63)		19		(44)		12		(32)
Loss on derivatives qualifying as cash flow hedges	(55)		(10)		(11)		(76)		(3)		(79)		(147)		(226)
Accumulated Other Comprehensive Loss	$	(72)	$	(12)	$	(11)	$	(95)	$	(16)	$	(111)	$	(162)	$	(273)

(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 19. 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.

The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Years Ended December 31,	2021		2020		2019
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	707	$	581	$	667
Denominator:
Weighted average number of shares outstanding - basic	358,086,621		309,494,939		309,491,082
Weighted average number of shares outstanding - diluted	358,578,608		309,559,387		309,514,910
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	1.97	$	1.88	$	2.16
Earnings Per Common Share, Diluted	$	1.97	$	1.88	$	2.16

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Note 20. Variable Interest Entities

We participate in certain partnership arrangements that qualify as 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 consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs.

On February 5, 2021, we closed on the final TEF agreement for Aeolus Wind Power VII, LLC (Aeolus VII) in a non-cash transaction. The four Aeolus VII wind farms total 688 MW of wind power. On September 9, 2021, we sold an additional TEF interest in Aeolus VII for $131 million. The $8 million difference between the amount received and the $139 million noncontrolling interest recognized was recorded as an adjustment to equity because there was no change in control as a result of the transaction. On November 4, 2021, we sold a TEF interest in Aeolus Wind Power VIII, LLC (Aeolus VIII) for $199 million, of which $8 million is held in escrow until certain conditions are met.

As of December 31, 2021, the assets and liabilities of the VIEs totaled approximately $2,039 million and $119 million, respectively. As of December 31, 2020, the assets and liabilities of VIEs totaled approximately $1,713 million and $107 million, respectively. At both December 31, 2021 and 2020, 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 December 31, 2021, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus VII and Aeolus VIII are our consolidated VIEs.

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

See Note 22 - Equity Method Investments for information on our VIE we do not consolidate.

Note 21. Grants, Government Incentives and Deferred Income

The changes in deferred income as of December 31, 2021 and 2020 consisted of:

(Millions)	Government grants		Other deferred income		Total
As of December 31, 2019	$	1,258	$	16	$	1,274
Disposals	(2)		—		(2)
Recognized in income	(66)		(2)		(68)
As of December 31, 2020	1,190		14		1,204
Disposals	—		—		—
Recognized in income	(65)		(9)		(74)
As of December 31, 2021	$	1,125	$	5	$	1,130

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Within deferred income, we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States Department of Treasury (DOT) provides eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the book to tax basis differences related to the property for income tax purposes within the nontaxable grant revenue deferred income tax liabilities (see Note 16 – Income Taxes).

We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grant’s terms and conditions, we are required to repay the grant funds to the DOT. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2021 and 2020.

Note 22. Equity Method Investments

On December 16, 2020, Renewables sold a 85% ownership interest in a wind farm located in South Dakota (Tatanka) to WEC Infrastructure involving total consideration of $238 million, excluding closing costs, and recognized a gain of $12 million, net of tax. The pre-tax gain of $16 million is included in "Other income (expense)" in our consolidated statements of income. Our retained investment in Tatanka of $24 million was valued based on an enterprise value of $298 million and applying an effective percentage of economic benefits retained of 7.97%, which was derived from a DCF model similar to the model used for Goodwill as described in Note 7. The net gain includes $4 million related to the remeasurement of our retained investment in Tatanka. The transaction was accounted for as a sale of assets and resulted in a loss of control. The retained 15% ownership interest is accounted for as an equity method investment. As of December 31, 2021, and 2020, the carrying value of our Tatanka investment was $23 million and $24 million, respectively.

On December 13, 2019, Renewables transferred a 50% ownership interest in a wind farm and a solar project located in Arizona (Poseidon) to Axium involving total consideration of $112 million, excluding closing costs, and recognized a gain of $96 million, net of tax. The pre-tax gain of $134 million is included in "Other income (expense)" in our consolidated statements of income. The net gain includes $50 million related to the remeasurement of our retained investment in Poseidon which was valued based on the consideration received in the transaction. The transaction was accounted for as the sale of a business and resulted in a loss of control. The retained 50% ownership interest is accounted for as an equity method investment. As of December 31, 2021 and 2020, the carrying value of our Poseidon investment was $96 million and $104 million, respectively.

In December 2018, Renewables sold 80% of our wholly owned subsidiary, Coyote Ridge Wind, LLC (Coyote Ridge), including substantially all of the related tax benefits, to WEC Infrastructure in exchange for $144 million of total proceeds with $84 million received in 2019 to complete the transaction. We recorded a gain of $4 million and $10 million from this transaction in “Other expense" in our consolidated statements of income for the years ended December 31, 2019 and 2018, respectively. We account for the remaining 20% membership interest under the equity method of accounting. As of December 31, 2021 and 2020, the carrying amount of our Coyote Ridge investment was $15 million and $16 million, respectively.

Renewables has two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC (Flat Rock I) and the Flat Rock Wind Power II LLC (Flat Rock II) wind farms located in upstate New York. Flat Rock I has a 231 MW capacity and Flat Rock II has a 91 MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. As of December 31, 2021 and 2020, the carrying amount of Flat Rock I was $93 million and $98 million, respectively, and Flat Rock II was $44 million and $47 million, respectively.

Renewables holds a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners (CIP). Vineyard Wind has acquired easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. The first easement area acquired was Lease Area 501 which contains 166,886 acres located southeast of Martha's Vineyard. Lease Area 501 was subsequently divided in 2021 creating Lease Area 534. In 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm (Vineyard Wind 1) and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. The Vineyard Wind 1 project will be located on Lease Area 501. In December 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project, which will be located on Lease area 534. In addition, in December 2021 Vineyard Wind’s Commonwealth Wind project, which will also be located on Lease Area 534 was selected as part of Massachusetts’ third offshore wind competitive procurement process. The Commonwealth Wind’s proposed 1,232 MW wind farm will deliver clean energy to the residents of Massachusetts primarily through contracts with the electric distribution companies in the state, subject to finalization of the power purchase agreements with the electric distribution companies.

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

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

Vineyard Wind 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 since it does not have a controlling interest in Vineyard Wind, and therefore we do not consolidate Vineyard Wind. As of December 31, 2021 and 2020, the carrying amount of Renewables' investment in Vineyard Wind was $141 million and $245 million, respectively.

On September 15, 2021, Renewables entered into an agreement with CIP to restructure Vineyard Wind, which closed on January 10, 2022. Following the restructuring agreement closing, Vineyard Wind 1 remains a 50-50 joint venture, Renewables has full ownership of the project company containing Lease Area 534, including the Park City Wind and Commonwealth Wind projects along with any remaining non-contracted area in Lease Area 534, and CIP has full ownership of the project company containing Lease Area 522. The consideration exchanged resulted in Renewables making a payment of approximately $168 million to CIP, and Renewables will recognize a gain ranging from $175 million to $200 million in 2022, driven by the increase in the market value of the leases and related development activities over its carrying value. The purchase price accounting is preliminary and subject to change.

Networks is a party to a 50-50 joint venture with Clearway Energy, Inc. in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is accounted for as an equity investment. As of December 31, 2021 and 2020, the carrying value of our GenConn investment was $99 million and $104 million, respectively.

Networks holds an approximate 20% ownership interest in New York TransCo. Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. On April 8, 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The selected project, New York Energy Solution (NYES), replaces nearly 80-year old transmission assets located in the upper to mid-Hudson Valley with streamlined, modernized technology, to enable surplus clean energy resources in upstate New York and help achieve the State’s energy goals. The total project cost is $600 million plus interconnection costs. New York Transco is subject to regulatory approval of its rates, terms and conditions with the FERC. As of both December 31, 2021 and 2020, the amount receivable from New York TransCo was $0. The investment in New York TransCo is accounted for as an equity investment. As of December 31, 2021 and 2020, the carrying value of our New York TransCo investment was $49 million and $30 million, respectively.

None of our joint ventures have any contingent liabilities or capital commitments, except for those disclosed above. Distributions received from equity method investments, excluding the return of capital as part of the Vineyard Wind 1 financial close disclosed above, amounted to $21 million, $22 million and $17 million for the years ended December 31, 2021, 2020 and 2019 respectively, which are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively. In addition, during the years ended December 31, 2021, 2020 and 2019, we received $11 million, $14 million and $9 million of distributions in RECs from our equity method investments. As of December 31, 2021, there was $10 million of undistributed earnings from our equity method investments. Capitalized interest costs related to equity method investments were $6 million, $8 million and $7 million for the years ended December 31, 2021, 2020 and 2019, respectively.

Note 23. Other Financial Statements Items

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Other income (expense)

Other income (expense) for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years ended December 31,	2021		2020		2019
(Millions)
Gain on sale of assets (a)	$	—	$	20	$	148
Allowance for funds used during construction	88		56		46
Carrying costs on regulatory assets	17		28		21
Non-service component of net periodic benefit cost	(37)		(62)		(79)
Other	(8)		(24)		(15)
Total Other Income (Expense)	$	60	$	18	$	121

(a) 2020 includes a $16 million gain from the Tatanka sale and 2019 includes a $134 million gain from the Poseidon sale (see Note 22).

Accounts receivable and unbilled revenues, net

Accounts receivable and unbilled revenues, net as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Trade receivables and unbilled revenues	$	1,420	$	1,295
Allowance for credit losses	(151)		(108)
Total Accounts receivable and unbilled revenues, net	$	1,269	$	1,187

The change in the allowance for credit losses as of December 31, 2021 and 2020 consisted of:

(Millions)
As of December 31, 2018	$	62
Current period provision	92
Write-off as uncollectible	(85)
As of December 31, 2019	$	69
Current period provision	83
Write-off as uncollectible	(44)
As of December 31, 2020	$	108
Current period provision	110
Write-off as uncollectible	(67)
As of December 31, 2021	$	151

DPA receivable balances were $108 million and $78 million as of December 31, 2021 and 2020, respectively. As of December 31, 2021 and 2020, our allowance for credit losses for DPAs was $68 million and $48 million, respectively.

Prepayments and Other Current Assets

Prepayments and other current assets as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Prepaid other taxes	$	95	$	135
Short-term investment (a)	—		300
Broker margin and collateral accounts	87		30
Other pledged deposits	4		2
Prepaid expenses	58		41
Other	1		17
Total	$	245	$	525

(a) Short-term investment from proceeds of the Iberdrola Loan.

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Other current liabilities

Other current liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Advances received	$	204	$	141
Accrued salaries	127		109
Short-term environmental provisions	52		49
Collateral deposits received	58		42
Pension and other postretirement	5		5
Finance leases	4		8
Other	34		14
Total	$	484	$	368

Disposition

On May 13, 2021, Renewables sold 100% of its ownership interest in two solar projects located in Nevada to Primergy Hot Pot Holdings LLC for total consideration of $35 million and recognized a gain of $11 million, net of tax. The pre-tax gain of $15 million is recorded in "Operating revenues" in our consolidated statements of income. The total consideration includes variable consideration that Renewables could receive based on the achievement of certain regulatory and project development milestones. The transaction was accounted for as an asset sale.

Note 24. 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 restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments, accelerated depreciation derived from repowering of wind farms, a legal settlement, costs incurred in connection with the COVID-19 pandemic and costs incurred related to the PNMR Merger.

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

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Segment information as of and for the year ended December 31, 2021 consisted of:

For the year ended December 31, 2021	Networks		Renewables		Other(a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,753	$	1,220	$	1	$	6,974
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	616		397		1		1,014
Operating income	876		26		(7)		895
Earnings (losses) from equity method investments	12		(5)		—		7
Interest expense, net of capitalization	217		1		80		298
Income tax expense (benefit)	98		(48)		(29)		21
Capital expenditures	2,294		680		2		2,976
Adjusted net income	661		170		(51)		780
As of December 31, 2021
Property, plant and equipment	18,737		10,118		11		28,866
Equity method investments	148		412		—		560
Total assets	$	26,126	$	12,578	$	800	$	39,504

(a)Includes Corporate and intersegment eliminations.

Segment information as of and for the year ended December 31, 2020 consisted of:

For the year ended December 31, 2020	Networks		Renewables		Other(a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,187	$	1,132	$	1	$	6,320
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	592		394		1		987
Operating income	877		(16)		8		869
Earnings (losses) from equity method investments	10		(13)		—		(3)
Interest expense, net of capitalization	234		7		75		316
Income tax expense (benefit)	120		(80)		(11)		29
Capital expenditures	1,838		943		—		2,781
Adjusted net income	568		115		(58)		625
As of December 31, 2020
Property, plant and equipment	17,079		9,662		10		26,751
Equity method investments	134		534		—		668
Total assets	$	24,592	$	12,867	$	364	$	37,823

(a)Includes Corporate and intersegment eliminations.

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Segment information for the year ended December 31, 2019 consisted of:

For the year ended December 31, 2019	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,150	$	1,184	$	2	$	6,336
Revenue - intersegment	14		—		(14)		—
Depreciation and amortization	549		383		1		933
Operating income	890		93		15		998
Earnings (losses) from equity method investments	11		(8)		—		3
Interest expense, net of capitalization	269		14		27		310
Income tax expense (benefit)	152		28		(11)		169
Capital expenditures	1,610		1,122		3		2,735
Adjusted net income	$	465	$	193	$	(17)	$	640

(a)Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019 is as follows:

Years Ended December 31,	2021		2020		2019
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	780	$	625	$	640
Adjustments:
Mark-to-market adjustments - Renewables (1)	(53)		(5)		76
Restructuring charges (2)	—		(6)		(6)
Accelerated depreciation from repowering (3)	—		(9)		(33)
Impact of COVID-19 (4)	(34)		(29)		—
Merger costs (5)	(12)		(6)		—
Legal settlement - Gas storage (6)	—		(5)		—
Income tax impact of adjustments	26		16		(10)
Net Income Attributable to Avangrid, Inc.	$	707	$	581	$	667

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

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

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

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

(5)Pre-merger costs incurred.

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

Note 25. Related Party Transactions

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

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Related party transactions for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Years Ended December 31,	2021				2020				2019
(Millions)	Sales To		Purchases From		Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(52)	$	1	$	(43)	$	1	$	(42)
Iberdrola Renovables Energia, S.L.	$	—	$	(10)	$	—	$	(9)	$	—	$	(9)
Iberdrola Financiación, S.A.	$	—	$	(9)	$	—	$	(7)	$	—	$	(3)
Vineyard Wind	$	14	$	—	$	9	$	—	$	13	$	—
Iberdrola Solutions	$	7	$	(39)	$	2	$	—	$	1	$	—
Other	$	2	$	(3)	$	—	$	—	$	1	$	(3)

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

Related party balances as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021				2020
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	3	$	(43)	$	2	$	(43)
Iberdrola Financiacion	$	—	$	(9)	$	—	$	(6)
Vineyard Wind	$	8	$	(8)	$	4	$	—
Iberdrola Solutions	$	—	$	(2)	$	5	$	—
Other	$	—	$	(1)	$	1	$	(1)

Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 10 for a discussion of the Iberdrola Loan.

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 December 31, 2021 and 2020 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 both December 31, 2021 and 2020, there was no outstanding amount under this credit facility.

We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable and notes receivable balances of $2 million and $5 million for the years ended December 31, 2021 and 2020, respectively. Renewables also had financial forward power contracts with Iberdrola Solutions to hedge Renewables' uncontracted wind exposure in Texas.

See Note 22 - Equity Method Investments for more information on transactions with our equity method investees.

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.

Note 26. Stock-Based Compensation

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). As of December 31, 2021, the total number of shares authorized for stock-based compensation plans was 2,500,000.

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Performance Stock Units

During 2016, 1,298,683 performance stock units (PSUs) were granted to certain officers and employees of AVANGRID. In 2017, 2018 and 2019, an additional 85,759, 75,350 and 3,881 PSUs, respectively, were granted to officers and employees of AVANGRID under the Plan with achievement measured based on certain performance and market-based metrics for the 2016 to 2019 time period.

The fair value of the PSUs on the grant date was $31.80 per share, which is expensed on a straight-line basis over the requisite service period of approximately seven years based on expected achievement. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recent quarterly dividend payment and the stock price as of the grant date.

In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved as earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes. The remaining unvested PSUs were forfeited. In May 2020, 42,777 shares of common stock were issued to settle the first installment payment and 2,605 PSUs were forfeited from the originally approved total number of PSUs. In March 2021, 45,661 shares of common stock were issued to settle the second installment payment. The final payment will occur in 2022.

During 2021, 1,336,787 PSUs, were granted to certain officers and employees of AVANGRID with achievement measured based on certain performance and market-based metrics for the 2021 to 2022 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.22 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date. The expense is recognized on a straight-line basis over the requisite service period of approximately four years based on expected achievement.

Restricted Stock Units

In June and October 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan two restricted stock units (RSUs) awards of 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vested in full in one installment in June and December 2020, respectively for each award. The fair value on the grant date was determined based on a price of $50.40 per share for the June 2018 awards and $47.59 per share for the October 2018 awards. In June 2020, 60,000 RSUs, plus dividend equivalents accrued through the vesting period, were settled for $3 million in cash. In March 2021, the October 2018 RSU grant was settled, net of applicable taxes, by issuing 5,953 shares of common stock.

In August 2020, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in three equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting dates. The fair value on the grant date was determined based on a price of $48.99 per share. In February 2021, the first installment of the RSU grant was settled by issuing 1,697 shares of common stock. In October 2021, this RSU grant was cancelled and the remaining unvested RSUs were forfeited.

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.

In June 2021, 17,500 RSUs were granted to an officer of AVANGRID with immediate vesting. The fair value on the grant date was determined based on a price of $53.59 per share. The RSU grant was settled, net of applicable taxes, by issuing 9,390 shares of common stock.

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

Phantom Share Units

In March 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards will vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to

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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 both June 2020 and March 2021, $2 million was paid to settle, respectively, the first and the second installments under this plan. As of both December 31, 2021 and 2020, the total liability was $2 million, which is included in other current and non-current liabilities.

The total stock-based compensation expense, which is included in "Operations and maintenance" of our consolidated statements of income for the years ended December 31, 2021, 2020 and 2019 was $18 million, $14 million and $3 million, respectively. The total income tax benefits recognized for stock-based compensation arrangements for each of the years ended December 31, 2021, 2020 and 2019, were $5 million, $4 million and $1 million, respectively.

A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2021, and changes during the fiscal year ended December 31, 2021, is presented below:

	Number of PSUs and RSUs	Weighted Average Grant Date Fair Value
Nonvested Balance – December 31, 2020	142,167	$	32.42
Granted	1,359,516	$	36.49
Forfeited	(90,603)	$	36.63
Vested	(87,751)	$	47.70
Nonvested Balance – December 31, 2021	1,323,328	$	36.05

As of December 31, 2021, total unrecognized costs for non-vested PSUs, RSUs and Phantom Shares was $25 million. The weighted-average period over which the PSU, RSU and Phantom Shares costs will be recognized is approximately 3 years.

The weighted-average grant date fair value of PSUs and RSUs granted during the year was $36.49 per share for the year ended December 31, 2021.

Note 27. Subsequent events

On February 16, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2022 to shareholders of record at the close of business on March 1, 2022.

On January 10, 2022 Renewables closed an agreement with CIP to restructure Vineyard Wind. See Note 22 - Equity Method Investments for more information on this transaction.

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Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF INCOME

FOR THE YEARS ENDED December 31, 2021, 2020 AND 2019

Years Ended December 31,	2021		2020		2019
(Millions)
Operating Revenues	$	—	$	—	$	—
Operating Expenses
Operating expense	19		10		3
Taxes other than income taxes	(11)		(11)		(12)
Total Operating Expenses	8		(1)		(9)
Operating (Loss) Income	(8)		1		9
Other Income
Other income	22		35		59
Equity earnings of subsidiaries	756		641		678
Interest expense	(93)		(109)		(93)
Income Before Income Tax	677		568		653
Income tax benefit	(30)		(13)		(14)
Net Income	$	707	$	581	$	667

See accompanying notes to Schedule I.

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Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED December 31, 2021, 2020, AND 2019

Years Ended December 31,	2021		2020		2019
(Millions)
Net Income	$	707	$	581	$	667
Other comprehensive loss of subsidiaries	(162)		(16)		(11)
Comprehensive Income	$	545	$	565	$	656

See accompanying notes to Schedule I.

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Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

BALANCE SHEETS

AS OF December 31, 2021 AND 2020

As of December 31,	2021		2020
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	1,424	$	1,438
Accounts receivable from subsidiaries	128		124
Notes receivable from subsidiaries	1,475		1,489
Prepayments and other current assets	52		357
Total current assets	3,079		3,408
Investments in subsidiaries	18,500		18,356
Other assets
Deferred income taxes	413		388
Other	3		3
Total other assets	416		391
Total Assets	$	21,995	$	22,155
Liabilities
Current Liabilities
Notes payable	—		308
Notes payable to subsidiaries	643		1,375
Accounts payable and accrued liabilities	3		12
Accounts payable to subsidiaries	9		9
Interest accrued	9		9
Interest accrued subsidiaries	1		10
Dividends payable	170		136
Total current liabilities	835		1,859
Derivative liabilities	19		—
Non-current debt	2,065		2,087
Non-current debt with affiliate	—		3,000
Total non-current liabilities	2,084		5,087
Total Liabilities	2,919		6,946
Equity
Stockholders' Equity:
Common stock	3		3
Additional paid-in capital	17,679		13,665
Treasury stock	(47)		(14)
Retained earnings	1,714		1,666
Accumulated other comprehensive loss	(273)		(111)
Total Equity	19,076		15,209
Total Liabilities and Equity	$	21,995	$	22,155

See accompanying notes to Schedule I.

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Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED December 31, 2021, 2020, AND 2019

Years Ended December 31,	2021		2020		2019
(Millions)
Net Cash used in Operating Activities	$	(397)	$	(142)	$	(1,299)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	130		(73)		633
Investments in subsidiaries	(1,026)		(591)		(399)
Return of capital from investments in subsidiaries	1,122		419		433
Other investments	300		(300)		—
Net Cash provided by (used in) Investing Activities	526		(545)		667
Cash Flow from Financing Activities
(Repayments) receipts of short-term notes payable from subsidiaries, net	(186)		(14)		107
Repayments of short-term notes payable	(309)		(253)		(27)
Proceeds from non-current debt	—		744		1,243
(Repayments) proceeds from non-current debt with affiliate	(3,000)		3,000		—
Repayments of non-current debt	—		(950)		—
Repurchase of common stock	(33)		(2)		—
Issuance of common stock	3,998		(1)		—
Dividends paid	(613)		(545)		(545)
Net Cash (used in) provided by Financing Activities	(143)		1,979		778
Net (Decrease) Increase in Cash and Cash Equivalents	(14)		1,292		146
Cash and Cash Equivalents, Beginning of Year	1,438		146		—
Cash and Cash Equivalents, End of Year	$	1,424	$	1,438	$	146

Supplemental Cash Flow Information
Cash paid for interest	$	74	$	111	$	85
Cash paid (refunded) payment for income taxes	$	(15)	$	65	$	43

See accompanying notes to Schedule I.

Note 1. Basis of Presentation

Avangrid, Inc. (AVANGRID) is a holding company and we conduct substantially all of our business through our subsidiaries. Substantially all of our consolidated assets are held by our subsidiaries. Accordingly, our cash flow and ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the distribution or other payment of their earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. Our condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. Our condensed financial statements should be read in conjunction with the consolidated financial statements and notes thereto of AVANGRID and subsidiaries (AVANGRID Group).

AVANGRID indirectly or directly owns all of the ownership interests of our significant subsidiaries. AVANGRID relies on dividends or loans from our subsidiaries to fund dividends to our primary shareholder.

AVANGRID’s significant accounting policies are consistent with those of the AVANGRID Group. For the purposes of these condensed financial statements, AVANGRID’s wholly owned and majority owned subsidiaries are recorded based upon our proportionate share of the subsidiaries net assets.

AVANGRID files a consolidated federal income tax return that includes the taxable income or loss of all our subsidiaries. Each subsidiary company is treated as a member of the consolidated group and determines its current and deferred taxes separately

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and settles its current tax liability or benefit each year directly with AVANGRID pursuant to a tax sharing agreement between AVANGRID and our members.

Proposed Merger with PNMR

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

Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, Avangrid, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals.

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

The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before April 20, 2023, as amended (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii)

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AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee).

In connection with the Merger, Iberdrola has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration.

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

On May 18, 2021, we issued 77,821,012 shares of common stock in two private placements. Iberdrola purchased 63,424,125 shares and Hyde Member LLC, a Delaware limited liability company and a wholly owned subsidiary of Qatar Investment Authority, purchased 14,396,887 shares of our common stock, par value $0.01 per share, at the purchase price of $51.40 per share, which was the closing price of the shares of our common stock on the NYSE as of May 11, 2021. Proceeds of the private placements were $4,000 million. $3,000 million of the proceeds were used to repay the Iberdrola Loan. After the effect of the private placements, Iberdrola retained its 81.5% ownership interest in AVANGRID.

Note 2. Common Stock

As of December 31, 2021, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 387,678,630 shares issued and 386,568,104 shares outstanding, 81.6% of which are owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $3 million and additional paid in capital of $17,679 million. As of December 31, 2020, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 309,794,917 shares issued and 309,077,300 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $ $0.01, for a total value of common stock capital of $3 million and additional paid in of $13,665 million. As of December 31, 2021 and 2020, we had 112,543 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2021 and 2020, we issued 77,883,713 and 42,777 shares of common stock, respectively, and released 301,239 and 72,028 shares of common stock held in trust, respectively, each having a par value of $0.01.

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 target relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2021, 694,148 shares were repurchased pursuant to the stock repurchase program. As of December 31, 2021, a total of 997,983 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. As of December 31, 2021, the total cost of all repurchases, including commissions, was $47 million.

On February 16, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2022 to shareholders of record at the close of business on March 1, 2022.

Note 3. Long-Term Debt

In 2017, AVANGRID issued $600 million aggregate principal amount of its 3.15% notes maturing in 2024.

On May 16, 2019, AVANGRID issued $750 million aggregate principal amount of its 3.80% notes maturing in 2029. Proceeds of the offering were used to finance and/or refinance, in whole or in part, one or more eligible renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $743 million.

On April 9, 2020, AVANGRID issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%. Net proceeds of the offering after the price discount and issuance-related expenses were $744 million.

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On December 14, 2020, AVANGRID and Iberdrola entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid in 2021 with the proceeds of the common share issuance described in Note 1.

Note 4. Cash Dividends Paid by Subsidiaries

Cash dividends paid by subsidiary are as follows:

Years ended December 31,	2021		2020		2019
(millions)
AVANGRID Networks	$	970	$	419	$	433
AVANGRID Renewables	$	152	$	—	$	—

For the years ended December 31, 2021, 2020 and 2019, AVANGRID made capital contributions to Networks of $1,011 million, $590 million and $158 million, respectively.

During 2021 and 2020, AVANGRID recorded a net non-cash contribution and dividend of $674 million and $423 million, respectively, to and from its subsidiaries to zero out their account balances of notes receivable and payable.

170

Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure.

None.

Item 9A. 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, or the Exchange Act), as of the end of the period covered by this Annual Report on Form 10-K. Based on such evaluation, our CEO and CFO have concluded that as of such date, our disclosure controls and procedures were effective to provide reasonable assurance that information required to be disclosed by the Company in reports that it files or submits under the Exchange Act is (i) recorded, processed, summarized and reported within the time periods specified in the SEC rules and forms and (ii) accumulated and communicated to the Company’s management, including its CEO and CFO, as appropriate to allow timely decisions regarding required disclosure.

Report of Management on Internal Control Over Financial Reporting

The management of AVANGRID is responsible for establishing and maintaining adequate internal control over financial reporting as defined in Rules 13a-15(f) and 15d-15(f) under the Exchange Act. AVANGRID’s internal control system over financial reporting is designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with U.S. generally accepted accounting principles. AVANGRID’s internal control over financial reporting includes those policies and procedures that:

1.pertain to the maintenance of records that, in reasonable detail, accurately and fairly reflect the transactions and dispositions of the assets of the company;

2.provide reasonable assurance that transactions are recorded as necessary to permit preparation of financial statements in accordance with U.S. generally accepted accounting principles, and that receipts and expenditures of the company are being made only in accordance with authorizations of management and directors of the company; and

3.provide reasonable assurance regarding prevention or timely detection of unauthorized acquisition, use or disposition of the company's assets that could have a material effect on the financial statements.

Because of inherent limitations, internal control over financial reporting may not prevent or detect misstatements. Therefore, even those systems determined to be effective can provide only reasonable assurance with respect to financial statement preparation and presentation. Also, projections of any evaluation of effectiveness to future periods are subject to risk that controls may become inadequate because of changes in condition, or that the degree of compliance with the policies or procedures may deteriorate.

AVANGRID's management assessed the effectiveness of AVANGRID's internal control over financial reporting as of December 31, 2021. In making this assessment, management used the criteria set forth by the Committee of Sponsoring Organizations of the Treadway Commission (2013 framework) ("COSO") in Internal Control-Integrated Framework. Based on this assessment, management determined that our internal control over financial reporting was effective as of December 31, 2021.

Our independent registered public accounting firm, KPMG LLP, has issued an audit report on the Company’s internal control over financial reporting, which appears in Part II, Item 8 of this Form 10-K.

Changes in Internal Control

There were no changes in our internal control over financial reporting identified in connection with the evaluation required by Rules 13a-15(d) and 15d-15(d) of the Exchange Act during the quarter ended December 31, 2021 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.

Item 9B. Other Information.

None.

Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.

Not applicable.

171

PART III 

Item 10. Directors, Executive Officers and Corporate Governance.

For information regarding our executive officers, see Part I of this Annual Report on Form 10-K. Additional information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Item 11. Executive Compensation.

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters.

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Item 13. Certain Relationships and Related Transactions, and Director Independence.

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

Item 14. Principal Accountant Fees and Services.

Our independent registered public accounting firm is KPMG LLP, New York, NY, Auditor Firm ID: 185

The information required by this item is incorporated by reference to our Proxy Statement for the 2022 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2021.

172

Part IV

Item 15. Exhibits and Financial Statement Schedules.

a) The following documents are made a part of this Annual Report on Form 10-K:

1. Financial Statements—Our consolidated financial statements are set forth under Part II, Item 8 “Financial Statements and Supplementary Data.”

2. Financial Statement Schedules— Our financial statement schedules are set forth under Part II, Item 8 “Financial Statements and Supplementary Data.”

3. Exhibits—The following instruments and documents are included as exhibits to this report.

Exhibit Number	Exhibit Description
2.1	Agreement and Plan of Merger, dated as of February 25, 2015, by and among Avangrid, Inc. (formerly Iberdrola USA, Inc.), Green Merger Sub, Inc. and UIL Holdings Corporation (incorporated herein by reference to Annex A to the proxy statement/prospectus included as Exhibit 2.1 in our Registration Statement on Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
2.2	Agreement and Plan of Merger, dated as of October 20, 2020, by and among PNM Resources, I Inc., Avangrid, Inc. and NM Green Holdings, Inc. (incorporated herein by reference to Exhibit 2.1 to Form 8-K file with the Securities and Exchange Commission on October 21, 2020).
3.1	Certificate of Incorporation of Avangrid, Inc. (incorporated herein by reference to Exhibit 3.2 to Form 8-K filed with the Securities and Exchange Commission on December 18, 2015).
3.2	Amended and Restated Bylaws of Avangrid, Inc. (incorporated herein by reference to Exhibit 3.1 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2017 filed with the Securities and Exchange Commission on August 1, 2017).
4.1	Specimen Common Stock Certificate (incorporated herein by reference to Exhibit 4.1 to Form S-4/A filed with the Securities and Exchange Commission on October 21, 2015).
4.2	Senior Indenture, dated as of October 7, 2010, between UIL Holdings Corporation and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.1 of UIL Holdings Corporation’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 7, 2010).
4.3	First Supplemental Indenture, dated as of October 7, 2010, between UIL Holdings Corporation and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.2 of UIL Holdings Corporation’s Current Report on Form 8-K filed with the Securities and Exchange Commission on October 7, 2010).
4.4	Second Supplemental Indenture, dated as of December 16, 2015, among UIL Holdings Corporation, Green Merger Sub, Inc. and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed with the Securities and Exchange Commission on December 18, 2015).
4.5	Third Supplemental Indenture, dated as of December 19, 2016, among Avangrid, Inc., UIL Holdings Corporation and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.5 of AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 filed with the Securities and Exchange Commission on March 10, 2017).
4.6	Indenture, dated as of November 21, 2017, between the Company and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed with the Securities and Exchange Commission on November 21, 2017).
4.7	First Supplemental Indenture, dated November 21, 2017, between the Company and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed with the Securities and Exchange Commission on November 21, 2017).

173

Exhibit Number	Exhibit Description
4.8	Form of Global Note Representing the Notes (incorporated herein by reference to Exhibit 4.3 to Form 8-K filed with the Securities and Exchange Commission on November 21, 2017).
4.9	Second Supplemental Indenture, dated as of May 16, 2019, among Avangrid, Inc. and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed with the Securities and Exchange Commission on May 16, 2019).
4.10	Third Supplemental Indenture, dated April 9, 2020, between the Company and The Bank of New York Mellon, as trustee (incorporated herein by reference to Exhibit 4.2 to Form 8-K filed with the Securities and Exchange Commission on April 9, 2020).
4.11	Form of Global Note Representing the Notes (included in Third Supplemental Indenture, dated April 9, 2020, between the Company and The Bank of New York Mellon, as trustee and incorporated herein by reference to Exhibit 4.2 of AVANGRID’s Current Report on Form 8-K filed with the SEC on April 9, 2020).
4.12	Description of Avangrid, Inc.'s Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (incorporated herein by reference to Exhibit 4.9 of AVANGRID's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed with the Securities and Exchange Commission on March 2, 2020).
4.13	Share Purchase Agreement, effective as of May 12, 2021, between Iberdrola, S.A. and Avangrid, Inc. (incorporated herein by reference to Exhibit 4.1 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 filed with the Securities and Exchange Commission on July 30, 2021).
4.14	Share Purchase Agreement, effective as of May 12, 2021, between Hyde Member LLC and Avangrid, Inc. (incorporated herein by reference to Exhibit 4.2 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2021 filed with the Securities and Exchange Commission on July 30, 2021).
10.1	Shareholder Agreement, dated as of December 16, 2015, by and between Avangrid, Inc. and Iberdrola, S.A. (incorporated herein by reference to Exhibit 4.1 to Form 8-K filed with the Securities and Exchange Commission on December 18, 2015).
10.2	Service Agreement, dated January 1, 2014, between Iberdrola USA, Inc. Management Corporation and Avangrid, Inc. (formerly Iberdrola USA, Inc.) (incorporated herein by reference to Exhibit 10.2 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.3	Accession Agreement, dated September 16, 2011, between Iberdrola Renewables Holdings, Inc. and Bank Mendes Gans N.V. (incorporated herein by reference to Exhibit 10.14 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.4	Employment Agreement dated October 1, 2010 among Robert Daniel Kump, Iberdrola USA Networks, Inc. (formerly Iberdrola USA, Inc.) and Iberdrola USA Management Corporation (incorporated herein by reference to Exhibit 10.23 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015). †
10.5	Service Contract dated January 16, 2014 between Robert Daniel Kump and Avangrid, Inc. (incorporated herein by reference to Exhibit 10.24 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015). †
10.6	Employment Agreement dated March 1, 2008 between R. Scott Mahoney and Iberdrola USA Management Corporation (formerly Energy East Management Corporation) (incorporated herein by reference to Exhibit 10.27 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015).†

174

Exhibit Number	Exhibit Description
10.7	Framework Agreement for the Provision of Corporate Services for Iberdrola and the Companies of its Group, and the Declaration of Acceptance, dated July 16, 2015 (incorporated herein by reference to Exhibit 10.28 to Form S-4 filed with the Securities and Exchange Commission on July 17, 2015).
10.8	Equipment Supply Agreement dated December 28, 2014 between Iberdrola Renewables, LLC and Gamesa Wind US, LLC (incorporated herein by reference to Exhibit 10.29 to Form S-4/A filed with the Securities and Exchange Commission on November 6, 2015).
10.9	Agreement and Release dated September 25, 2009 between Robert Daniel Kump and Iberdrola USA Management Corporation (formerly Energy East Management Corporation) (incorporated herein by reference to Exhibit 10.31 to Form S-4/A filed with the Securities and Exchange Commission on September 9, 2015). †
10.10	Form of Indemnification Agreement between Avangrid, Inc. (formerly Iberdrola USA, Inc.) and its directors and officers (incorporated herein by reference to Exhibit 10.32 to Form S-4/A filed with the Securities and Exchange Commission on October 21, 2015).†
10.11	Commercial Paper/Certificates of Deposit Issuing and Paying Agent Agreement dated May 13, 2016 among Avangrid, Inc., as Issuer, and Bank of America, National Association, as Issuing and paying Agent (incorporated herein by reference to Exhibit 10.1 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 filed with the Securities and Exchange Commission on August 4, 2016).
10.12	Form of Commercial Paper Dealer Agreement among Avangrid, Inc., as Issuer, and various Dealers (incorporated herein by reference to Exhibit 10.2 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2016 filed with the Securities and Exchange Commission on August 4, 2016).
10.13	Form of Performance Stock Unit Grant Agreement (incorporated herein by reference to Exhibit 10.1 to AVANGRID’s Current Report on Form 8-K filed with the SEC on July 19, 2016).†
10.14	Avangrid, Inc. Omnibus Incentive Plan (incorporated herein by reference to Form S-8 filed with the SEC on July 21, 2016).†
10.15	Uncommitted Line of Credit for Standby Letters of Credit Agreement, dated as of December 2, 2016, between Avangrid, Inc. and Crédit Agricole Corporate (incorporated herein by reference to Exhibit 10.44 of AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 filed with the Securities and Exchange Commission on March 10, 2017).
10.16	Substitution Agreement, dated as of December 19, 2016, between UIL Holdings Corporation and Avangrid, Inc. (incorporated herein by reference to Exhibit 10.45 of AVANGRID’s Annual Report on Form 10-K for the fiscal year ended December 31, 2016 filed with the Securities and Exchange Commission on March 10, 2017).
10.17	Amended and Restated Avangrid, Inc. Omnibus Incentive Plan (incorporated herein by reference to Exhibit 10.1 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2017 filed with the Securities and Exchange Commission on May 5, 2017).†
10.18	Customer Liquidity Agreement, dated December 1, 2017, between Avangrid, Inc., Bank of America, National Association, Iberdrola, S.A., Iberdrola Mexico, S.A. de C.V., and Scottish Power Ltd. (incorporated herein by reference to Exhibit 10.37 of AVANGRID's Annual Report on Form 10-K for the fiscal year ended December 31, 2017 filed with the Securities and Exchange Commission on March 26, 2018).
10.19	Underwriting Agreement, dated November 16, 2017, by and among the Avangrid, Inc., BBVA Securities Inc., BNP Paribas Securities Corp., Citigroup Global Markets Inc., and Wells Fargo Securities, LLC (incorporated herein by reference to Exhibit 1.1 to Form 8-K filed with the Securities and Exchange Commission on November 21, 2017).

175

Exhibit Number	Exhibit Description
10.20	Purchase Agreement, dated January 31, 2018, between Avangrid Renewables Holdings, Inc. and CCI U.S. Asset Holdings LLC (incorporated herein by reference to Exhibit 10.1 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2018 filed with the Securities and Exchange Commission on May 3, 2018).
10.21	Transmission Service Agreement, dated June 13, 2018, between Central Maine Power Company and NSTAR Electric Company (d/b/a Eversource) (incorporated herein by reference to Exhibit 10.2 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed with the Securities and Exchange Commission on August 2, 2018).
10.22	Transmission Service Agreement, dated June 13, 2018, among Central Maine Power Company, Massachusetts Electric Company (d/b/a National Grid), and Nantucket Electric Company (d/b/a National Grid) (incorporated herein by reference to Exhibit 10.3 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed with the Securities and Exchange Commission on August 2, 2018).
10.23	Transmission Service Agreement, dated June 13, 2018, between Central Maine Power Company and Fitchburg Gas & Electric Light Company (d/b/a Unitil) (incorporated herein by reference to Exhibit 10.4 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed with the Securities and Exchange Commission on August 2, 2018).
10.24	Transmission Service Agreement, dated June 13, 2018, between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.5 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed with the Securities and Exchange Commission on August 2, 2018).
10.25	Transmission Service Agreement, dated June 13, 2018, between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.6 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed with the Securities and Exchange Commission on August 2, 2018).
10.26	Transmission Service Agreement, dated June 13, 2018, between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.7 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed with the Securities and Exchange Commission on August 2, 2018).
10.27	Transmission Service Agreement, dated June 13, 2018, between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.8 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended June 30, 2018 filed with the Securities and Exchange Commission on August 2, 2018).
10.28	Employment Agreement, effective as of July 8, 2018, between Douglas K. Stuver and Avangrid Management Company, LLC (incorporated herein by reference to Exhibit 10.1 to AVANGRID’s Current Report on Form 8-K filed with the SEC on July 20, 2018).†
10.29	First Amendment to Transmission Service Agreement dated October 9, 2018 by and between Central Maine Power Company and NSTAR Electric Company (d/b/a Eversource) (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed with the SEC on October 15, 2018).
10.30	First Amendment to Transmission Service Agreement dated October 9, 2018 by and among Central Maine Power Company, Massachusetts Electric Company (d/b/a National Grid) and Nantucket Electric Company (d/b/a National Grid) (incorporated herein by reference to Exhibit 10.2 to Form 8-K filed with the SEC on October 15, 2018).
10.31	First Amendment to Transmission Service Agreement dated October 9, 2018 by and between Central Maine Power Company and Fitchburg Gas and Electric Light Company (d/b/a Unitil) (incorporated herein by reference to Exhibit 10.3 to Form 8-K filed with the SEC on October 15, 2018).
10.32	Amended and Restated Executive Variable Pay Plan (incorporated by reference to Exhibit 10.1 to AVANGRID's Current Report on Form 8-K filed with the SEC on February 20, 2019).†

176

Exhibit Number	Exhibit Description
10.33	Underwriting Agreement, dated May 14, 2019, by and among the Avangrid, Inc., Credit Agricole Securities (USA) Inc, MUFG Securities Americas Inc., Citigroup Global Markets Inc., and Wells Fargo Securities, LLC (incorporated herein by reference to Exhibit 1.1 to Form 8-K filed with the Securities and Exchange Commission on May 16, 2019).
10.34	Term Loan Credit Agreement, dated December 31, 2019, among Avangrid, Inc., The Several Lenders, Mizuho Bank, LTD and The Bank of Nova Scotia (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed with the Securities and Exchange Commission on January 7, 2020).
10.35	Employment Agreement, dated March 30, 2004 between Anthony Marone III and The United Illuminating Company (incorporated herein by reference to Exhibit 10.51 of AVANGRID's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed with the Securities and Exchange Commission on March 2, 2020).†
10.36	First Amendment to Employment Agreement, dated as of November 18, 2004, between Anthony Marone III and The United Illuminating Company (incorporated herein by reference to Exhibit 10.52 of AVANGRID's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed with the Securities and Exchange Commission on March 2, 2020).†
10.37	Second Amendment to Employment Agreement, dated as of August 4, 2008, between Anthony Marone III and The United Illuminating Company (incorporated herein by reference to Exhibit 10.53 of AVANGRID's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed with the Securities and Exchange Commission on March 2, 2020).†
10.38	Letter Agreement, dated September 20, 2016, between Anthony Marone III and Avangrid, Inc (incorporated herein by reference to Exhibit 10.54 of AVANGRID's Annual Report on Form 10-K for the fiscal year ended December 31, 2019 filed with the Securities and Exchange Commission on March 2, 2020).†
10.39	Second Amended and Restated Employment Agreement, dated as of May 4, 2020, between Anthony Marone III and Avangrid, Inc. (incorporated herein by reference to Exhibit 10.49 of AVANGRID's Annual Report on Form 10-K for the fiscal year ended December 31, 2020 filed with the Securities and Exchange Commission on March 2, 2021).†
10.40	Underwriting Agreement, dated April 7, 2020, by and among Avangrid, Inc. and BBVA Securities Inc., BNP Paribas Securities Corp., BofA Securities, Inc. and MUFG Securities Americas Inc., as representatives of the several Underwriters named therein (incorporated herein by reference to Exhibit 1.1 to Form 8-K filed with the Securities and Exchange Commission on April 9, 2020).
10.41	Employment Agreement, dated June 11, 2020, by and between Avangrid Management Company, LLC and Dennis V. Arriola (incorporated herein by reference to Exhibit 10.1 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).†
10.42	Revolving Credit Agreement, dated June 29, 2020, among Avangrid, Inc., the several lenders from time to time parties thereto, Mizuho Bank, Ltd., as administrative agent, and The Bank of Nova Scotia and Banco Bilbao Vizcaya Argentaria, S.A. New York Branch, as co-syndication agents (incorporated herein by reference to Exhibit 10.2 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.43	Amendment No. 2 to the Revolving Credit Agreement, dated June 29, 2020, among Avangrid, Inc., New York State Electric & Gas Corporation, Rochester Gas and Electric Corporation, Central Maine Power Company, The United Illuminating Company, Connecticut Natural Gas Corporation, The Southern Connecticut Gas Company, The Berkshire Gas Company, the several banks and other financial institutions or entities from time to time parties thereto, JPMorgan Chase Bank, N.A., as administrative agent, and Bank of America, N.A., as syndication agent, MUFG Bank, Ltd. and Santander Bank, N.A., as co-documentation agents, and Banco Bilbao Vizcaya Argentaria, S.A. New York Branch, as sustainability agent (incorporated herein by reference to Exhibit 10.3 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020),

177

Exhibit Number	Exhibit Description
10.44	Second Amendment to Transmission Service Agreement and Consent to Assignment dated June 25, 2020 by and between Central Maine Power Company and NSTAR Electric Company (d/b/a Eversource) (incorporated herein by reference to Exhibit 10.4 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.45	Second Amendment to Transmission Service Agreement and Consent to Assignment dated June 25, 2020 by and among Central Maine Power Company, Massachusetts Electric Company (d/b/a National Grid), and Nantucket Electric Company (d/b/a National Grid) incorporated herein by reference to Exhibit 10.5 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.46	Second Amendment to Transmission Service Agreement and Consent to Assignment dated June 25, 2020 by and between Central Maine Power Company and Fitchburg Gas and Electric Light Company (d/b/a Unitil) (incorporated herein by reference to Exhibit 10.6 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.47	Second Amendment to Transmission Service Agreement and Consent to Assignment dated June 25, 2020 by and between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.7 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.48	Second Amendment to Transmission Service Agreement and Consent to Assignment dated June 25, 2020 by and between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.8 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.49	Second Amendment to Transmission Service Agreement and Consent to Assignment dated June 25, 2020 by and between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.9 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.50	Second Amendment to Transmission Service Agreement and Consent to Assignment dated June 25, 2020 by and between Central Maine Power Company and H.Q. Energy Services (U.S.) Inc. (incorporated herein by reference to Exhibit 10.10 of AVANGRID's Quarterly Report on Form 10-Q for the quarter ended June 30, 2020 filed with the Securities and Exchange Commission on July 31, 2020).
10.51	Intra-Group Loan Agreement, dated December 14, 2020, between Avangrid, Inc. and Iberdrola, S.A. (incorporated herein by reference to Exhibit 10.1 to Form 8-K filed with the Securities and Exchange Commission on December 18, 2020).
10.52	Side Letter Agreement, dated April 15, 2021, between Avangrid, Inc. and Iberdrola, S.A. (incorporated herein by reference to Exhibit 10.1 to AVANGRID’s Current Report on Form 8-K filed with the Securities and Exchange Commission on April 16, 2021).
10.53	Separation Agreement, effective as of February 2, 2021, between Anthony Marone III and Avangrid, Inc. (incorporated herein by reference to Exhibit 10.1 of AVANGRID’s Quarterly Report on Form 10-Q for the quarter ended March 31, 2021 filed with the Securities and Exchange Commission on May 4, 2021).†
10.54	Employment Agreement, dated June 13, 2021, between Avangrid Management Company, LLC. and R Scott Mahoney (incorporated herein by reference to Exhibit 10.1 to AVANGRID’s Current Report on Form 8-K filed with the Securities and Exchange Commission on July 16, 2021).†
10.55	Restructuring Agreement, dated September 15, 2021, among CI-II Park Holding LLC, CI III Park Holding LLC, CI IV Master DEVCO LLC, Avangrid Renewables, LLC and Vineyard Wind LLC. (incorporated herein by reference to Exhibit 10.1 to AVANGRID’s Current Report on Form 8-K filed with the Securities and Exchange Commission on September 21, 2021).

178

Exhibit Number	Exhibit Description
10.56	Revolving Credit Agreement, dated as of November 23, 2021 among Avangrid, Inc., New York State Electric & Gas Corporation, Rochester Gas and Electric Corporation, Central Maine Power Company, The United Illuminating Company, Connecticut Natural Gas Corporation, The Southern Connecticut Gas Company, The Berkshire Gas Company, the several lenders from time to time parties thereto, Mizuho Bank, Ltd., as Administrative Agent, MUFG Bank, LTD., Banco Bilbao Vizcaya Argentaria, S.A. New York Branch and Santander Bank, N.A., as Co-Documentation Agents, Bank of America, N.A. and JPMorgan Chase Bank, N.A., as Co-Syndication Agents, Banco Bilbao Vizcaya Argentaria, S.A. New York Branch, as Sustainability Agent, and Mizuho Bank, Ltd., BOFA Securities, Inc., JPMorgan Chase Bank, N.A., MUFG Bank, LTD., BBVA Securities Inc., and Santander Bank, N.A., as Joint Lead Arrangers and Joint Bookrunners (incorporated herein by reference to Exhibit 10.1 to AVANGRID’s Current Report on Form 8-K filed with the Securities and Exchange Commission on November 24, 2021).
21.1	Significant subsidiaries of the Registrant.*
23.1	Consent of KPMG LLP, independent registered public accounting firm of Avangrid, Inc.*
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	Chief Executive Officer and Chief Financial Officer Certification Pursuant to 18 United States Code Section 1350, As Adopted Pursuant to Section 906 of the Sarbanes-Oxley Act of 2002.*
101.INS	Inline XBRL Instance Document - the instance document does not appear in the Interactive Data File because its XBRL tags are embedded within the Inline XBRL document.
101.SCH	Inline XBRL Taxonomy Extension Schema Document.*
101.CAL	Inline XBRL Taxonomy Extension Calculation Linkbase Document.*
101.DEF	Inline XBRL Taxonomy Extension Definition Linkbase Document.*
101.LAB	Inline XBRL Taxonomy Extension Label Linkbase Document.*
101.PRE	Inline XBRL Taxonomy Extension Presentation Linkbase Document.*
104	The cover page from the Company's Annual Report on Form 10-K for the year ended December 31, 2021, formatted as Inline XBRL and contained in Exhibit 101.

* Filed herewith.

† Compensatory plan or agreement.

The foregoing list of exhibits does not include instruments defining the rights of the holders of certain long-term debt of Avangrid, Inc. and its subsidiaries where the total amount of securities authorized to be issued under the instrument does not exceed ten percent (10%) of the total assets of Avangrid, Inc. and its subsidiaries on a consolidated basis; and Avangrid, Inc. hereby agrees to furnish a copy of each such instrument to the SEC on request.

Item 16. Form 10-K Summary.

None.

179

SIGNATURES

Pursuant to the requirements of Section 13 or 15(d) 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:	February 23, 2022	By:	/s/ Dennis V. Arriola
			Dennis V. Arriola
			Director and Chief Executive Officer

Pursuant to the requirements of the Securities Exchange Act of 1934, this report has been signed below by the following persons on behalf of the registrant and in the capacities and on the dates indicated.

Signature	Title	Date
/s/ Dennis V. Arriola	Director and Chief Executive Officer (Principal Executive Officer)	February 23, 2022
Dennis V. Arriola
/s/ Douglas K. Stuver	Chief Financial Officer (Principal Financial Officer)	February 23, 2022
Douglas K. Stuver
/s/ Scott M. Tremble	Controller (Principal Accounting Officer)	February 23, 2022
Scott M. Tremble
/s/ Ignacio S. Galán	Chairman of the Board	February 23, 2022
Ignacio S. Galán
/s/ John E. Baldacci	Director	February 23, 2022
John E. Baldacci
/s/ Daniel Alcain López	Director	February 23, 2022
Daniel Alcain López
/s/ Pedro Azagra Blázquez	Director	February 23, 2022
Pedro Azagra Blázquez
/s/ Robert Duffy	Director	February 23, 2022
Robert Duffy
/s/ Teresa Herbert	Director	February 23, 2022
Teresa Herbert
/s/ Patricia Jacobs	Director	February 23, 2022
Patricia Jacobs
/s/ John L. Lahey	Director	February 23, 2022
John L. Lahey
/s/ José Ángel Marra Rodríquez	Director	February 23, 2022
José Ángel Marra Rodríquez
/s/ Santiago Martinez Garrido	Director	February 23, 2022
Santiago Martinez Garrido
/s/ José Sáinz Armada	Director	February 23, 2022
José Sáinz Armada
/s/ Alan D. Solomont	Director	February 23, 2022
Alan D. Solomont
/s/ Elizabeth Timm	Director	February 23, 2022
Elizabeth Timm

180

EX-21.1

EXHIBIT 21.1

LIST OF SUBSIDIARIES OF Avangrid, Inc.

Name of Subsidiary	State or Jurisdiction of Incorporation Or Organization
Avangrid Networks, Inc.(1)*	Maine
New York State Electric & Gas Corporation(2)	New York
Rochester Gas and Electric Corporation(2)	New York
Central Maine Power Company(2)	Maine
Maine Natural Gas Corporation(2)	Maine
UIL Holdings Corporation(2)	Connecticut
The United Illuminating Company(4)	Connecticut
The Southern Connecticut Gas Company(4)	Connecticut
Connecticut Natural Gas Corporation(4)	Connecticut
The Berkshire Gas Company(4)	Massachusetts
Avangrid Renewables Holdings, Inc.(1)*	Delaware
Avangrid Renewables, LLC(3)	Oregon

(1)Subsidiary of Avangrid, Inc.

(2)Subsidiary of Avangrid Networks, Inc.

(3)Subsidiary of Avangrid Renewables Holdings, Inc.

(4)Subsidiary of UIL Holdings Corporation

* Holding Company

EX-23.1

EXHIBIT 23.1

Consent of Independent Registered Public Accounting Firm

We consent to the incorporation by reference in the registration statement (No. 333‑231251) on Form S-3 and registration statements (No. 333-212616 and No. 333-208571) on Form S-8 of Avangrid, Inc. of our reports dated February 23, 2022, with respect to the consolidated financial statements (and financial statement schedule I) of Avangrid, Inc. and the effectiveness of internal control over financial reporting.

/s/ KPMG LLP

New York, New York

February 23, 2022

EX-31.1

EXHIBIT 31.1

CERTIFICATION

I, Dennis V. Arriola, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 23, 2022	/s/ Dennis V. Arriola
	Dennis V. Arriola
	Director and Chief Executive Officer

EX-31.2

EXHIBIT 31.2

CERTIFICATION

I, Douglas K. Stuver, certify that:

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

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

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

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

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

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

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

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

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

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

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

Date: February 23, 2022	/s/ Douglas K. Stuver
	Douglas K. Stuver Chief Financial Officer

EX-32

EXHIBIT 32

CERTIFICATION OF CHIEF EXECUTIVE OFFICER AND CHIEF FINANCIAL OFFICER

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

Pursuant to 18 U.S.C. 1350, the undersigned, Dennis V. Arriola and Douglas K. Stuver, the Chief Executive Officer and Chief Financial Officer, respectively, of Avangrid, Inc. (the “issuer”), do each hereby certify that the report on Form 10‑K to which this certification is attached as an exhibit (the “report”) fully complies with the requirements of section 13(a) or 15(d) of the Securities Exchange Act of 1934 (15 U.S.C. 78m or 78o(d)) and that information contained in the report fairly presents, in all material respects, the financial condition and results of operations of the issuer.

/s/ Dennis V. Arriola

Dennis V. Arriola

Director and Chief Executive Officer

Avangrid, Inc.

February 23, 2022

/s/ Douglas K. Stuver

Douglas K. Stuver

Chief Financial Officer

Avangrid, Inc.

February 23, 2022

XML

Cover Page - USD ($)
$ in Millions

12 Months Ended

Dec. 31, 2021

Feb. 22, 2022

Jun. 30, 2021

Cover [Abstract]

Document Type

10-K

Document Annual Report

true

Document Period End Date

Dec. 31, 2021

Current Fiscal Year End Date

--12-31

Document Transition Report

false

Entity File Number

001-37660

Entity Registrant Name

Avangrid, Inc.

Entity Incorporation, State or Country Code

NY

Entity Tax Identification Number

14-1798693

Entity Address, Address Line One

180 Marsh Hill Road

Entity Address, City or Town

Orange,

Entity Address, State or Province

CT

Entity Address, Postal Zip Code

06477

City Area Code

207

Local Phone Number

629-1190

Title of 12(b) Security

Common Stock, par value $0.01 per share

Trading Symbol

AGR

Security Exchange Name

NYSE

Entity Well-known Seasoned Issuer

Yes

Entity Voluntary Filers

No

Entity Current Reporting Status

Yes

Entity Interactive Data Current

Yes

Entity Filer Category

Large Accelerated Filer

Entity Small Business

false

Entity Emerging Growth Company

false

ICFR Auditor Attestation Flag

true

Entity Shell Company

false

Entity Public Float

$ 3,684

Entity Common Stock, Shares Outstanding

386,577,494

Documents Incorporated by Reference

Portions of the documents listed below have been incorporated by reference into the indicated parts of this report, as specified in the responses to the item numbers involved.

Designated portions of the Proxy Statement relating to the 2022 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.

Amendment Flag

false

Document Fiscal Year Focus

2021

Document Fiscal Period Focus

FY

Entity Central Index Key

0001634997

XML

Audit Information	12 Months Ended
	Dec. 31, 2021
Audit Information [Abstract]
Auditor Name	KPMG LLP
Auditor Location	New York, NY
Auditor Firm ID	185

XML

Consolidated Statements of Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Statement [Abstract]
Operating Revenues	$ 6,974	$ 6,320	$ 6,336
Operating Expenses
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Operations and maintenance	2,706	2,466	2,305
Depreciation and amortization	1,014	987	933
Taxes other than income taxes, net	640	619	591
Total Operating Expenses	6,079	5,451	5,338
Operating Income	895	869	998
Other Income and (Expense)
Other income (expense)	60	18	121
(Losses) earnings from equity method investments	7	(3)	3
Interest expense, net of capitalization	(298)	(316)	(310)
Income Before Income Tax	664	568	812
Income tax expense	21	29	169
Net Income	643	539	643
Net loss attributable to noncontrolling interests	64	42	24
Net Income Attributable to Avangrid, Inc.	$ 707	$ 581	$ 667
Earnings Per Common Share, Basic (in dollars per share)	$ 1.97	$ 1.88	$ 2.16
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.97	$ 1.88	$ 2.16
Weighted-average Number of Common Shares Outstanding:
Basic (in shares)	358,086,621	309,494,939	309,491,082
Diluted (in shares)	358,578,608	309,559,387	309,514,910

XML

Consolidated Statements of Comprehensive Income - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Net Income	$ 643	$ 539	$ 643
Other Comprehensive Income
Gain on defined benefit plans, net of income taxes of $0, $0 and $0, respectively	2	0	1
Amortization of pension cost for nonqualified plans, net of income taxes of $(1), $3 and $(1), respectively	(8)	(13)	(1)
Unrealized loss from equity method investment, net of income taxes of $(3), $0 and $0, respectively	(9)	0	0
Unrealized loss during the year on derivatives qualifying as cash flow hedges, net of income taxes of $(44), $(7) and $(9), respectively	(159)	(22)	(22)
Reclassification to net income of losses (gains) on cash flow hedges, net of income taxes of $(3), $2 and $3, respectively	12	19	11
Other Comprehensive Loss	(162)	(16)	(11)
Comprehensive Income	481	523	632
Net loss attributable to noncontrolling interests	64	42	24
Comprehensive Income Attributable to Avangrid, Inc.	$ 545	$ 565	$ 656

XML

Consolidated Statements of Comprehensive Income (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Comprehensive Income [Abstract]
Gain on defined benefit plans, net of income taxes	$ 0	$ 0	$ 0
Amortization of pension cost for nonqualified plans, taxes	1	3	1
Unrealized loss from equity method investment, taxes	(3)	0	0
Unrealized loss during the year on derivatives qualifying as cash flow hedges, taxes	(44)	(7)	(9)
Reclassification to net income of losses on cash flow hedges, taxes	$ (3)	$ 2	$ 3

XML

Consolidated Balance Sheets - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Current Assets
Cash and cash equivalents	$ 1,474	$ 1,463
Accounts receivable and unbilled revenues, net	1,269	1,187
Accounts receivable from affiliates	11	12
Derivative assets	35	18
Fuel and gas in storage	139	93
Materials and supplies	204	169
Prepayments and other current assets	245	525
Regulatory assets	400	310
Total Current Assets	3,777	3,777
Total Property, Plant and Equipment ($1,959 and $1,637 related to VIEs, respectively)	28,866	26,751
Operating lease right-of-use assets	148	153
Equity method investments	560	668
Other investments	61	68
Regulatory assets	2,247	2,572
Other Assets
Goodwill	3,119	3,119
Intangible assets	293	305
Derivative assets	59	79
Other	374	331
Total Other Assets	3,845	3,834
Total Assets	39,504	37,823
Current Liabilities
Current portion of debt	372	313
Notes payable	159	307
Notes payable to affiliate	2	0
Interest accrued	69	70
Accounts payable and accrued liabilities	1,586	1,453
Accounts payable to affiliates	61	50
Dividends payable	170	136
Taxes accrued	43	73
Operating lease liabilities	12	8
Derivative liabilities	64	17
Other current liabilities	484	368
Regulatory liabilities	307	274
Total Current Liabilities	3,329	3,069
Regulatory liabilities	3,022	3,137
Other Non-current Liabilities
Deferred income taxes	2,016	1,919
Deferred income	1,130	1,204
Pension and other postretirement	684	1,007
Operating lease liabilities	149	154
Derivative liabilities	160	79
Asset retirement obligations	253	210
Environmental remediation costs	298	292
Other	580	448
Total Other Non-current Liabilities	5,270	5,313
Non-current debt	7,922	7,478
Non-current debt to affiliate	0	3,000
Total Non-current Liabilities	16,214	18,928
Total Liabilities	19,543	21,997
Commitments and Contingencies	0	0
Stockholders' Equity:
Common stock, $.01 par value, 500,000,000 shares authorized, 387,678,630 and 309,794,917 shares issued; 386,568,104 and 309,077,300 shares outstanding, respectively	3	3
Additional paid-in capital	17,679	13,665
Treasury stock	(47)	(14)
Retained earnings	1,714	1,666
Accumulated other comprehensive loss	(273)	(111)
Total Stockholders’ Equity	19,076	15,209
Noncontrolling interests	885	617
Total Equity	19,961	15,826
Total Liabilities and Equity	$ 39,504	$ 37,823

XML

Consolidated Balance Sheets (Parenthetical) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, plant and equipment	$ 28,866	$ 26,751
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01
Common stock, authorized (in shares)	500,000,000	500,000,000
Common stock issued (in shares)	387,678,630	309,794,917
Common stock, outstanding (in shares)	386,568,104	309,077,300
Variable Interest Entity, Primary Beneficiary
Property, plant and equipment	$ 1,959	$ 1,637

XML

Consolidated Statements of Cash Flows - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Flow from Operating Activities
Net income	$ 643	$ 539	$ 643
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization	1,014	987	933
Accretion expenses	12	11	12
Regulatory assets/liabilities amortization and carrying cost	(72)	(13)	64
Pension cost	52	82	91
Earnings from equity method investments	(7)	3	(3)
Distribution of earnings from equity method investments	17	19	12
Unrealized losses (gains) on marked to market derivative contracts	86	5	(76)
Gain from divestment and disposal of property	24	(10)	(135)
Deferred taxes	11	17	164
Other non-cash items	(82)	(83)	(51)
Changes in operating assets and liabilities:
Current assets	(275)	(173)	126
Noncurrent assets	(45)	(170)	(152)
Current liabilities	286	160	(2)
Noncurrent liabilities	(103)	(86)	(38)
Net Cash Provided by Operating Activities	1,561	1,288	1,588
Cash Flow from Investing Activities
Capital expenditures	(2,976)	(2,781)	(2,735)
Contributions in aid of construction	130	48	74
Proceeds from sale of equity method and other investment	0	238	108
Proceeds from sale of property, plant and equipment	24	7	18
Payments to affiliates	5	(3)	(2)
Cash distribution from equity method investments	155	3	5
Other investments and equity method investments, net	222	(370)	(176)
Net Cash Used in Investing Activities	(2,440)	(2,858)	(2,708)
Cash Flow from Financing Activities
Non-current debt issuances	833	1,367	2,137
Non-current debt issuance with affiliate	0	3,000	0
Repayments of non-current debt	(304)	(1,011)	(346)
Repayment of non-current debt with affiliate	(3,000)	0	0
Repayments of other short-term debt, net	(306)	(253)	(28)
Repayments of financing leases	(6)	(9)	(27)
Repurchase of common stock	(33)	(2)	0
Issuance of common stock	3,998	(1)	0
Distributions to noncontrolling interests	(10)	(5)	(63)
Contributions from noncontrolling interests	330	312	133
Dividends paid	(613)	(545)	(545)
Net Cash Provided by Financing Activities	889	2,853	1,261
Net Increase in Cash, Cash Equivalents and Restricted Cash	10	1,283	141
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,467	184	43
Cash, Cash Equivalents and Restricted Cash, End of Year	1,477	1,467	184
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	279	278	270
Cash paid for income taxes	$ 2	$ 8	$ 2

XML

Consolidated Statements of Changes in Equity - USD ($) $ in Millions		Total	Cumulative Effect, Period of Adoption, Adjustment	Total Stockholders' Equity	Total Stockholders' Equity Cumulative Effect, Period of Adoption, Adjustment	Common Stock		Additional paid-in capital	Treasury Stock	Retained Earnings	Retained Earnings Cumulative Effect, Period of Adoption, Adjustment	Accumulated Other Comprehensive Income (Loss)	Accumulated Other Comprehensive Income (Loss) Cumulative Effect, Period of Adoption, Adjustment	Non-controlling Interests
Balance at beginning of period (in shares) at Dec. 31, 2018	[1]					309,005,272
Balance at beginning of period at Dec. 31, 2018		$ 15,389	$ (1)	$ 15,090	$ (1)	$ 3		$ 13,657	$ (12)	$ 1,514	$ 11	$ (72)	$ (12)	$ 299
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		643		667						667				(24)
Other comprehensive income, net of tax		(11)		(11)								(11)
Comprehensive Income		632
Dividends declared		(545)		(545)						(545)
Stock-based compensation		3		3				3
Distributions to noncontrolling interests		(63)		(4)						(4)				(59)
Contributions from noncontrolling interests		124		(9)						(9)				133
Balance at end of period (in shares) at Dec. 31, 2019	[1]					309,005,272
Balance at end of period at Dec. 31, 2019		15,539	$ (1)	15,190	$ (1)	$ 3		13,660	(12)	1,634	$ (1)	(95)		349
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		539		581						581				(42)
Other comprehensive income, net of tax		(16)		(16)								(16)
Comprehensive Income		523
Dividends declared		$ (545)		(545)						(545)
Release of common stock held in trust (in shares)		72,028				72,028	[1]
Issuance of common stock (in shares)	[1]					42,777
Issuance of common stock		$ (1)		(1)				(1)
Repurchase of common stock (in shares)	[1]					(42,777)
Repurchase of common stock		(2)		(2)					(2)
Stock-based compensation		6		6				6
Distributions to noncontrolling interests		(5)												(5)
Contributions from noncontrolling interests		$ 312		(3)						(3)				315
Balance at end of period (in shares) at Dec. 31, 2020		309,077,300				309,077,300	[1]
Balance at end of period at Dec. 31, 2020		$ 15,826		15,209		$ 3		13,665	(14)	1,666		(111)		617
Increase (Decrease) in Stockholders' Equity [Roll Forward]
Net income		643		707						707				(64)
Other comprehensive income, net of tax		(162)		(162)								(162)
Comprehensive Income		481
Dividends declared		$ (647)		(647)						(647)
Release of common stock held in trust (in shares)		301,239				301,239	[1]
Issuance of common stock (in shares)	[1]					77,883,713
Issuance of common stock		$ 3,998		3,998				3,998
Repurchase of common stock (in shares)	[1]					(694,148)
Repurchase of common stock		(33)		(33)					(33)
Stock-based compensation		16		16				16
Distributions to noncontrolling interests		(10)												(10)
Contributions from noncontrolling interests		$ 330		(12)						(12)				342
Balance at end of period (in shares) at Dec. 31, 2021		386,568,104				386,568,104	[1]
Balance at end of period at Dec. 31, 2021		$ 19,961		$ 19,076		$ 3		$ 17,679	$ (47)	$ 1,714		$ (273)		$ 885

[1] Par value of share amounts is $.01

XML

Consolidated Statements of Changes in Equity (Parenthetical) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Statement of Stockholders' Equity [Abstract]
Other comprehensive income, tax	$ (51)	$ (2)	$ (7)
Dividends declared (in dollars per share)	$ 1.76	$ 1.76	$ 1.76
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01

XML

Background and Nature of Operations

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Background and Nature of Operations

Background and Nature of Operations

Avangrid, Inc. (AVANGRID, we or the Company) is an energy services holding company engaged in the regulated energy transmission and distribution business through its principal subsidiary Avangrid Networks, Inc. (Networks), and in the renewable energy generation business through its principal subsidiary, Avangrid Renewables Holding, Inc. (ARHI). ARHI in turn holds subsidiaries including Avangrid Renewables, LLC (Renewables). Iberdrola, S.A. (Iberdrola), a corporation organized under the laws of the Kingdom of Spain, owns 81.6% of the outstanding common stock of AVANGRID. The remaining outstanding shares are owned by various shareholders with approximately 14.8% of AVANGRID's outstanding shares publicly-traded on the New York Stock Exchange (NYSE).

Proposed Merger with PNMR

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

Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, Avangrid, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals.

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

The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before April 20, 2023, as amended (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii) AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee).

In connection with the Merger, Iberdrola has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration.

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

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

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Basis of Presentation	12 Months Ended
	Dec. 31, 2021
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Basis of Presentation	Basis of PresentationThe accompanying consolidated financial statements have been prepared in accordance with U.S. GAAP and are presented on a consolidated basis, and therefore include the accounts of AVANGRID and its consolidated subsidiaries, Networks and ARHI. All intercompany transactions and accounts have been eliminated in consolidation in all periods presented.

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Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates

Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates

Significant Accounting Policies

We consider the following policies to be the most significant in understanding the judgments that are involved in preparing our consolidated financial statements:

(a) Principles of consolidation

We consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting.

(b) Revenue recognition

We recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services. Refer to Note 4 for further details.

(c) Regulatory accounting

We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs.

We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.

(d) Business combinations and assets acquisitions (disposals)

We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred.

In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed.

(e) Noncontrolling interests

Noncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement.

Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets.

(f) Equity method investments

We account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary.

(g) Goodwill and other intangible assets

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

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

Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite.

Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in our consolidated statements of income within the expense category that is consistent with the function of the intangible assets.

(h) Property, plant and equipment

We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset.

Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment.

We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service.

We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation.

We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives:

Major class	Asset Category	Estimated Useful Life (years)
Plant	Combined cycle plants	35-75
	Hydroelectric power stations	45-90
	Wind power stations	25-40
	Solar power stations	25
	Transmission and transport facilities	41-80
	Distribution facilities	4-80
Equipment	Conventional meters and measuring devices	7-85
	Computer software	3-37
Other	Buildings	30-82
	Operations offices	3-75

Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated

depreciation. Networks' composite rate of depreciation were 2.8% and 2.9% of average depreciable property for 2021 and 2020, respectively.

We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs.

Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income.

(i) Leases

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

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

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

(j) Impairment of long-lived assets

We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset.

The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset.

(k) Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability.

The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use.

We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date.

The three input levels of the fair value hierarchy are as follows:

•Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract.

•Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data.

Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair value.

(l) Equity investments with readily determinable fair values

We measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.

(m) Derivatives and hedge accounting

Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met.

Certain derivatives hedge specific cash flows that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. Certain interest rate derivatives hedge a liability (i.e. debt) that qualify and are designated for hedge accounting are classified as fair value hedges. Changes in the fair value of interest rate derivatives designated as a fair value hedge and the offsetting changes in the fair value of the underlying hedged exposure (i.e. debt) are recorded in Interest expense. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI.

Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities.

We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.

(n) Cash and cash equivalents

Cash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued

liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows.

(o) Trade receivable and unbilled revenue, net of allowance for credit losses

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

Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. Due to COVID-19, the UIL companies’ regulators require them to offer to customers, through early February 2022, a 24-month repayment plan.

We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. We consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts.

(p) Variable interest entities

An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20).

We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors.

(q) Debentures, bonds and bank borrowings

We record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets.

(r) Inventory

Inventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.”

We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.”

In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.”

(s) Government grants

Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting.

In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses.

(t) Deferred income

Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.

(u) Asset retirement obligations

We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability.

The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred.

Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations.

(v) Environmental remediation liability

In recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis.

(w) Post-employment and other employee benefits

We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees.

We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management.

We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking

process. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss. We use a December 31st measurement date for our benefits plans.

We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period.

(x) Income taxes

We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs.

Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets.

We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements.

Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” in our consolidated statements of income.

Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income.

Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities.

Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.

(y) Stock-based compensation

Stock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier. 

Adoption of New Accounting Pronouncements

(a) Simplifying the accounting for income taxes

In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes, eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. We adopted the amendments effective January 1, 2021, with no material effect to our consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement.

(b) Improvements to lessor accounting for certain leases with variable lease payments

In July 2021, the FASB issued amendments to make targeted improvements to ASC 842 for lessor’s accounting for certain leases with variable lease payments, which affect lease classification. The amendments require a lessor to classify and account for a lease with variable lease payments as an operating lease if (a) the lease would have been classified as a sales-type lease or a direct financing lease and (b) the lessor would have otherwise recognized a day-one loss. The amendments are effective for fiscal years beginning after December 15, 2021, for all entities, and interim periods within those fiscal years for public business entities, with early application permitted. We have elected to early apply the amendments effective October 1, 2021, and apply the amendments prospectively to leases that commence or are modified on or after that date. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows.

(c) Accounting for revenue contracts with customers acquired in a business combination

In October 2021, the FASB issued amendments related to the accounting for revenue contracts acquired in a business combination. The amendments require an entity (acquirer) to recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with ASC 606, Revenue from Contracts with Customers. At the acquisition date, an acquirer should account for the related revenue contract in accordance with ASC 606 as if it had originated the contracts. Generally, this should result in an acquirer recognizing and measuring the acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s financial statements. The amendments also provide certain practical expedients for acquirers when recognizing and measuring acquired contract assets and contract liabilities from revenue contracts in a business combination. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively to business combinations occurring on or after the effective date of the amendments. Early adoption is permitted. We have elected to early apply the amendments effective October 1, 2021. Our adoption did not materially affect our consolidated results of operations, financial position and cash flows.

Accounting Pronouncements Issued But Not Yet Adopted

The following are new accounting pronouncements not yet adopted that we have evaluated or are evaluating to determine their effect on our consolidated financial statements.

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

In March 2020, the FASB issued amendments and created ASC 848 to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension.

In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate

reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments were effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.

Our prospective adoption of ASC 848 on January 1, 2022 will not materially affect our consolidated results of operations, financial position and cash flows.

(b) Disclosures by business entities about government assistance

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

Use of Estimates and Assumptions

The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for credit losses and unbilled revenues; (2) asset impairments, including goodwill; (3) investments in equity instruments; (4) depreciable lives of assets; (5) income tax valuation allowances; (6) uncertain tax positions; (7) reserves for professional, workers’ compensation and comprehensive general insurance liability risks; (8) contingency and litigation reserves; (9) fair value measurements; (10) earnings sharing mechanisms; (11) environmental remediation liabilities; (12) AROs; (13) pension and other postretirement employee benefits and (14) noncontrolling interest balances. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates we use in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates.

We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from COVID-19 has made such estimates and assumptions more difficult to assess and calculate. Affected estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While we have not yet had material effects of COVID-19 on our financial results, actual results could differ from those estimates, which could result in material effects to our consolidated financial statements in future reporting periods.

Union collective bargaining agreements

We have approximately 47.7% of our employees covered by a collective bargaining agreement. Agreements expiring in the coming year apply to approximately 18.8% of our employees.

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Revenue

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Revenue

Revenue

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

The following describes the principal activities, by reportable segment, from which we generate revenue. For more detailed information about our reportable segments, refer to Note 24.

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 including intersegment eliminations.

Contract Costs, Contract Liabilities and Practical Expedient

We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2022 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2021 and 2020, and are presented in "Other non-current assets" on our 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 $9 million at December 31, 2021 and 2020, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $22 million for the year ended December 31, 2021, and $21 million for both of the years ended December 31, 2020 and 2019 as revenue related to contract liabilities.

We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2021, 2020 and 2019 are as follows:

	Year Ended December 31, 2021
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	4,015	$	—	$	—	$	4,015
Regulated operations – natural gas	1,516		—		—		1,516
Nonregulated operations – wind	—		1,028		—		1028
Nonregulated operations – solar	—		20		—		20
Nonregulated operations – thermal	—		63		—		63
Other (a)	67		84		—		151
Revenue from contracts with customers	5,598		1,195		—		6,793
Leasing revenue	7		—		—		7
Derivative revenue	—		3		—		3
Alternative revenue programs	115		—		—		115
Other revenue	34		22		—		56
Total operating revenues	$	5,754	$	1,220	$	—	$	6,974

	Year Ended December 31, 2020
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	3,642	$	—	$	—	$	3,642
Regulated operations – natural gas	1,311		—		—		1,311
Nonregulated operations – wind	—		822		—		822
Nonregulated operations – solar	—		19		—		19
Nonregulated operations – thermal	—		39		—		39
Other (a)	58		101		—		159
Revenue from contracts with customers	5,011		981		—		5,992
Leasing revenue	6		—		—		6
Derivative revenue	—		136		—		136
Alternative revenue programs	157		—		—		157
Other revenue	14		15		—		29
Total operating revenues	$	5,188	$	1,132	$	—	$	6,320

	Year Ended December 31, 2019
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	3,485	$	—	$	—	$	3,485
Regulated operations – natural gas	1,479		—		—		1,479
Nonregulated operations – wind	—		803		—		803
Nonregulated operations – solar	—		26		—		26
Nonregulated operations – thermal	—		29		—		29
Other (a)	91		62		(12)		141
Revenue from contracts with customers	5,055		920		(12)		5,963
Leasing revenue	6		—		—		6
Derivative revenue	—		244		—		244
Alternative revenue programs	75		—		—		75
Other revenue	28		20		—		48
Total operating revenues	$	5,164	$	1,184	$	(12)	$	6,336

(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 December 31, 2021 and 2020, accounts receivable balances related to contracts with customers were approximately $1,220 million and $1,151 million, respectively, including unbilled revenues of $405 million and $341 million, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets.

As of December 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of December 31, 2021	2022		2023		2024		2025		2026		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	6	$	1	$	1	$	—	$	—	$	—	$	8
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	39		24		9		2		3		2		79
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	26		18		14		12		10		65		145
Total operating revenues	$	71	$	43	$	24	$	14	$	13	$	67	$	232

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).

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Industry Regulation

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Industry Regulation

Industry Regulation

Electricity and Natural Gas Distribution – Maine, New York, Connecticut and Massachusetts

Each of Networks’ eight regulated utility companies must comply with regulatory procedures that differ in form but in all cases conform to the basic framework outlined below. Generally, tariff reviews cover various years and provide for a reasonable ROE, protection from, and automatic adjustments for, exceptional costs incurred and efficiency incentives. The distribution rates and allowed ROEs for Networks’ regulated utilities in New York are subject to regulation by the New York Public Service Commission (NYPSC), in Maine by the Maine Public Utilities Commission (MPUC), in Connecticut by the Connecticut Public Utilities Regulatory Authority (PURA) and in Massachusetts by the Department of Public Utilities (DPU).

The revenues of Networks companies are essentially regulated, being based on tariffs established in accordance with administrative procedures set by the various regulatory bodies. The tariffs applied to the Networks companies are approved by the regulatory commissions of the different states and are based on the cost of providing service. The revenues of each of the Networks companies are set to be sufficient to cover its operating costs, including energy costs, finance costs and the costs of equity, the last of which reflects our capital ratio and a reasonable ROE.

Energy costs that are incurred in the New York and New England wholesale markets are passed on to consumers. The difference between energy costs that are budgeted and those that are actually incurred by the utilities is offset by applying compensation procedures that result in either immediate or deferred tariff adjustments. These procedures apply to other costs, which are in most cases exceptional, such as the effects of extreme weather conditions, environmental factors, regulatory and accounting changes, and treatment of vulnerable customers, that are offset in the tariff process. Any New York and Connecticut revenues that allow a utility to exceed target returns, usually the result of better than expected cost efficiency, are generally shared between the utility and its customers, resulting in future tariff reductions.

The NYSEG and RG&E rate plans, the Maine distribution rate plan and associated proceedings, the Federal Energy Regulatory Commission (FERC) Transmission Return on Equity (ROE) case, the Connecticut rate plans, Reforming Energy Vision (REV), the storm proceedings in New York and the Tax Act are some of the most important specific regulatory processes that currently affect Networks.

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. The MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017. The management efficiency

adjustment was ordered to remain in effect until CMP demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment starting from September 1, 2021. The MPUC approved CMP's request for removal of the management efficiency adjustment effective as of its February 18, 2022 order.

The order provided additional funding for staffing increases, vegetation management programs and storm restoration costs, while retaining the basic tiered structure for storm cost recovery implemented in the 2014 stipulation. The MPUC order also retained the RDM implemented in 2014. The order denied CMP’s request to increase rates for higher costs associated with services provided by its affiliates and ordered the initiation of a management audit to evaluate whether CMP's current management structure, and the management and other services from its affiliates, are appropriate and in the interest of Maine customers. The management audit was commenced in July 2020 by the MPUC's consultants and culminated with a report issued by the MPUC’s consultants in July 2021. On February 18, 2022, the MPUC opened a narrowly tailored follow-on investigation examining how CMP and its customers are affected by decisions made at the CMP corporate parent level about earnings, capital budgeting, and planning. In this context, the investigation will also examine regulatory approaches and structures including ratemaking and performance mechanisms. We cannot predict the outcome of this investigation.

NYSEG and RG&E Rate Plans

2016 Joint Proposal

On June 15, 2016, the NYPSC approved NYSEG's and RG&E's 2016 Joint Proposal for a three-year rate plan for electric and gas service which balanced the varied interests of the signatory parties including but not limited to maintaining the companies’ credit quality and mitigating the rate impacts to customers. The 2016 Joint Proposal reflected many customer benefits including: acceleration of the companies’ natural gas leak prone main replacement programs and increased funding for electric vegetation management to provide continued safe and reliable service. The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows:

	May 1, 2018
	Rate Increase		Delivery Rate Increase
Utility	(Millions)		%
NYSEG Electric	$	30	4.10	%
NYSEG Gas	$	15	7.30	%
RG&E Electric	$	26	5.70	%
RG&E Gas	$	10	5.20	%

The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas was 9.00%. The equity ratio for each company was 48%; however, the equity ratio was set at the actual up to 50% for earnings sharing calculation purposes. The customer share of any earnings above allowed levels increased as the ROE increased, with customers receiving 50%, 75% and 90% of earnings in rate year three (May 1, 2018 – April 30, 2019) above 9.75%, 10.25% and 10.75% ROE, respectively. The rate plans also included the implementation of a rate adjustment mechanism (RAM) designed to return or collect certain defined reconciled revenues and costs, new depreciation rates and continuation of the existing RDM for each business. The 2016 Joint Proposal reflected the recovery of deferred NYSEG Electric storm costs of approximately $262 million, of which $123 million is being amortized over ten years and the remaining $139 million is being amortized over five years. The proposal also continues reserve accounting for qualifying Major Storms ($26 million annually for NYSEG Electric and $3 million annually for RG&E Electric). Incremental maintenance costs incurred to restore service in qualifying divisions will be chargeable to the Major Storm Reserve provided they meet certain thresholds.

The 2016 Joint Proposal maintained NYSEG’s and RG&E’s current electric reliability performance measures (and associated potential negative revenue adjustments for failing to meet established performance levels) which include the system average interruption frequency index (SAIFI) and the customer average interruption duration index (CAIDI). The 2016 Joint Proposal also modified certain gas safety performance measures at the companies, including those relating to the replacement of leak prone mains, leak backlog management, emergency response and damage prevention. The proposal established threshold performance levels for designated aspects of customer service quality and continued and expanded NYSEG’s and RG&E’s bill reduction and arrears forgiveness Low Income Programs with increased funding levels. The 2016 Joint Proposal provided for the implementation of NYSEG’s Energy Smart Community (ESC) Project in the Ithaca region which serves as a test-bed for implementation and deployment of Reforming the Energy Vision (REV) initiatives. The ESC Project is supported by NYSEG’s planned Distribution Automation upgrades and Advanced Metering Infrastructure (AMI) implementation for customers on

circuits in the Ithaca region. The companies also are pursuing Non-Wires Alternative projects as described in the proposal. Other REV-related incremental costs and fees were included in the RAM to the extent cost recovery is not provided for elsewhere. Under the proposal, the RAM was applicable to all customers and serves to return or collect RAM Eligible Deferrals and Costs, including: (1) property taxes; (2) Major Storm deferral balances; (3) gas leak prone pipe replacement; (4) REV costs and fees which are not covered by other recovery mechanisms; and (5) NYSEG Electric Pole Attachment revenues. RG&E implemented a RAM in July 2018 since certain eligibility thresholds were exceeded.

The 2016 Joint Proposal provided for partial or full reconciliation of certain expenses including, but not limited to: pensions and other postretirement benefits; property taxes; variable rate debt and new fixed rate debt; gas research and development; environmental remediation costs; major storms; nuclear electric insurance limited credits; economic development; and low income programs. The 2016 Joint Proposal also included a downward-only Net Plant reconciliation. In addition, the 2016 Joint Proposal included downward-only reconciliations for the costs of electric distribution and gas vegetation management, pipeline integrity and incremental maintenance. The 2016 Joint Proposal provided that NYSEG and RG&E continue their electric RDMs on a total revenue per class basis and their gas RDMs on a revenue per customer basis.

2020 Joint Proposal

On June 22, 2020, NYSEG and RG&E filed a joint proposal with the NYPSC for a new three-year rate plan (2020 Joint Proposal). On November 19, 2020, the NYPSC approved the 2020 Joint Proposal, with modifications to the rate increases at the two electric businesses. The modifications were made to limit the overall bill impacts, to a level at or below 2.00% per year, in consideration of the current impacts of COVID-19 on the economic climate. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The new rates help to 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 ESM, 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 Increase		Rate Increase		Delivery Rate Increase		Rate Increase		Delivery Rate Increase
Utility	(Millions)		%		(Millions)		%		(Millions)		%
NYSEG Electric	$	34	4.6	%	$	46	5.9	%	$	36	4.2	%
NYSEG Gas	$	—	—	%	$	2	0.8	%	$	3	1.6	%
RG&E Electric	$	17	3.8	%	$	14	3.2	%	$	16	3.3	%
RG&E Gas	$	—	—	%	$	—	—	%	$	2	1.3	%

UI, CNG, SCG and BGC Rate Plans

Under Connecticut law, The United Illuminating Company’s (UI) retail electricity customers are able to choose their electricity supplier while UI remains their electric distribution company. UI purchases power for those of its customers under standard service rates who do not choose a retail electric supplier and have a maximum demand of less than 500 kilowatts and its customers under supplier of last resort service for those who are not eligible for standard service and who do not choose to purchase electric generation service from a retail electric supplier. The cost of the power is a “pass-through” to those customers through the Generation Service Charge on their bills.

UI has wholesale power supply agreements in place for its entire standard service load for the first half of 2022, 60% of its standard service load for the second half of 2022. Supplier of last resort service is procured on a quarterly basis and UI has a wholesale power supply agreement in place for the first quarter of 2022. However, from time to time, there are no bidders in the procurement process for supplier of last resort service and UI manages the load directly.

In 2016, PURA approved new distribution rate schedules for 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 ESM pursuant to which UI and its customers share on a 50/50 basis all distribution earnings above the allowed ROE in a calendar year, continued the existing decoupling mechanism and approved the continuation of the requested storm reserve. Any dollars due to customers from the ESM continue to be first applied against any storm regulatory asset balance (if one exists at that time) or refunded to customers through a bill credit if such storm regulatory asset balance does not exist.

In 2017, PURA approved new tariffs for the Southern Connecticut Gas Company (SCG) effective January 1, 2018 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 approximately 52.00% equity level. Any dollars due to customers from the ESM will be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.

In December 2018, PURA approved new tariffs for 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 January 18, 2019, the DPU approved new distribution rates for BGC. The distribution rate increase is based on an ROE 9.70% and 54.00% equity ratio. The new tariffs provide for the implementation of an RDM and pension expense tracker and also provide that BGC will not file to change base distribution rates to become effective before November 1, 2021. BGC expects to file an application to amend its distribution rates in the first half of 2022. We cannot predict the outcome of this proceeding.

REV

In April 2014, the NYPSC commenced a proceeding entitled REV, which is a wide-ranging initiative to reform New York State’s energy industry and regulatory practices. REV has been divided into two tracks, Track 1 for Market Design and Technology, and Track 2 for Regulatory Reform. REV and its related proceedings have and will continue to propose regulatory changes that are intended to promote more efficient use of energy, deeper penetration of renewable energy resources such as wind and solar and wider deployment of distributed energy resources (DER), such as micro grids, on-site power supplies and storage.

REV is also intended to promote greater use of advanced energy management products to enhance demand elasticity and efficiencies. Track 1 of this initiative involves a collaborative process to examine the role of distribution utilities in enabling market-based deployment of DER to promote load management and greater system efficiency, including peak load reductions. NYSEG is participating in the initiative with other New York utilities. The NYPSC issued a 2015 order in Track 1, which acknowledges the utilities’ role as a Distribution System Platform provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) by June 30, 2016, followed by bi-annual updates. The companies filed the initial DSIP, which also included information regarding the potential deployment of Automated Metering Infrastructure (AMI) across its entire service territory. In December 2016, the companies filed a petition to the NYPSC requesting approval for cost recovery associated with the full deployment of AMI. A collaborative associated with this petition began in the first quarter of 2017, was suspended in the second quarter of 2017, subsequently resumed in the first quarter of 2018 and then further suspended and was been included in the companies’ May 20, 2019 rate filing. The companies also filed their first bi-annual update of the DSIP on July 31, 2018 and filed their next bi-annual update on June 30, 2020.

Other various proceedings have also been initiated by the NYPSC which are REV related, and each proceeding has its own schedule. These proceedings include the Clean Energy Standard, Value of DER and Net Energy Metering, Demand Response Tariffs and Community Choice Aggregation. As part of the Clean Energy Standard proceeding, all electric utilities were ordered to begin payments to New York State Energy Research and Development Authority (NYSERDA) for RECs and Zero Emissions Credits beginning in 2017.

Track 2 of the REV initiative is also underway, and through a NYPSC staff whitepaper review process, is examining potential changes in current regulatory, tariff, market design and incentive structures that could better align utility interests with achieving New York state and NYPSC’s policy objectives. New York utilities will also be addressing related regulatory issues in their individual rate cases. A Track 2 order was issued in May 2016, and includes guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs and data utilization and security. The companies, in December 2016, filed a proposal for the implementation of EAMs in the areas of System Efficiency, Energy Efficiency, Interconnections and Clean Air. A collaborative process to review the companies’ petition was suspended in 2017. The approved 2020 Joint Proposal includes EAMs.

In March 2017, the NYPSC issued three separate REV-related orders. These orders created a series of filing requirements for NYSEG and RG&E beginning in March 2017 and extending through the end of 2018. The three orders involve: 1) modifications to the electric utilities’ proposed interconnection EAM framework; 2) further DSIP requirements, including filing of an updated DSIP plan by mid-2018 and implementing two energy storage projects at each company by the end of 2018; and 3) Net Energy Metering Transition including implementation of Phase One of the Value of DER. In September 2017, the NYPSC issued another order related to the Value of DER, requiring tariff filings, changes to Standard Interconnection

Requirements and planning for the implementation of automated consolidated billing. As of the end of 2018, both NYSEG and RG&E had deployed two energy storage projects each, consistent with the March 2017 NYPSC order requirements. In December 2018, the NYPSC staff submitted whitepapers on standby and buyback service rate design, future value stack compensation and capacity value compensation. The NYPSC ruled on the proposals set forth in the whitepapers on May 16, 2019. NYSEG and RG&E filed proposed standby and buyback rates with the NYPSC in September 2019. On November 25, 2020, DPS Staff, jointly with NYSERDA, issued a whitepaper on further recommendations regarding standby and buyback rates that were based on the electric utilities’ September 23, 2019 filings. Comments on the recommendations in the whitepaper are due February 22, 2021, and reply comments are due March 8, 2021. A final Commission Order is expected in 2022.

On April 18, 2019, the NYPSC issued an order on future value stack compensation and capacity value compensation. The order established a new Community Credit in place of the Market Transition Credit for certain CDG projects in NYSEG’s and RGE’s territories and expanded eligibility for Phase One Net Metering for projects that have a rated capacity of 750 kW AC or lower. The changes became effective on June 1, 2019. The NYPSC also issued an order on value stack compensation for high-capacity-factor Resources on December 12, 2019, modifying the treatment of certain high-capacity-factor DER in the Value Stack compensation framework. The modification per the December 12, 2019 Order became effective February 1, 2020. On March 19, 2020, the Commission issued an additional Order regarding Value Stack Compensation. The Order directs National Grid, NYSEG and RGE to reallocate capacity from closed tranches where available capacity remained due to projects being canceled since the issuance of the VDER Compensation Order, and to assign that capacity to a new Community Credit Tranche with compensation at 2 cents per kWh. The utilities must also continue to reallocate capacity to this new Tranche for the next six months when there are cancellations of projects that have received a Market Transition Credit (MTC) or Community Credit allocation. The new provisions per the March 19, 2020 Order became effective May 1, 2020.

On May 14, 2020, the Commission issued an Order extending and expanding distributed solar incentives. In addition to authorizing the extension of and additional funding for the NY-Sun program, the Commission modified certain program rules related to the NY-Sun program and the VDER policy. As part of the ordered modifications, the Commission directed the electric utilities with VDER tariffs to add tariff language for a Remote Crediting program that will allow Value-Stack-eligible generation resources to distribute the credits they receive for generation injected into the utility system to the utility bills of multiple, separately sited, non-residential customers. The Commission ordered the utilities to submit tariff leaves that implement the modifications associated with the Remote Crediting program to become effective November 1, 2020. Given the complexity of the program changes, the utilities have petitioned the Commission for an extension. Tariffs were filed on August 16, 2021, becoming effective on September 1, 2021.

On July 16, 2020, the Commission issued an Order establishing a net metering successor tariff. The Order continues Phase One NEM for all eligible mass market and commercial projects under 750 kW interconnected after January 1, 2022 and implements a modest customer benefit contribution (CBC) for onsite DERs to address cost recovery of certain public benefit programs. Customers that install DERs interconnected after January 1, 2022 shall be charged a monthly per kW fee based on the nameplate rating of the DER. Draft tariff leaves implementing the Commission’s Order and proposed CBC calculations were filed on November 1, 2020. A final Commission Order was issued on August 13, 2021, implementing the CBC effective January 1, 2022 for new mass market net metering customers.

On April 24, 2018, the NYPSC instituted a proceeding to consider the role of utilities in providing infrastructure and rate design to encourage the expansion electric vehicles and electric vehicle supply equipment. The Commission issued an Order on February 2, 2019 to establish a Direct Current Fast Charger incentive program, with subsequent clarifications provided in Orders issued on July 12, 2019 and March 3, 2020. On July 16, 2020, the NYPSC issued an Order approving a $700 million statewide program (NYSEG and RG&E combined share is approximately $118 million). The make-ready program will be funded by investor-owned utilities in New York State and creates a cost-sharing program that incentivizes utilities and charging station developers to site electric vehicle charging infrastructure in places that will provide a maximal benefit to consumers.

CMP Customer Billing System Investigation

On March 1, 2018, the MPUC issued a Notice of Investigation initiating a summary investigation into CMP’s metering, billing and customer communications practices. Due to the highly technical nature of CMP’s customer billing system the MPUC ordered a forensic audit of CMP’s customer billing system to identify any errors that have, or continue to result in billing inaccuracies, and to review CMP’s customer communication practices. On December 20, 2018, the MPUC released the findings of the forensic audit of CMP’s customer billing system and customer communication practices. On January 9, 2020, the hearing examiners issued their report whereby they recommended that the Commission find that the evidence in the record shows that there is no systemic problem within CMP’s metering and billing systems that has caused erroneous high usage on customers’ bills. Instead, the evidence-including the detailed forensic audit conducted by an independent third-party auditor-demonstrates that CMP’s metering and billing systems have been, and continue to be, recording and transmitting customer usage data accurately, and, with the exception of discrete billing calculation and presentation issues, customers’ billed amounts have been

accurate. On January 30, 2020, the MPUC Commissioners deliberated and based on the verbal discussion, the Commissioners indicated that CMP’s Metering and Billing system is accurately reporting data; there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The Commissioners were critical of CMP finding that CMP failed to implement proper testing of the SmartCare system prior to go-live; CMP’s implementation of SmartCare was imprudent; CMP’s SmartCare implementation experienced an unacceptable number of billing errors, delayed or estimated bills, bill presentment issues and unreasonable time required to address these issues; and the implementation issues were compounded by inadequate staffing, resulting in the inability of customers to contact a CMP representative. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above the MPUC imposed a reduction of 100 basis points in ROE, as a management efficiency adjustment, to address concerns with CMP’s customer service performance following the implementation of its new billing system in 2017 and on February 24, 2020 issued an order in the metering and billing investigation. Each order reflected the MPUC’s conclusion that CMP’s Metering and Billing system is accurately reporting data, there is no systemic root cause for high usage complaints and errors related to CMP’s metering and billing system are localized and random, not systemic. The management efficiency adjustment was ordered to remain in effect until CMP demonstrated satisfactory customer service performance on four specified service quality measures for a rolling average period of 18 months, which commenced on March 1, 2020. CMP has met the required rolling average benchmarks for all four of these quality measures and on September 20, 2021, filed with the MPUC a request for removal of the management efficiency adjustment. In addition to requesting the lifting of the management efficiency adjustment, CMP requested an accounting order to allow it to defer for future recovery the revenues it would effectively lose by not having the adjustment starting from September 1, 2021. The MPUC approved CMP's request for removal of the management efficiency adjustment as of its February 18, 2022 order.

Tax Cuts and Jobs Act

On December 22, 2017, the Tax Cuts and Jobs Act of 2017 (the Tax Act) was signed into law. The Tax Act significantly changed the federal taxation of business entities including, among other things, implementing a federal corporate tax rate decrease from 35% to 21% for tax years beginning after December 31, 2017. Reductions in accumulated deferred income tax balances due to the reduction in the corporate income tax rates 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, to review and address the implications of the Tax Act on the utilities.

In New York, the NYPSC issued an order requiring sur-credits to return benefits reflecting the lower effective tax rate of 21% to customers effective October 1, 2018. For NYSEG Gas, RG&E Electric and RG&E Gas the NYPSC also required the sur-credit to include the return to customers of the January - September 2018 Tax Act savings over three years. The remaining deferred amounts associated with the recognition of the effects of the Tax Act are being used as rate moderators in the approved 2020 Joint Proposal. In Connecticut, with regard to UI, the PURA approved a multi-docket settlement proposal on June 28, 2021, which required UI to flow accumulated Tax Act savings back to customers over a 22-month period, commencing on July 1, 2021 through April 30, 2023. With regard to SCG, we expect Tax Act savings to be deferred until they are reflected in tariffs in a future rate case, unless PURA determines otherwise. CNG and BGC include Tax Act savings in their current rate plans. In Maine, CMP adjusted rates beginning July 1, 2018 to pass back to customers the Tax Act savings after offsetting for recovery of deferred 2017 storm costs. In its February 19, 2020 order in the CMP’s distribution rate case proceeding discussed above, the MPUC approved CMP’s distribution related accumulated deferred income tax balances associated with the Tax Act as well as the authorized amortization periods for the return of regulatory liabilities and the recovery regulatory assets. At the FERC, CMP transmission and UI transmission adjusted their tariffs in June 2018 to reflect the income statement value of Tax Act savings. On December 22, 2021, the FERC issued an order finding that the New England Transmission Owners (NETOs) Regional Network Service proposed revisions partially comply with the requirements of Order 864 and directed the NETOs to submit a further compliance filing within 60 days of the date of the order. The compliance is effective January 27, 2020, consistent with Order 864 and January 1, 2022, to reflect the fact that the NETOs existing transmission formula rates under the ISO-NE Tariff will be replaced by a settled formula rate effective January 1, 2022.

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 $142 million and $148 million, respectively for this item at December 31, 2021 and 2020.

In 2017, audits of the power tax regulatory assets were commenced by the NYPSC and MPUC. On January 11, 2018, the NYPSC issued an order opening an operations audit on NYSEG and RG&E and certain other New York utilities regarding tax

accounting. The NYPSC audit report is expected to be completed during 2022. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which indicated the auditor was unable to verify the asset “acquisition value” used to calculate the Power Tax regulatory asset. The audit report requires that CMP must provide support for the beginning balance of the regulatory assets or it will be unable to recover the value of the assets, which is approximately $11 million, excluding carrying costs. CMP responded to the audit report in its rate case filing by providing additional acquisition value support and, therefore, requested full recovery of the Power Tax regulatory asset. MPUC staff expressed concerns about the value CMP has attributed to this issue. The MPUC had an outside firm conduct an audit of CMP's filing and acquisition values, and the auditor found CMP's information was reasonable. In September 2019, CMP filed a report in response to the audit report and addressed MPUC staff concerns. On December 17, 2019, CMP filed a stipulation with the MPUC providing for recovery of the Power Tax regulatory asset and adjusting the carrying costs values for the period of July 1, 2017 through June 30, 2019. The MPUC approved the stipulation on January 21, 2020, which allowed CMP to start collecting the Power Tax Regulatory asset over the next 32.5 years beginning in July 2020.

Minimum Equity Requirements for Regulated Subsidiaries

Our regulated utility subsidiaries of Maine and New York (NYSEG, RG&E, CMP and MNG) are each subject to a minimum equity ratio requirement that is tied to the capital structure assumed in establishing revenue requirements. Pursuant to these requirements, each of NYSEG, RG&E, CMP and MNG must maintain a minimum equity ratio equal to the ratio in its currently effective rate plan or decision measured using a trailing 13-month average. On a monthly basis, each utility must maintain a minimum equity ratio of no less than 300 basis points below the equity ratio used to set rates. The minimum equity ratio requirement has the effect of limiting the amount of dividends that may be paid and may, under certain circumstances, require that the parent contribute equity capital. In addition, NYSEG and RG&E equity distributions that would result in a 13-month average common equity less than the maximum equity ratio utilized for the earnings sharing mechanism, or ESM, are prohibited if the credit rating of NYSEG, RG&E, AVANGRID or Iberdrola are downgraded by a nationally recognized rating agency to the lowest investment grade with a negative watch or downgraded to non-investment grade. These regulated utility subsidiaries are prohibited by regulation from lending to unregulated affiliates. These regulated utility subsidiaries have also agreed to minimum equity ratio requirements in certain borrowing agreements. These requirements are lower than the regulatory requirements.

Pursuant to agreements with the relevant utility commission, UI, SCG, CNG and BGC are restricted from paying dividends if paying such dividend would result in a common equity ratio lower than 300 basis points below the equity percentage used to set rates in the most recent distribution rate proceeding as measured using a trailing 13-month average calculated as of the most recent quarter end. In addition, UI, SCG, CNG and BGC are prohibited from paying dividends to their parent if the utility’s credit rating, as rated by any of the three major credit rating agencies, falls below investment grade, or if the utility’s credit rating, as determined by two of the three major credit rating agencies, falls to the lowest investment grade and there is a negative watch or review downgrade notice.

We had restricted net assets of approximately $5,808 million associated with the minimum equity requirements as of December 31, 2021.

Movement of capital from our wholly owned unregulated subsidiaries is unrestricted.

New Renewable Source Generation

Under Connecticut Public Act (PA) 11-80, Connecticut electric utilities are required to enter into long-term contracts to purchase Connecticut Class I RECs from renewable generators located on customer premises. Under this program, UI was initially required to enter into contracts totaling approximately $200 million in commitments over an approximate 21-year period. The obligations were initially expected to phase in over a six-year solicitation period and peak at an annual commitment level of about $14 million per year after all selected projects are online. PA 17-144, PA 18-50 and PA 19-35 extended the original six-year solicitation period of the program by adding seventh, eighth, ninth, and tenth years, and increased the original funding level of this program by adding up to $64 million in additional commitments by UI. Upon purchase, UI accounts for the RECs as inventory. UI expects to partially mitigate the cost of these contracts through the resale of the RECs. PA 11-80 provides that the remaining costs (and any benefits) of these contracts, including any gain or loss resulting from the resale of the RECs, are fully recoverable from (or credited to) customers through electric rates.

In October of 2018, UI entered into five PPAs totaling approximately 50 MW from developers of offshore wind and fuel cell generation pursuant to state law that provides the net costs of the PPAs are recoverable through electric rates. On December 19, 2018, PURA approved the PPAs, and approved UI’s use of the non-bypassable federally mandated congestion charges for all customers to recover the net costs of the PPAs.

In 2019, UI entered into PPAs with 11 projects, totaling approximately 12 million MWh, pursuant to state law that provides that the net costs of the PPAs are recoverable through electric rates.

In 2020, pursuant to Connecticut Act Concerning the Procurement of Energy Derived From Offshore Wind, UI entered into a PPA with Vineyard Wind, an affiliate of UI, to provide 804 MW of offshore wind through the development of its Park City Wind Project. Similar to the case with the zero carbon PPAs discussed above, the net costs of the PPAs are recoverable through electric rates.

Pursuant to Maine law, the MPUC is authorized to conduct periodic requests for proposals seeking long-term supplies of energy, capacity or RECs, from qualifying resources. The MPUC is further authorized to order Maine transmission and distribution utilities to enter into contracts with sellers selected from the MPUC’s competitive solicitation process. Pursuant to a MPUC Order dated October 8, 2009, CMP entered into a 20-year agreement with Evergreen Wind Power III, LLC, on March 31, 2010, to purchase capacity and energy from Evergreen’s 60 Megawatt (MW) Rollins wind farm. CMP’s purchase obligations under the Rollins contract are approximately $7 million per year. Pursuant to a MPUC Order dated December 18, 2017, CMP entered into a 20-year agreement with Dirigo Solar, LLC on September 10, 2018, to purchase capacity and energy from multiple Dirigo solar facilities throughout CMP’s service territory. CMP’s purchase obligations under the Dirigo contract will increase as additional solar facilities are brought on line, eventually reaching a level of approximately $4 million per year. Pursuant to a MPUC Order dated November 6, 2019, CMP entered into a 20-year agreement with Maine Aqua Ventus I GP LLC on December 9, 2019, to purchase capacity and energy from an off-shore wind farm under development near Monhegan Island, Maine. CMP’s purchase obligations under the Maine Aqua Ventus contract will be approximately $12 million per year once the facility begins commercial operation. Pursuant to Maine law, the MPUC conducted two competitive solicitation processes to procure, in the aggregate, an amount of energy or RECs from Class 1A resources that is equal to 14% of retail electricity sales in the State during calendar year 2018, or 1.715 million MWh. Of that 14% total, the MPUC must acquire at least 7%, but not more than 10%. Through contracts approved in December 2020 (Tranche 1), CMP was ordered to execute 13 contracts. In October 2021 CMP executed contracts with 6 additional facilities (Tranche 2). Each of the Tranche 1 and Tranche 2 are for 20-year terms. In accordance with MPUC orders, CMP either sells the purchased energy, or in one case the RECs, from these facilities in the ISO New England markets, through periodic auctions of the purchased output to wholesale buyers in the New England regional market, or through a sale to a third party for the RECs. Under Maine law, CMP is assured recovery of any differences between power purchase costs and achieved market revenues through a reconcilable component of its retail distribution rates. Although the MPUC has conducted multiple requests for proposals under Maine law, and has tentatively accepted long-term proposals from other sellers, these selections have not yet resulted in additional currently effective contracts with CMP.

Connecticut Energy Legislation

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

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

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

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

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

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

On August 6, 2020, the PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. 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 Storm Isaias Docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. We cannot predict the outcome of these appeals.

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Regulatory Assets and Liabilities

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Regulatory Assets and Liabilities

Regulatory Assets and Liabilities

Pursuant to the requirements concerning accounting for regulated operations, our utilities capitalize as regulatory assets incurred and accrued costs that are probable of recovery in future electric and natural gas rates. We base our assessment of whether recovery is probable on the existence of regulatory orders that allow for recovery of certain costs over a specific period, or allow for reconciliation or deferral of certain costs. When costs are not treated in a specific regulatory order, we use regulatory precedent to determine if recovery is probable. Our operating utilities also record, as regulatory liabilities, obligations to refund previously collected revenue or to spend revenue collected from customers on future costs. The primary items that are not included in rate base or accruing carrying costs are regulatory assets for qualified pension and other postretirement benefits, which reflect unrecognized actuarial gains and losses; debt premium; environmental remediation costs, which are primarily the offset of accrued liabilities for future spending; unfunded future income taxes, which are the offset to the unfunded future deferred income tax liability recorded; asset retirement obligations; hedge losses; and contracts for differences. The total net amount of these items is approximately $1,136 million.

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 December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Pension and other post-retirement benefits	$	545	$	927
Pension and other post-retirement benefits cost deferrals	95		105
Storm costs	448		451
Rate adjustment mechanism	68		33
Revenue decoupling mechanism	68		58
Transmission revenue reconciliation mechanism	15		31
Contracts for differences	73		86
Hardship programs	24		20
Plant decommissioning	2		3
Deferred purchased gas	52		30
Deferred transmission expense	13		26
Environmental remediation costs	256		247
Debt premium	71		83
Unamortized losses on reacquired debt	23		26
Unfunded future income taxes	424		373
Federal tax depreciation normalization adjustment	142		148
Asset retirement obligation	20		21
Deferred meter replacement costs	46		33
COVID-19 cost recovery	21		1
Other	241		180
Total regulatory assets	2,647		2,882
Less: current portion	400		310
Total non-current regulatory assets	$	2,247	$	2,572

“Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses.

“Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases.

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

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

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

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

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

rates.

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

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

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

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

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

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

“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of forty-six years and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances.

“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020.

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

“Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by AMI meters. This amount is being amortized over the initial depreciation period of related retired meters.

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

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

Regulatory liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Energy efficiency portfolio standard	$	45	$	58
Gas supply charge and deferred natural gas cost	7		3
Pension and other post-retirement benefits cost deferrals	73		59
Carrying costs on deferred income tax bonus depreciation	23		34
Carrying costs on deferred income tax - Mixed Services 263(a)	7		11
2017 Tax Act	1,327		1,435
Rate change levelization	99		55
Revenue decoupling mechanism	13		9
Accrued removal obligations	1,192		1,184
Asset sale gain account	2		7
Economic development	26		28
Positive benefit adjustment	22		30
Theoretical reserve flow thru impact	6		10
Deferred property tax	22		31
Net plant reconciliation	16		20
Debt rate reconciliation	49		63
Rate refund – FERC ROE proceeding	35		33
Transmission congestion contracts	23		22
Merger-related rate credits	12		14
Accumulated deferred investment tax credits	24		25
Asset retirement obligation	18		18
Earnings sharing provisions	13		17
Middletown/Norwalk local transmission network service collections	17		18
Low income programs	25		28
Non-firm margin sharing credits	15		14
New York 2018 winter storm settlement	5		9
Hedges gains	19		—
Other	194		176
Total regulatory liabilities	3,329		3,411
Less: current portion	307		274
Total non-current regulatory liabilities	$	3,022	$	3,137

“Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

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

“Pension and other postretirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.

“Carrying costs on deferred income tax bonus depreciation” represent the carrying costs benefit of increased accumulated deferred income taxes created by the change in tax law allowing bonus depreciation. A portion of this balance is amortized

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

"Carrying costs on deferred income tax - Mixed Services 263(a)" represent the carrying costs benefit of increased accumulated deferred income taxes created by Section 263 (a) IRC. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

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

"Rate change levelization" adjusts the New York delivery rate increases across the three-year plan to avoid unnecessary spikes and offsetting dips in customer rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is five years and began in 2020.

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

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

“Asset sale gain account” represents the net gain on the sale of certain assets that will be used for the future benefit of customers. The amortization period in current rates is three years for NYSEG and two years for RG&E and began in 2020.

“Economic development” represents the economic development program, which enables NYSEG and RG&E to foster economic development through attraction, expansion and retention of businesses within its service territory. If the level of actual expenditures for economic development allocated to NYSEG and RG&E varies in any rate year from the level provided for in rates, the difference is refunded to customers. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three years and began in 2020.

“Positive benefit adjustment” resulted from Iberdrola’s 2008 acquisition of AVANGRID (formerly Energy East Corporation). This is being used to moderate increases in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases. The amortization period in current rates is three to five 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 14 for more details.

"Transmission congestion contracts" represents deferral of the Nine Mile 2 Nuclear Plant transmission congestion contract at RGE. 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. In both of the years ended December 31, 2021 and 2020, $2 million of rate credits were applied against customer bills.

“Accumulated deferred investment tax credits” represents investment tax credits related to plant investments that are deferred when earned and amortized over the estimated lives of the related assets.

“Asset retirement obligation” represents fair value of the liability for an asset retirement the company is legally committed to removing (PCB transformers, bare steel).

"Earning sharing provisions" represents the annual earnings over the earning 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 NYSPSC following the comprehensive investigation of New York’s major utility companies’ preparation and response to March 2018 storms. This 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.

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Goodwill and Intangible assets

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Goodwill and Intangible assets

Goodwill and Intangible assets

Goodwill by reportable segment as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Networks	$	2,747	$	2,747
Renewables	372		372
Total	$	3,119	$	3,119

During 2021, there were no changes in gross amounts and accumulated losses of goodwill for the Networks and Renewables reportable segments.

Goodwill Impairment Assessment

For impairment testing purposes, our reporting units are the same as operating segments, except for Networks, which contains three reporting units, Maine, New York and UIL. Goodwill for the Maine reporting unit is $325 million from the purchase of CMP by Energy East Corporation in 2000. Goodwill for the New York reporting unit is $654 million primarily from the purchase of RG&E by Energy East in 2002. Goodwill for the UIL reporting unit is $1,768 million from the 2015 acquisition of UIL.

We perform our annual impairment testing in the fourth quarter, as of October 1. Our qualitative assessment involves evaluating key events and circumstances that could affect the fair value of our reporting units, as well as other factors. Events and circumstances evaluated include macroeconomic conditions, industry, regulatory and market considerations, cost factors and their effect on earnings and cash flows, overall financial performance as compared with projected results and actual results of relevant prior periods, other relevant entity specific events and events affecting a reporting unit.

Our quantitative assessment utilizes a discounted cash flow model under the income approach and includes critical assumptions, primarily the discount rate and internal estimates of forecasted cash flows. We use a discount rate that is developed using market participant assumptions, which consider the risk and nature of the respective reporting unit’s cash flows and the rates of return market participants would require in order to invest their capital in our reporting units. We test the reasonableness of the conclusions of our quantitative impairment testing using a range of discount rates and a range of assumptions for long-term cash flows.

For 2021, we utilized a qualitative assessment for the Networks reporting units and a quantitative assessment for the Renewables reporting unit. For 2020, we utilized a quantitative assessment for the Networks and Renewables reporting units. We had no impairment of goodwill in 2021 and 2020 as a result of our impairment testing.

Intangible assets

Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2021 and 2020:

As of December 31, 2021	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
(Millions)
Wind development	$	592	$	(301)	$	291
Other	18		(16)		2
Total Intangible Assets	$	610	$	(317)	$	293

As of December 31, 2020	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
(Millions)
Wind development	$	593	$	(290)	$	303
Other	31		(29)		2
Total Intangible Assets	$	624	$	(319)	$	305

Wind development costs, with the exception of future ‘pipeline’ development costs, are amortized on a straight-line basis in accordance with the life of the related assets once placed in service. Amortization expense was $13 million, $14 million and $15 million for the years ended December 31, 2021, 2020 and 2019, respectively. We believe our future cash flows will support the recoverability of our intangible assets.

We expect amortization expense for the five years subsequent to December 31, 2021, to be as follows:

Year ending December 31,	Amount
(Millions)
2022	$	14
2023	$	13
2024	$	13
2025	$	12
2026	$	12

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Property, Plant and Equipment

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Property, Plant and Equipment

Property, Plant and Equipment

Property, plant and equipment as of December 31, 2021, consisted of:

As of December 31, 2021	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	17,392	$	13,446	$	30,838
Natural gas transportation, distribution and other	5,032		13		5,045
Other common operating property	—		286		286
Total Property, Plant and Equipment in Service	22,424		13,745		36,169
Total accumulated depreciation	(5,806)		(4,783)		(10,589)
Total Net Property, Plant and Equipment in Service	16,618		8,962		25,580
Construction work in progress	2,064		1,222		3,286
Total Property, Plant and Equipment	$	18,682	$	10,184	$	28,866

Property, plant and equipment as of December 31, 2020, consisted of:

As of December 31, 2020	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	16,364	$	12,854	$	29,218
Natural gas transportation, distribution and other	4,637		13		4,650
Other common operating property	—		274		274
Total Property, Plant and Equipment in Service	21,001		13,141		34,142
Total accumulated depreciation	(5,363)		(4,436)		(9,799)
Total Net Property, Plant and Equipment in Service	15,638		8,705		24,343
Construction work in progress	1,384		1,024		2,408
Total Property, Plant and Equipment	$	17,022	$	9,729	$	26,751

Capitalized interest costs were $33 million, $51 million and $51 million for the years ended December 31, 2021, 2020 and 2019, respectively. Accrued liabilities for property, plant and equipment additions were $297 million, $285 million and $357 million as of December 31, 2021, 2020 and 2019, respectively.

We impaired or wrote off amounts of $20 million, $7 million and $11 million for the years ended December 31, 2021, 2020 and 2019, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction.

Depreciation expense for the years ended December 31, 2021, 2020 and 2019, amounted to $1,001 million, $973 million and $918 million, respectively.

In 2021, an indicator of impairment was identified for the New England Clean Energy Connect (NECEC) project resulting from a Maine referendum decision and we performed a test of recoverability in which no impairment loss was recognized. As of December 31, 2021 and 2020, we have capitalized approximately $546 million and $180 million, respectively, for the NECEC project.

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Asset retirement obligations

12 Months Ended

Dec. 31, 2021

Asset Retirement Obligation Disclosure [Abstract]

Asset retirement obligations

Asset retirement obligations

AROs are intended to meet the costs for dismantling and restoration work that we have committed to carry out at our operational facilities.

The reconciliation of ARO carrying amounts for the years ended December 31, 2021 and 2020 consisted of:

(Millions)
As of December 31, 2019	$	190
Liabilities settled during the year	(2)
Liabilities incurred during the year	9
Accretion expense	11
Revisions in estimated cash flows (a)	2
As of December 31, 2020	$	210
Liabilities settled during the year	(2)
Liabilities incurred during the year	7
Accretion expense	12
Revisions in estimated cash flows (a)	26
As of December 31, 2021	$	253

(a)Represents an increase in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities.

Several of the wind generation facilities have restricted cash for purposes of settling AROs. As of both December 31, 2021 and 2020, restricted cash related to AROs was $3 million. These amounts have been included in “Other Assets” on our consolidated balance sheets. Accretion expenses are included in “Operations and maintenance” in our consolidated statements of income.

We have AROs for which a liability has not been recognized because the fair value cannot be reasonably estimated due to indeterminate settlement dates, including for the removal of hydroelectric dams due to structural inadequacy or for

decommissioning; the removal of property upon termination of an easement, right-of-way or franchise; and costs for abandonment of certain types of gas mains.

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Debt

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Debt

Debt

Long-term debt as of December 31, 2021 and 2020 consisted of:

As of December 31,		2021			2020
	Maturity Dates	Balances		Interest Rates	Balances		Interest Rates
(Millions)
First mortgage bonds - fixed (a)	2022-2051	$	2,759	1.85%-8.00%	$	2,575	1.85%-8.00%
Unsecured pollution control notes - fixed	2023-2029	478		1.40%-3.50%	478		1.40%-3.50%
Other various non-current debt - fixed	2022-2050	5,110		1.95%-6.66%	4,785		1.95%-7.80%
Unamortized debt issuance costs and discount		(53)			(47)
Total Debt		8,294			7,791
Less: debt due within one year, included in current liabilities		372			313
Total Non-current Debt		$	7,922		$	7,478

(a)The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $7,871 million.

Iberdrola Loan

On December 14, 2020, AVANGRID and Iberdrola entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid with the proceeds of the common share issuance described in Note 1.

Other 2021 Long-Term Debt Issuances

Company	Issue Date	Type	Amount (Millions)		Interest rate		Maturity
NYSEG	9/24/2021	Unsecured Notes	$	350	2.15	%	2031
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.91	%	2051
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.10	%	2031
CMP	12/15/2021	First Mortgage Bonds	$	200	2.05	%	2031
SCG	12/15/2021	First Mortgage Bonds	$	40	2.05	%	2031

Long-term debt maturities, including sinking fund obligations, due over the next five years consist of:

2022		2023		2024		2025		2026		Total
(Millions)
$	372	$	439	$	612	$	1,107	$	660	$	3,190

We make certain standard covenants to lenders in our third-party debt agreements, including, in certain agreements, covenants regarding the ratio of indebtedness to total capitalization. A breach of any covenant in the existing credit facilities or the agreements governing our other indebtedness would result in an event of default. Certain events of default may trigger automatic acceleration. Other events of default may be remedied by the borrower within a specified period or waived by the lenders and, if not remedied or waived, give the lenders the right to accelerate. Neither we nor any of our subsidiaries were in breach of covenants or of any obligation that could trigger the early redemption of our debt as of both December 31, 2021 and 2020 and throughout 2021 and 2020.

Fair Value of Debt

As of December 31, 2021 and 2020, the estimated fair value of long-term debt, including the Iberdrola Loan as of December 31, 2020, was $9,155 million and $12,166 million, respectively. The estimated fair value was determined, in most cases, by discounting the future cash flows at market interest rates. The interest rate curve used to make these calculations takes into account the risks associated with the electricity industry and the credit ratings of the borrowers in each case. The fair value of debt is considered Level 2 within the fair value hierarchy.

Short-term Debt

AVANGRID had $159 million and $307 million of notes payable as of December 31, 2021 and 2020, respectively.

AVANGRID has a commercial paper program with a limit of $2 billion which is backstopped by the AVANGRID credit facilities described below. As of December 31, 2021 and 2020, the amount of notes payable under the commercial paper program was $0 and $309 million, respectively, presented net of discounts on the balance sheet. As of December 31, 2020, the weighted-average interest rate on outstanding commercial paper was 0.32%.

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 contains a commitment from lenders, which will expire on April 20, 2022 if not terminated by AVANGRID at an earlier date 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 December 31, 2021, we had no borrowings outstanding under this credit facility.

Since the AVANGRID Credit Facility is also a backstop to the AVANGRID commercial paper program, the total amount available under the facility as of December 31, 2021 was $3,575 million.

2020 Credit Facility

During 2020, we entered into a revolving credit agreement with several lenders, or the 2020 Credit Facility, that provides maximum borrowings up to $500 million. We terminated this facility on April 28, 2021.

Iberdrola Group Credit Facility

AVANGRID has a credit facility with Iberdrola Financiacion, S.A.U., a company of the Iberdrola Group. The facility has a limit of $500 million and matures on June 18, 2023. AVANGRID pays a facility fee of 10.5 basis points annually on the facility. As of both December 31, 2021 and 2020, there was no outstanding amount under this credit facility.

Supplier Financing Arrangements

We operate a supplier financing arrangement. During 2021, we arranged for the extension of payment terms with some suppliers, which could elect to be paid by a financial institution earlier than maturity under supplier financing arrangements. Due to the interest cost associated with these arrangements, the balances are classified as "Notes payable" on our consolidated balance sheets. The balance relates to capital expenditures and, therefore, is treated as non-cash activity. As of December 31, 2021 and 2020, the amount of notes payable under supplier financing arrangements was $161 million and $0, respectively. As of December 31, 2021, the weighted average interest rate on the balance was 0.82%.

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Fair Value of Financial Instruments and Fair Value Measurements

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Fair Value of Financial Instruments and Fair Value Measurements

Fair Value of Financial Instruments and Fair Value Measurements

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

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

•NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based

upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1.

•NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. 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 12 for further discussion of CfDs).

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

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

We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2.

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

Restricted cash was $3 million and $4 million as of December 31, 2021 and 2020, respectively and is included in “Other Assets” on our consolidated balance sheets.

The financial instruments measured at fair value as of December 31, 2021 and 2020 consisted of:

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

As of December 31, 2020	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity and other investments with readily determinable fair values	$	49	$	14	$	—	$	—	$	63
Derivative assets
Derivative financial instruments - power	$	5	$	31	$	105	$	(54)	$	87
Derivative financial instruments - gas	—		24		19		(35)		8
Contracts for differences	—		—		2		—		2
Total	$	5	$	55	$	126	$	(89)	$	97
Derivative liabilities
Derivative financial instruments - power	$	(23)	$	(31)	$	(23)	$	72	$	(5)
Derivative financial instruments - gas	(1)		(9)		(2)		9		(3)
Contracts for differences	—		—		(88)		—		(88)
Derivative financial instruments – Other	—		—		—		—		—
Total	$	(24)	$	(40)	$	(113)	$	81	$	(96)

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2021, 2020 and 2019 consisted of:

(Millions)	2021		2020		2019
Fair value as of January 1,	$	13	$	25	$	(15)
Gains for the year recognized in operating revenues	21		8		53
Losses for the year recognized in operating revenues	(34)		(2)		(2)
Total gains or losses for the period recognized in operating revenues	(13)		6		51
Gains recognized in OCI	2		1		2
Losses recognized in OCI	(52)		(3)		(3)
Total gains or losses recognized in OCI	(50)		(2)		(1)
Net change recognized in regulatory assets and liabilities	13		6		5
Purchases	(17)		(2)		(22)
Settlements	(13)		(15)		4
Transfers out of Level 3 (a)	(2)		(5)		3
Fair value as of December 31,	$	(69)	$	13	$	25
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$	(13)	$	6	$	51

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

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 December 31, 2021.

Index	Avg.		Max.		Min.
NYMEX ($/MMBtu)	$	3.18	$	6.52	$	2.27
AECO ($/MMBtu)	$	2.41	$	5.69	$	1.53
Ameren ($/MWh)	$	32.23	$	93.59	$	18.01
COB ($/MWh)	$	46.83	$	231.90	$	9.15
ComEd ($/MWh)	$	29.60	$	86.32	$	14.98
ERCOT N hub ($/MWh)	$	35.05	$	140.00	$	13.66
ERCOT S hub ($/MWh)	$	34.24	$	140.00	$	13.88
Indiana hub ($/MWh)	$	34.20	$	93.81	$	20.74
Mid C ($/MWh)	$	43.53	$	229.90	$	5.15
Minn hub ($/MWh)	$	28.82	$	90.99	$	15.23
NoIL hub ($/MWh)	$	29.35	$	84.00	$	14.64
PJM W hub ($/MWh)	$	33.49	$	113.93	$	17.78

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

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

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

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

The determination of fair value of the CfDs (see Note 12 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	December 31, 2021
Risk of non-performance	0.39% - 0.51%
Discount rate	0.97% - 1.26%
Forward pricing ($ per KW-month)	$2.00 - $4.80

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Derivative Instruments and Hedging

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

Derivative Instruments and Hedging

Derivative Instruments and Hedging

Our operating and financing activities are exposed to certain risks, which are managed by using derivative instruments. All derivative instruments are recognized as either assets or liabilities at fair value on our 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 December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets:

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

As of December 31, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	3	$	5	$	3	$	3
Derivative liabilities	(3)		(4)		(34)		(78)
	—		1		(31)		(75)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		—
	—		—		(1)		—
Total derivatives before offset of cash collateral	—		1		(32)		(75)
Cash collateral receivable	—		—		18		1
Total derivatives as presented in the balance sheet	$	—	$	1	$	(14)	$	(74)

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021	2020
(Millions)
Wholesale electricity purchase contracts (MWh)	5.7	5.6
Natural gas purchase contracts (Dth)	9.4	9.5
Fleet fuel purchase contracts (Gallons)	2.0	2.5

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 December 31, 2021 and 2020 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2021, 2020 and 2019 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						For the Year Ended December 31,
December 31, 2021	Electricity		Natural Gas		2021	Electricity		Natural Gas
Regulatory assets	$	—	$	—	Purchased power, natural gas and fuel used	$	(23)	$	(11)
Regulatory liabilities	$	(16)	$	(3)
December 31, 2020					2020
Regulatory assets	$	17	$	1	Purchased power, natural gas and fuel used	$	55	$	4
Regulatory liabilities	$	—	$	—
					2019
					Purchased power, natural gas and fuel used	$	25	$	1

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 December 31, 2021, UI has recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $73 million, a gross derivative liability of $75 million ($72 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2020, UI has recorded a gross derivative asset of $2 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $86 million, a gross derivative liability of $88 million ($85 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 years ended December 31, 2021, 2020 and 2019, respectively, were as follows:

	Years Ended December 31,
	2021		2020		2019
(Millions)
Derivative Assets	$	—	$	—	$	(3)
Derivative Liabilities	$	13	$	6	$	8

Certain foreign currency exchange contracts are not designated as hedging instruments. For the years ended December 31, 2021 and 2020, we recorded a gain of $0 and $4 million, respectively, related to our foreign currency contracts not designated as hedging instruments, included in "Other income" in our consolidated statements of income. No amounts were recorded for the year ended December 31, 2019.

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Year Ended December 31,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss (Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2021
Interest rate contracts	$	—	Interest expense	$	4	$	298
Commodity contracts	2		Purchased power, natural gas and fuel used	(1)		1,719
Foreign currency exchange contracts	(5)			—
Total	$	(3)		$	3
2020
Interest rate contracts	$	—	Interest expense	$	4	$	316
Commodity contracts	(1)		Purchased power, natural gas and fuel used	1		1,379
Foreign currency exchange contracts	1			—
Total	$	—		$	5
2019
Interest rate contracts	$	—	Interest expense	$	6	$	310
Commodity contracts	—		Purchased power, natural gas and fuel used	1		1,509
Foreign currency exchange contracts	(1)			—
Total	$	(1)		$	7

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

On June 20, 2019, Networks entered into a forward contract to hedge the foreign currency exchange risk of approximately $100 million in forecasted capital expenditures through June 2023. The forward foreign currency contracts, which were designated and qualified as cash flow hedges, were settled in December 2021. The net loss of $5 million in accumulated OCI on the foreign exchange derivative will be reclassified into earnings over the useful life of the underlying capital expenditures.

The net loss in accumulated OCI related to previously settled forward starting swaps and accumulated amortization is $47 million and $51 million as of December 31, 2021 and 2020, respectively. We recorded $4 million, $4 million and $6 million in net derivative losses related to discontinued cash flow hedges during the years ended December 31, 2021, 2020 and 2019, respectively. We will amortize approximately $4 million of discontinued cash flow hedges in 2022.

Unrealized losses of $1 million on hedge derivatives are reported in OCI because the forecasted transaction is considered to be probable as of December 31, 2021. We expect that immaterial amounts of those losses will be reclassified into earnings within the next twelve months. The maximum length of time over which we are hedging our exposure to the variability in future cash flows for forecasted fleet fuel transactions is twelve months.

(b) Renewables activities

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 December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021	2020
(MWh/Dth in Millions)
Wholesale electricity purchase contracts	4	3
Wholesale electricity sales contracts	10	7
Natural gas and other fuel purchase contracts	20	24
Financial power contracts	9	12
Basis swaps - purchases	30	35
Basis swaps - sales	—	2

The fair values of derivative contracts associated with Renewables' activities as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021		2020
(Millions)
Wholesale electricity purchase contracts	$	36	$	4
Wholesale electricity sales contracts	(77)		11
Natural gas and other fuel purchase contracts	6		—
Financial power contracts	35		66
Basis swaps - purchases	—		7
Total	$	—	$	88

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 22, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of December 31, 2021, the fair value of the interest rate swap was a $58 million non-current liability. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred.

The tables below present Renewables' derivative positions as of December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets:

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

As of December 31, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	47	$	89	$	2	$	9
Derivative liabilities	(23)		(2)		(4)		(11)
	24		87		(2)		(2)
Designated as hedging instruments
Derivative assets	8		15		2		7
Derivative liabilities	(5)		(6)		(3)		(10)
	3		9		(1)		(3)
Total derivatives before offset of cash collateral	27		96		(3)		(5)
Cash collateral (payable) receivable	(9)		(18)		—		—
Total derivatives as presented in the balance sheet	$	18	$	78	$	(3)	$	(5)

Derivatives not designated as hedging instruments

The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Year Ended December 31, 2021
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	1	$	(1)
Wholesale electricity sales contracts	(2)		(33)
Financial power contracts	4		(42)
Financial and natural gas contracts	(1)		(25)
Total loss included in operating revenues	$	2	$	(101)	$	6,974
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	32
Financial and natural gas contracts	—		12
Total gain included in purchased power, natural gas and fuel used	$	—	$	44	$	1,719
Total Gain (Loss)	$	2	$	(57)

	Year Ended December 31, 2020
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	—
Wholesale electricity sales contracts	(1)		6
Financial power contracts	2		—
Financial and natural gas contracts	—		(13)
Total (loss) gain included in operating revenues	$	—	$	(7)	$	6,320
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(4)
Financial and natural gas contracts	—		6
Total gain included in purchased power, natural gas and fuel used	$	—	$	2	$	1,379
Total Loss	$	—	$	(5)

	Year Ended December 31, 2019
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	—
Wholesale electricity sales contracts	3		40
Financial power contracts	(3)		23
Financial and natural gas contracts	(1)		1
Total (loss) gain included in operating revenues	$	(2)	$	64	$	6,336
Purchased power, natural gas and fuel used
Financial power contracts	—		(1)
Financial and natural gas contracts	—		15
Total gain included in purchased power, natural gas and fuel used	$	—	$	14	$	1,509
Total (Loss) Gain	$	(2)	$	78

During September 2019, Renewables liquidated a portion of one of its wholesale electricity sales contracts and recorded a gain of $43 million for the year ended December 31, 2019.

Derivatives designated as hedging instruments

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 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)
2021
Interest rate contracts	$	(58)	Interest Expense	$	—	$	298
Commodity contracts	$	(142)	Operating revenues	$	(3)	$	6,974
Total	$	(200)		$	(3)
2020
Commodity contracts	$	1	Operating revenues	$	6	$	6,320
2019
Commodity contracts	$	(5)	Operating revenues	$	3	$	6,336

(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 $59 million of gain included in accumulated OCI at December 31, 2021 is expected to be reclassified into earnings within the next twelve months. We recorded immaterial amounts of net derivative losses related to discontinued cash flow hedges for the years ended December 31, 2021, 2020 and 2019.

(c) Corporate activities

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.

The net loss in accumulated OCI related to previously settled interest rate contracts is $48 million and $57 million as of December 31, 2021 and 2020, respectively. We amortized into income $9 million, $8 million and $2 million of the loss related to the settled interest rate contracts for the years ended December 31, 2021, 2020 and 2019, respectively. We will amortize approximately $9 million of the net loss on the interest rate contracts during 2022.

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 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)
2021
Interest rate contracts	$	—	Interest expense	$	9	$	298
2020
Interest rate contracts	$	(27)	Interest expense	$	8	$	316
2019
Interest rate contracts	$	(24)	Interest expense	$	2	$	310

(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 year ended December 31, 2021 are as follows:

(millions)	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
As of December 31, 2021				Year Ended December 31, 2021
Current Assets	$	—	Interest Expense	$	(3)	$	298
Non-current liabilities	$	(19)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	19

(d) Counterparty credit risk management

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

The wholesale power supply agreements of UI contain default provisions that include required performance assurance, including certain collateral obligations, in the event that UI’s credit ratings on senior debt were to fall below investment grade. If such an event had occurred as of December 31, 2021, UI would have had to post an aggregate of approximately $19 million in collateral.

We have various master netting arrangements in the form of multiple contracts with various single counterparties that are subject to contractual agreements that provide for the net settlement of all contracts through a single payment. Those arrangements reduce our exposure to a counterparty in the event of a default on or termination of any single contract. For financial statement presentation purposes, we offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement. The amount of cash collateral under master netting arrangements that has not been offset against net derivative positions was $67 million and $18 million as of December 31, 2021 and 2020, respectively. Derivative instruments settlements and collateral payments are included throughout the "Changes in operating assets and liabilities" section of operating activities in the 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 December 31, 2021 is $0, for which we have posted collateral.

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Leases

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Leases

LeasesWe have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 62 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option.

The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Lease cost
Finance lease cost
Amortization of right-of-use assets	$	8	$	17	$	12
Interest on lease liabilities	3		4		3
Total finance lease cost	11		21		15
Operating lease cost	14		16		18
Short-term lease cost	4		3		5
Variable lease cost	4		—		2
Sublease income	—		—		—
Total lease cost	$	33	$	40	$	40

Balance sheet and other information as of December 31, 2021 and 2020 was as follows:

As of December 31,	2021			2020
(Millions, except lease term and discount rate)
Operating Leases
Operating lease right-of-use assets	$	148		$	153
Operating lease liabilities, current	12			8
Operating lease liabilities, long-term	149			154
Total operating lease liabilities	$	161		$	162
Finance Leases
Other assets	$	156		$	162
Other current liabilities	4			8
Other non-current liabilities	91			91
Total finance lease liabilities	$	95		$	99
Weighted-average Remaining Lease Term (years)
Finance leases	7.3			8.12
Operating leases	20.5			21.38
Weighted-average Discount Rate
Finance leases	3.49		%	3.71		%
Operating leases	3.06		%	3.21		%

For the years ended December 31, 2021, 2020 and 2019 supplemental cash flow information related to leases was as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	16	$	13	$	13
Operating cash flows from finance leases	$	3	$	3	$	3
Financing cash flows from finance leases	$	6	$	9	$	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	$	—	$	46	$	1
Operating leases	$	10	$	94	$	3

As of December 31, 2021, maturities of lease liabilities were as follows:

	Finance Leases		Operating Leases
(Millions)
Year ending December 31,
2022	$	5	$	14
2023	53		14
2024	23		12
2025	2		11
2026	2		11
Thereafter	19		160
Total lease payments	104		223
Less: imputed interest	(9)		(62)
Total	$	95	161

Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $45 million and $47 million at December 31, 2021 and December 31, 2020, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility.

Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.

Leases

LeasesWe have operating leases for office buildings, facilities, vehicles and certain equipment. Our finance leases are primarily related to electric generation and certain buildings, vehicles and equipment. Certain of our lease agreements include rental payments adjusted periodically for inflation or are based on other periodic input measures. Our leases do not contain any material residual value guarantees or material restrictive covenants. Our leases have remaining lease terms of 1 year to 62 years, some of which may include options to extend the leases for up to 40 years, and some of which may include options to terminate. We consider extension or termination options in the lease term if it is reasonably certain we will exercise the option.

The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Lease cost
Finance lease cost
Amortization of right-of-use assets	$	8	$	17	$	12
Interest on lease liabilities	3		4		3
Total finance lease cost	11		21		15
Operating lease cost	14		16		18
Short-term lease cost	4		3		5
Variable lease cost	4		—		2
Sublease income	—		—		—
Total lease cost	$	33	$	40	$	40

Balance sheet and other information as of December 31, 2021 and 2020 was as follows:

As of December 31,	2021			2020
(Millions, except lease term and discount rate)
Operating Leases
Operating lease right-of-use assets	$	148		$	153
Operating lease liabilities, current	12			8
Operating lease liabilities, long-term	149			154
Total operating lease liabilities	$	161		$	162
Finance Leases
Other assets	$	156		$	162
Other current liabilities	4			8
Other non-current liabilities	91			91
Total finance lease liabilities	$	95		$	99
Weighted-average Remaining Lease Term (years)
Finance leases	7.3			8.12
Operating leases	20.5			21.38
Weighted-average Discount Rate
Finance leases	3.49		%	3.71		%
Operating leases	3.06		%	3.21		%

For the years ended December 31, 2021, 2020 and 2019 supplemental cash flow information related to leases was as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	16	$	13	$	13
Operating cash flows from finance leases	$	3	$	3	$	3
Financing cash flows from finance leases	$	6	$	9	$	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	$	—	$	46	$	1
Operating leases	$	10	$	94	$	3

As of December 31, 2021, maturities of lease liabilities were as follows:

	Finance Leases		Operating Leases
(Millions)
Year ending December 31,
2022	$	5	$	14
2023	53		14
2024	23		12
2025	2		11
2026	2		11
Thereafter	19		160
Total lease payments	104		223
Less: imputed interest	(9)		(62)
Total	$	95	161

Renewables has a sale-leaseback arrangement (as a seller-lessee) on a solar generation facility. The finance lease liability outstanding (including the current portion thereof) was $45 million and $47 million at December 31, 2021 and December 31, 2020, respectively. In 2013, Renewables sold the generation facility to a consortium of buyers (referred to as “Trusts”) and simultaneously entered into an agreement with the Trusts for the right to use the facility for up to 15 years with an early buyout option in year 10. The gain on the sale of the generation facility was deferred and is being amortized to depreciation expense over the 25-year life of the facility.

Most of our leases do not provide an implicit rate in the lease; thus we use our incremental borrowing rate based on the information available at the commencement date in determining the present value of lease payments.

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Commitments and Contingent Liabilities

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Commitments and Contingent Liabilities

Commitments and Contingent Liabilities

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 $27 million and $8 million, respectively, as of December 31, 2021, which has not changed since December 31, 2020, 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 of this decision, which was granted. On May 21, 2020, FERC issued a ruling, which, among other things, adjusted the methodology to determine the MISO transmission owners’ ROE, resulting in an increase in ROE from 9.88% to 10.02% by utilizing the risk premium model in addition to the DCF model and capital-asset pricing model under both prongs of Section 206 of the FPA, and calculated the zone of reasonableness into equal thirds rather than employing the quartile approach. On November 19, 2020, FERC issued an order addressing arguments raised on rehearing of its May 21, 2020 order, making minor adjustments to certain typographical errors with regard to some of the case inputs it included in its Risk Premium model analysis. However, those minor adjustments did not affect the outcome of the case, leaving the 10.02% ROE established by the May 21, 2020 order in place. Parties to these orders affecting the MISO transmission owners’ base ROE petitioned for their review at the D.C. Circuit Court of Appeals in January 2021. The NETO’s submitted an amici curia brief in support of the MISO transmission owners’ on March 17, 2021. We cannot predict the outcome of these proceedings, including the potential impact the MISO transmission owners' ROE proceeding may have in establishing a precedent for our pending four Complaints.

On April 15, 2021, the FERC issued a supplemental Notice of Proposed Rulemaking (Supplemental NOPR) that proposes to eliminate the 50 basis-point ROE incentive for utilities who join Regional Transmission Organizations after 3 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 PPA entered into by Renewables, as seller, to the California Department of Water Resources, as purchaser, alleging that the terms and conditions of the PPA 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 PPAs unjust and

unreasonable. However, the proposed ruling did conclude that the price of the PPAs imposed an excessive burden on customers in the amount of $259 million. Renewables position, as presented at hearings and agreed by the FERC trial staff, is that Renewables entered into bilateral power purchase contracts appropriately and complied with all applicable legal standards and requirements. The parties have submitted briefs on exceptions to the administrative law judge’s proposed ruling to the FERC. In April 2018, Renewables requested, based on the nearly two years of delay from the preliminary proposed ruling and the Supreme Court precedent, that the FERC issue a final decision expeditiously. On June 17, 2021, the FERC issued an Order Establishing Limited Remand remanding the case to the administrative law judge for additional detailed findings and legal analysis with respect to the impact of the conduct of one of the parties other than Renewables on their long-term contracts. The order did not address any of the other findings, including all of the findings with respect to Renewables, which remain pending. There is no specific timetable for the administrative law judge’s ruling. On July 9, 2021, Renewables filed a motion requesting that the FERC expeditiously issue a final decision with respect to the Renewables long-term contract rather than waiting for the administrative law judge’s ruling. We cannot predict the outcome of this proceeding.

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

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

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

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

On January 8, 2021, the Beatrice Corwin Living Irrevocable Trust, by and through its Authorized Trustee, Robert Corwin filed a complaint in the Supreme Court of the State of New York Westchester County against Iberdrola and the members of the Company’s Board of Directors, as defendants, and the Company, as a nominal defendant with respect to certain counts contained in the complaint. The complaint alleges certain violations of fiduciary duties by Iberdrola and the members of the Company’s Board of Directors related to the existence of certain pre-emptive rights provided to Iberdrola in the Shareholder Agreement between the Company and Iberdrola, dated December 16, 2015, and the binding nature of such rights. On March 29, 2021, the parties stipulated to and requested, and the Supreme Court of the State of New York Westchester County issued an Order providing for, the transfer of the venue of the complaint to the Supreme Court, County of New York. On May 20, 2021, the matter was transferred to New York County and assigned to the Commercial Division of the Supreme Court, County of New York. On September 3, 2021, the plaintiffs filed an amended verified complaint (i) dropping claims concerning the purported breach of AVANGRID’s articles of incorporation and New York’s statute concerning equal treatment among shareholders, (ii) adding and modifying their claims related to the duty of good faith and loyalty and (iii) adding allegations concerning the Iberdrola Loan and the May 2021 private placement of our common shares to Iberdrola and Hyde Partners, LLC. In addition, the plaintiffs are now purporting to bring a class action lawsuit. On October 22, 2021, we and our board of directors filed a motion to dismiss and Iberdrola filed a motion to dismiss and an application to stay discovery pending resolution of dispositive motions. On December 8, 2021, the plaintiffs filed an omnibus opposition to the motions to dismiss and the defendants' filed a reply to such motion on January 14, 2022. Oral arguments are scheduled March 17, 2022. We cannot predict the outcome of this matter.

Power, Gas and Other Arrangements

Power and Gas Supply Arrangements – Networks

NYSEG and RG&E are the providers of last resort for customers. As a result, the companies buy physical energy and capacity from the NYISO. In accordance with the NYPSC's February 26, 2008 Order, NYSEG and RG&E are required to hedge on behalf of non-demand billed customers. The physical electric capacity purchases we make from parties other than the NYISO are to comply with the hedge requirement for electric capacity. The companies enter into financial swaps to comply with the hedge requirement for physical electric energy purchases. Other purchases, from some Independent Power Producers (IPPs) and the New York Power Authority, are from contracts entered into many years ago when the companies made purchases under contract as part of their supply portfolio to meet their load requirement. More recent IPP purchases are required to comply with the companies’ Public Utility Regulatory Policies Act (PURPA) purchase obligation.

NYSEG, RG&E, SCG, CNG and BGC (collectively, the Regulated Gas Companies) satisfy their natural gas supply requirements through purchases from various producers and suppliers, withdrawals from natural gas storage, capacity contracts and winter peaking supplies and resources. The Regulated Gas Companies operate diverse portfolios of gas supply, firm transportation capacity, gas storage and peaking resources. Actual gas costs incurred by each of the Regulated Gas Companies are passed through to customers through state regulated purchased gas adjustment mechanisms, subject to regulatory review.

The Regulated Gas Companies purchase the majority of their natural gas supply at market prices under seasonal, monthly or mid-term supply contracts and the remainder is acquired on the spot market. The Regulated Gas Companies diversify their sources of supply by amount purchased and location and primarily acquire gas at various locations in the U.S. Gulf of Mexico region, in the Appalachia region and in Canada.

The Regulated Gas Companies acquire firm transportation capacity on interstate pipelines under long-term contracts and utilize that capacity to transport both natural gas supply purchased and natural gas withdrawn from storage to the local distribution system.

The Regulated Gas Companies acquire firm underground natural gas storage capacity using long-term contracts and fill the storage facilities with gas in the summer months for subsequent withdrawal in the winter months.

Winter peaking resources are primarily attached to the local distribution systems and are either owned or are contracted for by the Regulated Gas Companies, each of which is a Local Distribution Company. Each Regulated Gas Company owns or has rights to the natural gas stored in an LNG facility directly attached to its distribution system.

Other arrangements include contractual obligations for property, plant and equipment, material and services on order but not yet delivered at December 31, 2021.

Power, Gas and Other Arrangements – Renewables

Gas purchase commitments consist of firm transport capacity to fuel the Klamath Cogen and Peaking gas generators. Power purchase commitments include the following: (i) long-term firm transmission agreements with fixed monthly capacity payments that allow the delivery of electricity from wind and thermal generation sources to various customers (ii) a 95.6 MW (average) three-year purchase of hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2022 and expiring in 2024) and (iii) a five-year purchase of 52 MW (average) hydro capacity and energy to provide balancing services to the NW wind assets that has monthly fixed payments (beginning in 2019 and expiring in 2023). Power sales commitments include: (i) winter capacity sale of 150 MW through 2042, (ii) fixed price, fixed volume hydro energy sales through 2024, (iii) fixed price, fixed volume power sales off the Klamath Cogen facility, (iv) a seasonal tolling arrangement off the Klamath peaking facility with fixed capacity charges through 2024; (v) fixed price, fixed volume renewable energy credit sales off merchant wind facilities, (vi) sales of merchant wind farm capacity to various ISOs and (vii) sales of ancillary services (e.g., regulation and frequency response, generator imbalance, etc.) to third parties from Renewables’ Balancing Authority.

In June 2020, Renewables entered into a Payment In Lieu of Taxes (PILOT) agreement related to two of its projects with Torrance County, New Mexico. The agreement requires PILOT payments to Torrance County through 2049. The total amount of PILOT payments related to the two projects in 2021 was $1 million.

Renewables also has easement contracts which are included in the table below.

Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2021 consisted of:

Year	Purchases		Sales
	(Millions)
2022	$	1,069	$	227
2023	168		122
2024	111		75
2025	65		28
2026	49		37
Thereafter	971		72
Totals	$	2,433	$	561

Guarantee Commitments to Third Parties

As of December 31, 2021, we had approximately $483 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding, including approximately $21 million related to Vineyard Wind. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind as described in Note 22, 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 December 31, 2021, neither we nor our subsidiaries have any liabilities recorded for these instruments.

NECEC Commitments

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. 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 during 2021.

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Environmental Liabilities

12 Months Ended

Dec. 31, 2021

Environmental Remediation Obligations [Abstract]

Environmental Liabilities

Environmental Liabilities

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

Waste sites

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

We have recorded an estimated liability of $7 million related to eleven of the twenty-six sites. We have paid remediation costs related to the remaining fifteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $9 million related to another twelve sites where we believe it is probable that we will incur remediation and/or monitoring costs, although we have not been notified that we are among the potentially responsible parties or that we are regulated under State Resource Conservation and Recovery Act programs. It is possible the ultimate cost to remediate these sites may be significantly more than the accrued amount. As of December 31, 2021, our estimate for costs to remediate these sites ranges from $14 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the allocation of the clean-up costs.

Manufactured Gas Plants

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

not included in any registry list. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.

As of December 31, 2021, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $162 million to $276 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 December 31, 2021, 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 December 31, 2021 and 2020, the liability associated with our MGP sites in Connecticut was $113 million and $96 million, respectively, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates.

As of December 31, 2021 and 2020, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $303 million and $300 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 2082.

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 December 31, 2021, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $14 million and $7 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable.

English Station

In January 2012, Evergreen Power, LLC (Evergreen Power) and Asnat Realty LLC (Asnat), then owners of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000, filed a lawsuit in federal district court in Connecticut related to environmental remediation at the English Station site. This proceeding was stayed in 2014 pending resolutions of other proceedings before the DEEP concerning the English Station site. In December 2016, the court administratively closed the file without prejudice to reopen upon the filing of a motion to reopen by any party.

In December 2013, Evergreen Power and Asnat filed a subsequent lawsuit related to the English Station site. On April 16, 2018, the plaintiffs filed a revised complaint alleging fraud and unjust enrichment against UIL and UI and adding former UIL officers as named defendants alleging fraud. On February 21, 2019, the court granted our Motion to Strike with respect to all counts except for the count against UI for unjust enrichment. The counts stricken include all counts against the individual defendants as well as against UIL. The plaintiffs have appealed the court's decision to strike and oral arguments have taken place. On May 4, 2021, the Appeals Court affirmed the court's decision striking the counts. The plaintiffs filed a petition to appeal to the Connecticut Supreme Court, which was denied, leaving only the claim against UI for unjust enrichment. We cannot predict the outcome of this matter.

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

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

As of both December 31, 2021 and 2020, the amount reserved related to English Station was $22 million. Since inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of this matter.

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Income Taxes

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Income Taxes

Income Taxes

The Taxpayer Certainty and Disaster Tax Relief Act of 2019 (Division Q of the Further Consolidated Appropriations Act of 2020) was signed into law in 2019 that extended the PTC and ITC options for wind facilities to 60% of the full credit for facilities commencing construction in 2020, leaving in place phased down credits for projects commencing in years prior to 2020.

The Consolidated Appropriations Act, 2021, signed into law on December 27, 2020 provides extensions to renewable income tax incentives. Onshore and offshore wind projects may now claim a 60% PTC for projects commencing construction in 2020 and 2021. In addition, offshore wind may now elect to claim a 30% ITC for projects commencing construction through 2025. Onshore wind can claim an 18% ITC for projects commencing construction in 2020 or 2021, with no ITC thereafter.

Solar projects commencing construction before 2020 may claim a 30% ITC. Solar projects that commence construction from 2020-2022 may claim a 26% ITC, projects commencing construction in 2023 may claim a 22% ITC and projects commencing thereafter may claim a 10% ITC. The ITC statutes require solar projects be completed by the end of 2025 in order to claim the applicable ITCs except for projects under the 10% credit.

The Internal Revenue Service (IRS) previously provided continuity safe harbor guidance that requires renewable projects to be completed within four years of the year construction commences. Any projects that do not meet this requirement will fall outside of the safe harbor and be subject to IRS scrutiny with regard to the date construction commenced. In 2021, the IRS provided new guidance for an extension to a period of 6 years for the Continuity Safe Harbor for projects for which construction began in 2016 through 2019 and 5 years for the Continuity Safe Harbor for projects in which construction begin in 2020. Most importantly, this new guidance for the continuity requirement is satisfied if the taxpayer demonstrates satisfaction of either the Continuous Construction or the Continuous Efforts Tests, regardless of the method that the taxpayer used to begin construction. In late December 2020, the IRS issued a notice giving onshore wind projects on federal lands, with transmission permit requirements, and offshore wind projects 10 years to complete construction.

Since early 2020, and in response to regulatory orders received in most but not all of our operating jurisdictions, we began returning to customers both protected and unprotected excess accumulated deferred income tax (ADIT) from the 2017 Tax Act. Such amounts are subject to the terms of those orders while meeting the requirements of normalization for both ARAM and RSG methodologies.

Current and deferred taxes charged to expense for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 31,	2021		2020		2019
(Millions)
Current
Federal	$	6	$	3	$	11
State	4		9		(6)
Current taxes charged to expense	10		12		5
Deferred
Federal	49		67		164
State	72		38		58
Deferred taxes charged to expense	121		105		222
Production tax credits	(109)		(87)		(57)
Investment tax credits	(1)		(1)		(1)
Total Income Tax Expense	$	21	$	29	$	169

The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 31,	2021		2020		2019
(Millions)
Tax expense at federal statutory rate	$	140	$	119	$	170
Depreciation and amortization not normalized	(19)		(13)		(23)
Investment tax credit amortization	(1)		(1)		(1)
Tax return related adjustments	—		1		(2)
Production tax credits	(109)		(87)		(57)
Tax equity financing arrangements	14		1		8
State tax expense (benefit), net of federal benefit	61		37		41
Excess ADIT amortization	(65)		(42)		—
Valuation allowance	21		12		4
Other, net	(21)		2		29
Total Income Tax Expense	$	21	$	29	$	169

Deferred tax assets and liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Deferred Income Tax Liabilities (Assets)
Property related	$	4,257	$	4,147
Unfunded future income taxes	104		100
Federal and state tax credits	(844)		(731)
Federal and state NOL’s	(998)		(1,047)
Joint ventures/partnerships	188		167
Nontaxable grant revenue	(292)		(311)
Pension and other post-retirement benefits	1		22
Tax Act - tax on regulatory remeasurement	(352)		(382)
Valuation allowance	110		81
Other	(158)		(127)
Deferred Income Tax Liabilities	$	2,016	$	1,919
Deferred tax assets	$	2,644	$	2,598
Deferred tax liabilities	4,660		4,517
Net Accumulated Deferred Income Tax Liabilities	$	2,016	$	1,919

As of December 31, 2021, we had gross federal tax net operating losses of $3.6 billion, federal PTCs and ITCs, federal R&D tax credits and other federal credits of $805 million, state tax effected net operating losses of $314 million in several jurisdictions and miscellaneous state tax credits of $146 million available to carry forward and reduce future income tax liabilities. For federal purposes, we recognized a valuation allowance of $37 million, and for state purposes, we recognized a valuation allowance of $73 million. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2023. The more significant state net operating losses begin to expire in 2024.

Valuation allowances are recorded to reduce deferred tax assets when it is more likely than not that all or a portion of a tax benefit will not be realized. The valuation allowance for deferred tax assets as of December 31, 2021 and 2020 was $110 million and $81 million, respectively. Valuation allowances have been established on various federal tax credits, state net operating losses and state tax credit carryforwards. The Company has recorded a federal valuation allowance on its federal tax credit carryforwards of $37 million and has recorded a state valuation allowance on its state net operating losses and state tax credit carryforwards of $73 million. The $29 million increase in valuation allowance from 2020 to 2021 includes an increase of $21 million for additional valuation allowance on Federal tax credit carryforwards and an increase of $8 million on state net operating losses and state tax credits.

The reconciliation of unrecognized income tax benefits for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years ended December 31,	2021		2020		2019
(Millions)
Beginning Balance	$	127	$	148	$	153
Increases for tax positions related to prior years	3		11		14
Increases for tax positions related to current year	—		—		16
Decreases for tax positions related to prior years	(3)		(32)		(18)
Reduction for tax position related to settlements with taxing authorities	—		—		(17)
Ending Balance	$	127	$	127	$	148

Unrecognized income tax benefits represent income tax positions taken on income tax returns but not yet recognized in the consolidated financial statements. The accounting guidance for uncertainty in income taxes provides that the financial effects of a tax position shall initially be recognized when it is more likely than not based on the technical merits the position will be sustained upon examination, assuming the position will be audited and the taxing authority has full knowledge of all relevant information.

Accruals for interest and penalties on tax reserves were immaterial for the years ended December 31, 2021, 2020 and 2019. If recognized, $107 million of the total gross unrecognized tax benefits would affect the effective tax rate.

As of December 31, 2021, unrecognized tax benefits are primarily attributed to state tax matters in New York, in which a decrease could occur upon settlement of an outstanding audit during 2022.

AVANGRID and its subsidiaries, without ARHI, have been audited for the federal tax years 1998 through 2009. The results of these audits, net of reserves already provided, were immaterial. Tax years 2010 and forward are open for potential federal adjustments. All New York state returns, which were filed without ARHI, are closed through 2011 and Maine state returns are closed through 2015.

All federal tax returns filed by ARHI from the periods ended March 31, 2004, to December 31, 2009, are closed for adjustment. All New York combined state returns are closed for adjustment through 2011. Generally, the adjustment period for the individual states we filed in is at least as long as the federal period.

As of December 31, 2021, UIL is subject to audit of its federal tax return for years 2014 through its short period 2015. UIL's short period ending in 2015 is open and subject to Connecticut audit.

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Post-retirement and Similar Obligations

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

Post-retirement and Similar Obligations

Post-retirement and Similar Obligations

AVANGRID and its subsidiaries sponsor a number of retirement benefit plans. The plans include qualified defined benefit pension plans, supplemental non-qualified pension plans, defined contribution plans and other postretirement benefit plans for eligible employees and retirees. Eligibility and benefits vary depending on each plan's design. For example, certain benefits are based on years of service and final average compensation while others may use a cash balance formula that calculates benefits using a percentage of annual compensation.

Qualified Retirement Benefit Plans

As of December 31, 2021 and 2020, our obligations and funded status consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
(Millions)
Change in benefit obligation
Benefit Obligation as of January 1,	$	3,819	$	3,669	$	452	$	439
Service cost	40		47		3		3
Interest cost	87		107		10		13
Plan amendments	2		7		—		—
Actuarial loss (gain)	(184)		236		(23)		29
Curtailments	(38)		(21)		—		—
Benefits paid	(239)		(226)		(34)		(32)
Benefit Obligation as of December 31,	3,487		3,819		408		452
Change in plan assets
Fair Value of Plan Assets as of January 1,	3,092		2,848		167		155
Actual return on plan assets	237		388		15		26
Employer contributions	27		84		12		18
Curtailments	(38)		(2)		—		—
Benefits paid	(239)		(226)		(67)		(32)
Fair Value of Plan Assets as of December 31,	3,079		3,092		127		167
Funded Status as of December 31,	$	(408)	$	(727)	$	(281)	$	(285)

During 2021, the pension benefit obligation had an actuarial gain of $184 million, primarily due to a $205 million gain from increases in discount rates. There were no significant gains or losses relating to the postretirement benefit obligations.

During 2020, the pension benefit obligation had an actuarial loss of $236 million, primarily due to a $276 million loss from decreases in discount rates. The only significant plan change in 2020 was an agreement to freeze the UI union pension plan. There were no significant gains or losses relating to the postretirement benefit obligations.

As of December 31, 2021 and 2020, funded status amounts recognized on our consolidated balance sheets consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
(Millions)
Current liabilities	$	—	$	—	$	(5)	$	(5)
Non-current liabilities	(408)		(727)		(276)		(280)
Total	$	(408)	$	(727)	$	(281)	$	(285)

We have determined that Networks’ regulated operating companies are allowed to defer as regulatory assets or regulatory liabilities items that would have otherwise been recorded in accumulated OCI pursuant to the accounting requirements concerning defined benefit pension and other postretirement plans.

Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2021 and 2020 consisted of:

	Pension Benefits				Postretirement Benefits
Years Ended December 31,	2021		2020		2021		2020
(Millions)
Net loss (gain)	$	271	$	610	$	(18)	$	14
Prior service cost (credit)	$	10	$	10	$	(1)	$	(8)

Amounts recognized in OCI for ARHI for the years ended December 31, 2021 and 2020, consisted of:

	Pension Benefits				Postretirement Benefits
Years Ended December 31,	2021		2020		2021		2020
(Millions)
Net loss (gain)	$	16	$	21	$	(5)	$	(7)

As of December 31, 2021 and 2020, the projected benefit obligation (PBO) exceeded the fair value of pension plan assets for all qualified plans. The accumulated benefit obligation (ABO) exceeded the fair value of pension plan assets for all but one plan, as of December 31, 2021, and for all of our qualified plans, as of December 31, 2020. The aggregate PBO and ABO and the fair value of plan assets for our underfunded qualified plans consisted of: 

	PBO in excess of plan assets
As of December 31,	2021		2020
(Millions)
Projected benefit obligation	$	3,487	$	3,819
Fair value of plan assets	$	3,079	$	3,092
	ABO in excess of plan assets
As of December 31,	2021		2020
(Millions)
Accumulated benefit obligation	$	1,790	$	3,629
Fair value of plan assets	$	1,536	$	3,092

As of December 31, 2021 and 2020, the accumulated postretirement benefits obligation for all qualified plans exceeded the fair value of plan assets.

Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
For the years ended December 31,	2021		2020		2019		2021		2020		2019
(Millions)
Net Periodic Benefit Cost:
Service cost	$	39	$	46	$	41	$	3	$	3	$	3
Interest cost	86		106		128		10		13		16
Expected return on plan assets	(199)		(198)		(190)		(7)		(8)		(7)
Amortization of prior service cost (benefit)	2		1		(1)		(5)		(9)		(10)
Amortization of net loss	115		124		113		2		2		1
Settlement charge	6						—
Net Periodic Benefit Cost	49		79		91		3		1		3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	—		(18)		—		—		—		—
Settlement charge	(6)		—		—		—		—		—
Net loss (gain)	(218)		46		80		(31)		11		13
Amortization of net loss	(115)		(124)		(113)		(2)		(2)		(1)
Current year prior service cost (credit)	2		7		(2)		1		—		—
Amortization of prior service (cost) benefit	(2)		(1)		1		5		9		10
Total Other Changes	(339)		(90)		(34)		(27)		18		22
Total Recognized	$	(290)	$	(11)	$	57	$	(24)	$	19	$	25

Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
For the years ended December 31,	2021		2020		2019		2021		2020		2019
(Millions)
Net Periodic Benefit Cost:
Service cost	$	1	$	1	$	1	$	—	$	—	$	—
Interest cost	1		1		2		—		—		—
Expected return on plan assets	(2)		(2)		(2)		—		—		—
Amortization of net loss (gain)	2		2		1		(1)		(1)		(1)
Settlement charge	1		1		—		—		—		—
Net Periodic Benefit Cost	3		3		2		(1)		(1)		(1)
Other Changes in plan assets and benefit obligations recognized in OCI:
Settlement charge	(1)		—		—		(1)		—		—
Net loss (gain)	(3)		1		—		1		—		—
Amortization of net (loss) gain	(2)		(2)		(1)		1		1		1
Amortization of prior service cost	—		—		—		—		—		(2)
Total Other Changes	(6)		(1)		(1)		1		1		(1)
Total Recognized	$	(3)	$	2	$	1	$	—	$	—	$	(2)

The net periodic benefit cost for postretirement benefits represents the amount expensed for providing health care benefits to retirees and their eligible dependents. We include the service cost component in other operating expenses net of capitalized portion and include the components of net periodic benefit cost other than the service cost component in other expense. 

The weighted-average assumptions used to determine our benefit obligations as of December 31, 2021 and 2020 consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
Discount rate	2.85	%	2.34	%	2.66	%	2.19	%
Rate of compensation increase	3.53	%	3.52	%	3.50	%	3.50	%
Interest crediting rate	2.87	%	2.87	%	N/A		N/A

The discount rate is the rate at which the benefit obligations could presently be effectively settled. We determined the discount rates by developing yield curves derived from a portfolio of high grade noncallable bonds with yields that closely match the duration of the expected cash flows of our benefit obligations.

The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
Years Ended December 31,	2021		2020		2019		2021		2020		2019
Discount rate	2.34	%	3.01	%	3.98	%	2.19	%	2.99	%	3.97	%
Expected long-term return on plan assets	7.30	%	7.30	%	7.30	%	4.05	%	5.09	%	5.08	%
Rate of compensation increase	3.52	%	3.66	%	3.79	%	3.50	%	3.48	%	3.50	%

We developed our expected long-term rate of return on plan assets assumption based on a review of long-term historical returns for the major asset classes, the target asset allocations, and the effect of rebalancing of plan assets discussed below. Our analysis considered current capital market conditions and projected conditions. NYSEG, RG&E and UIL amortize unrecognized actuarial gains and losses over ten years from the time they are incurred as required by the NYPSC, PURA and DPU. Our other companies use the standard amortization methodology under which amounts in excess of ten-percent of the greater of the projected benefit obligation or market related value are amortized over the plan participants’ average remaining service to retirement.

Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
Health care cost trend rate assumed for next year	5.00%/7.00%		5.25%/7.25%
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2029 / 2025		2029 / 2025

Contributions

We make annual contributions in accordance with our funding policy of not less than the minimum amounts as required by applicable regulations. We expect to contribute $22 million and $11 million, respectively, to our pension and other postretirement benefit plans during 2022.

Estimated Future Benefit Payments

Expected benefit payments as of December 31, 2021 consisted of:

(Millions)	Pension Benefits		Postretirement Benefits
2022	$	217	$	30
2023	$	212	$	29
2024	$	214	$	29
2025	$	213	$	28
2026	$	215	$	27
2027 - 2031	$	1,057	$	122

Non-Qualified Retirement Benefit Plans

We also sponsor various unfunded pension plans for certain current employees, former employees and former directors. The total liability for these plans, which is included in Other current and Other non-current liabilities on our consolidated balance sheets, was $63 million and $59 million at December 31, 2021 and 2020, respectively.

Plan Assets

Our pension plan assets are consolidated in one master trust. A consolidated master trust provides for a uniform investment manager lineup and an efficient, cost effective means of allocating income and expenses to each plan. Our primary investment objective is to have a diversified asset allocation policy that mitigates risk and volatility while meeting or exceeding our projected expected return to ensure that current and future benefit obligations are adequately funded. Further diversification and risk mitigation is achieved within each asset class by avoiding significant concentrations in certain markets, utilizing a combination or passive and active investment managers with unique skill and expertise, a systematic allocation to various asset classes and providing broad exposure to different segments of the equity, fixed income and alternative investment markets.

Networks and ARHI have established target asset allocation policies with allowable ranges for their pension plan assets within broad categories of asset classes made up of Return-Seeking investments and Liability-Hedging/Fixed Income investments. In 2020, a streamlined investment policy was implemented, which aligned Networks target allocations to the estimated funded status of each specific plan. Return-Seeking assets range from 25%-60% and Liability-Hedging assets range from 40%-75%. Return-Seeking assets include investments in domestic, international and emerging equity real estate, global asset allocation strategies and hedge funds. Liability-Hedging investments generally consist of long-term corporate bonds, annuity contracts, long-term treasury STRIPS and opportunistic fixed income investments. Systematic rebalancing within the target ranges increases the probability that the annualized return on the investments will be enhanced, while realizing lower overall risk, should any asset categories drift outside their specified ranges.

The fair values of pension plan assets, by asset category, as of December 31, 2021, consisted of:

As of December 31, 2021			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	69	$	20	$	49	$	—
U.S. government securities	298		298		—		—
Common stocks	138		138		—		—
Registered investment companies	276		276		—		—
Corporate bonds	837		—		837		—
Preferred stocks	1		1		—		—
Common collective trusts	862		—		862		—
Other, principally annuity, fixed income	51		—		51		—
	$	2,532	$	733	$	1,799	$	—
Other investments measured at net asset value	547
Total	$	3,079

The fair values of pension plan assets, by asset category, as of December 31, 2020, consisted of:

As of December 31, 2020			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	120	$	—	$	120	$	—
U.S. government securities	177		177		—		—
Common stocks	107		107		—		—
Registered investment companies	301		301		—		—
Corporate bonds	710		—		710		—
Preferred stocks	1		1		—		—
Common collective trusts	1,018		—		1,018		—
Other, principally annuity, fixed income	50		6		44		—
	$	2,484	$	592	$	1,892	$	—
Other investments measured at net asset value	608
Total	$	3,092

Valuation Techniques

We value our pension plan assets as follows:

•Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings.

•U.S. government securities – at the closing price reported in the active market in which the security is traded.

•Common stocks – at the closing price reported in the active market in which the individual investment is traded.

•Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Preferred stocks – at the closing price reported in the active market in which the individual investment is traded.

•Common collective trusts/Registered investment companies – Level 1: at the closing price reported in the active market in which the individual investment is traded. Level 2: the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

•Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient.

Our postretirement plan assets are consolidated with one trustee in multiple voluntary employees’ beneficiary association (VEBA) and 401(h) arrangements. The assets are invested in various asset classes to achieve sufficient diversification and mitigate risk. This is achieved for our VEBA assets by utilizing multiple institutional mutual and money market funds, which provide exposure to different segments of the securities markets. The 401(h) assets are invested alongside the Pension assets they are tied to and share the same asset allocation policy. Approximately 54% of the postretirement benefits plan assets are invested in VEBA and 401(h) arrangements that are not subject to income taxes with the remainder being invested in arrangements subject to income taxes.

In 2020, a streamlined investment policy was implemented for Networks and ARHI that aligned target allocations. Equities range from 49%-69% and Fixed Income assets range from 31-51%. Equity investments are diversified across U.S. and non-U.S. stocks, investment styles, and market capitalization ranges. Fixed Income investments are primarily invested in U.S. bonds and may also include some non-U.S. bonds. We primarily minimize the risk of large losses through diversification, but also through monitoring and managing other aspects of risk through quarterly investment portfolio reviews. Systematic rebalancing within target ranges increases the probability of increasing the projected expected return, while mitigating risk, should any asset categories drift outside their specified ranges.

The fair values of other postretirement plan assets, by asset category, as of December 31, 2021 consisted of:

As of December 31, 2021			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	5	$	—	$	5	$	—
U.S. government securities	1		1		—		—
Common stocks	1		1		—		—
Registered investment companies	101		101		—		—
Corporate bonds	3		—		3		—
Preferred stocks	—		—		—		—
Common collective trusts	5		—		5		—
Other, principally annuity, fixed income	9		—		9		—
	$	125	$	103	$	22	$	—
Other investments measured at net asset value	2
Total	$	127

The fair values of other postretirement plan assets, by asset category, as of December 31, 2020 consisted of:

As of December 31, 2020			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	6	$	—	$	6	$	—
U.S. government securities	1		1		—		—
Registered investment companies	141		141		—		—
Corporate bonds	3		—		3		—
Common collective trusts	4		—		4		—
Other, principally annuity, fixed income	9		—		9		—
	$	164	$	142	$	22	$	—
Other investments measured at net asset value	3
Total	$	167

Valuation Techniques

We value our postretirement plan assets as follows:

•Cash and cash equivalents – Level 1: at cost, plus accrued interest, which approximates fair value. Level 2: proprietary cash associated with other investments, based on yields currently available on comparable securities of issuers with similar credit ratings.

•U.S. government securities – at the closing price reported in the active market in which the security is traded.

•Common stocks and registered investment companies – at the closing price reported in the active market in which the individual investment is traded.

•Corporate bonds – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Common collective trusts – the fair value is primarily derived from the quoted prices in active markets of the underlying securities. Because the fund shares are offered to a limited group of investors, they are not considered to be traded in an active market.

•Other investments, principally annuity and fixed income – based on yields currently available on comparable securities of issuers with similar credit ratings.

•Other investments measured at net asset value (NAV) – fund shares offered to a limited group of investors and alternative investments, such as private equity and real estate oriented investments, partnership/joint ventures and hedge funds are valued using the NAV as a practical expedient.

Pension and postretirement benefit plan equity securities did not include any Iberdrola common stock as of both December 31, 2021 and 2020.

Defined contribution plans

We also have defined contribution plans defined as 401(k)s for all eligible AVANGRID employees. There are various match formulas depending on years of service, age and pension plan closure/freeze date. For the years ended December 31, 2021, 2020 and 2019, the annual contributions we made to these plans was $58 million, $49 million and $40 million, respectively.

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Equity

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Equity

Equity

As of December 31, 2021 and 2020, we had 112,543 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2021 and 2020, we issued 77,883,713 and 42,777 shares of common stock, respectively, and released 301,239 and 72,028 shares of common stock held in trust, respectively, each having a par value of $0.01. See Note 1 for information on our May 2021 equity issuance.

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 target relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2021, 694,148 shares were repurchased pursuant to the stock repurchase program primarily as an advanced re-purchase to hedge a portion of the anticipated payouts under AVANGRID stock based compensation plans. As of December 31, 2021, a total of 997,983 shares have been repurchased in the open market,

all of which are included as AVANGRID treasury shares. As of December 31, 2021, the total cost of all repurchases, including commissions, was $47 million.

Accumulated OCI (Loss)

Accumulated OCI (Loss) for the years ended December 31, 2021, 2020 and 2019 consisted of:

Accumulated Other Comprehensive Income (Loss)	As of December 31, 2018		Adoption of new accounting standard		2019 Change		As of December 31, 2019		2020 Change		As of December 31, 2020		2021 Change		As of December 31, 2021
(Millions)
Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $0 for 2019, $0 for 2020 and $0 for 2021	$	(11)	$	(2)	$	1	$	(12)	$	—	$	(12)	$	2	$	(10)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $(1) for 2019, $3 for 2020 and $(1) for 2021	(6)		—		(1)		(7)		(13)		(20)		(8)		(28)
Unrealized loss from equity method investment, net of income tax benefit of $(3) for 2021 (a)	$	—	$	—	$	—	$	—	$	—	$	—	$	(9)	$	(9)
Unrealized (loss) gain on derivatives qualifying as cash flow hedges:
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $(9) for 2019, $(7) for 2020 and $(44) for 2021	9		—		(22)		(13)		(22)		(35)		(159)		(194)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $3 for 2019, $2 for 2020 and $(3) for 2021 (b)	(64)		(10)		11		(63)		19		(44)		12		(32)
Loss on derivatives qualifying as cash flow hedges	(55)		(10)		(11)		(76)		(3)		(79)		(147)		(226)
Accumulated Other Comprehensive Loss	$	(72)	$	(12)	$	(11)	$	(95)	$	(16)	$	(111)	$	(162)	$	(273)

(a)Foreign currency and interest rate contracts.

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

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Earnings Per Share

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Earnings Per Share

Earnings Per Share

Basic earnings per share is computed by dividing net income attributable to AVANGRID by the weighted-average number of shares of our common stock outstanding.

The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Years Ended December 31,	2021		2020		2019
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	707	$	581	$	667
Denominator:
Weighted average number of shares outstanding - basic	358,086,621		309,494,939		309,491,082
Weighted average number of shares outstanding - diluted	358,578,608		309,559,387		309,514,910
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	1.97	$	1.88	$	2.16
Earnings Per Common Share, Diluted	$	1.97	$	1.88	$	2.16

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Variable Interest Entities

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Variable Interest Entities

Variable Interest Entities

We participate in certain partnership arrangements that qualify as 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 consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs.

On February 5, 2021, we closed on the final TEF agreement for Aeolus Wind Power VII, LLC (Aeolus VII) in a non-cash transaction. The four Aeolus VII wind farms total 688 MW of wind power. On September 9, 2021, we sold an additional TEF interest in Aeolus VII for $131 million. The $8 million difference between the amount received and the $139 million noncontrolling interest recognized was recorded as an adjustment to equity because there was no change in control as a result of the transaction. On November 4, 2021, we sold a TEF interest in Aeolus Wind Power VIII, LLC (Aeolus VIII) for $199 million, of which $8 million is held in escrow until certain conditions are met.

As of December 31, 2021, the assets and liabilities of the VIEs totaled approximately $2,039 million and $119 million, respectively. As of December 31, 2020, the assets and liabilities of VIEs totaled approximately $1,713 million and $107 million, respectively. At both December 31, 2021 and 2020, 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 December 31, 2021, El Cabo Wind, LLC (El Cabo), Patriot Wind Farm LLC (Patriot), Aeolus VII and Aeolus VIII are our consolidated VIEs.

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

See Note 22 - Equity Method Investments for information on our VIE we do not consolidate.

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Grants, Government Incentives and Deferred Income

12 Months Ended

Dec. 31, 2021

Other Liabilities Disclosure [Abstract]

Grants, Government Incentives and Deferred Income

Grants, Government Incentives and Deferred Income

The changes in deferred income as of December 31, 2021 and 2020 consisted of:

(Millions)	Government grants		Other deferred income		Total
As of December 31, 2019	$	1,258	$	16	$	1,274
Disposals	(2)		—		(2)
Recognized in income	(66)		(2)		(68)
As of December 31, 2020	1,190		14		1,204
Disposals	—		—		—
Recognized in income	(65)		(9)		(74)
As of December 31, 2021	$	1,125	$	5	$	1,130

Within deferred income, we classify grants we received under Section 1603 of the American Recovery and Reinvestment Act of 2009, where the United States Department of Treasury (DOT) provides eligible parties the option of claiming grants for specified energy property in lieu of tax credits, which we claimed for the majority of our qualifying properties. Deferred income has been recorded for the grant amounts and is amortized as an offset against depreciation expense using the straight-line method over the estimated useful life of the associated property to which the grants apply. We recognize a net deferred tax asset for the book to tax basis differences related to the property for income tax purposes within the nontaxable grant revenue deferred income tax liabilities (see Note 16 – Income Taxes).

We are required to comply with certain terms and conditions applicable to each grant and, if a disqualifying event should occur as specified in the grant’s terms and conditions, we are required to repay the grant funds to the DOT. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2021 and 2020.

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Equity Method Investments

12 Months Ended

Dec. 31, 2021

Equity Method Investments and Joint Ventures [Abstract]

Equity Method Investment

Equity Method Investments

On December 16, 2020, Renewables sold a 85% ownership interest in a wind farm located in South Dakota (Tatanka) to WEC Infrastructure involving total consideration of $238 million, excluding closing costs, and recognized a gain of $12 million, net of tax. The pre-tax gain of $16 million is included in "Other income (expense)" in our consolidated statements of income. Our retained investment in Tatanka of $24 million was valued based on an enterprise value of $298 million and applying an effective percentage of economic benefits retained of 7.97%, which was derived from a DCF model similar to the model used for Goodwill as described in Note 7. The net gain includes $4 million related to the remeasurement of our retained investment in Tatanka. The transaction was accounted for as a sale of assets and resulted in a loss of control. The retained 15% ownership interest is accounted for as an equity method investment. As of December 31, 2021, and 2020, the carrying value of our Tatanka investment was $23 million and $24 million, respectively.

On December 13, 2019, Renewables transferred a 50% ownership interest in a wind farm and a solar project located in Arizona (Poseidon) to Axium involving total consideration of $112 million, excluding closing costs, and recognized a gain of $96 million, net of tax. The pre-tax gain of $134 million is included in "Other income (expense)" in our consolidated statements of income. The net gain includes $50 million related to the remeasurement of our retained investment in Poseidon which was valued based on the consideration received in the transaction. The transaction was accounted for as the sale of a business and resulted in a loss of control. The retained 50% ownership interest is accounted for as an equity method investment. As of December 31, 2021 and 2020, the carrying value of our Poseidon investment was $96 million and $104 million, respectively.

In December 2018, Renewables sold 80% of our wholly owned subsidiary, Coyote Ridge Wind, LLC (Coyote Ridge), including substantially all of the related tax benefits, to WEC Infrastructure in exchange for $144 million of total proceeds with $84 million received in 2019 to complete the transaction. We recorded a gain of $4 million and $10 million from this transaction in “Other expense" in our consolidated statements of income for the years ended December 31, 2019 and 2018, respectively. We account for the remaining 20% membership interest under the equity method of accounting. As of December 31, 2021 and 2020, the carrying amount of our Coyote Ridge investment was $15 million and $16 million, respectively.

Renewables has two 50-50 joint ventures with Horizon Wind Energy, LLC, which own and operate the Flat Rock Windpower LLC (Flat Rock I) and the Flat Rock Wind Power II LLC (Flat Rock II) wind farms located in upstate New York. Flat Rock I has a 231 MW capacity and Flat Rock II has a 91 MW capacity. We account for the Flat Rock joint ventures under the equity method of accounting. As of December 31, 2021 and 2020, the carrying amount of Flat Rock I was $93 million and $98 million, respectively, and Flat Rock II was $44 million and $47 million, respectively.

Renewables holds a 50% voting interest in Vineyard Wind, LLC (Vineyard Wind), a joint venture with Copenhagen Infrastructure Partners (CIP). Vineyard Wind has acquired easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. The first easement area acquired was Lease Area 501 which contains 166,886 acres located southeast of Martha's Vineyard. Lease Area 501 was subsequently divided in 2021 creating Lease Area 534. In 2018, Vineyard Wind was selected by the Massachusetts Electric Distribution Companies (EDCs) to construct and operate Vineyard Wind’s proposed 800 MW wind farm (Vineyard Wind 1) and electricity transmission project pursuant to the Massachusetts Green Communities Act Section 83C RFP for offshore wind energy projects. The Vineyard Wind 1 project will be located on Lease Area 501. In December 2019, DEEP selected Vineyard Wind to provide 804 MW of offshore wind through the development of its Park City Wind Project, which will be located on Lease area 534. In addition, in December 2021 Vineyard Wind’s Commonwealth Wind project, which will also be located on Lease Area 534 was selected as part of Massachusetts’ third offshore wind competitive procurement process. The Commonwealth Wind’s proposed 1,232 MW wind farm will deliver clean energy to the residents of Massachusetts primarily through contracts with the electric distribution companies in the state, subject to finalization of the power purchase agreements with the electric distribution companies.

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

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

Vineyard Wind 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 since it does not have a controlling interest in Vineyard Wind, and therefore we do not consolidate Vineyard Wind. As of December 31, 2021 and 2020, the carrying amount of Renewables' investment in Vineyard Wind was $141 million and $245 million, respectively.

On September 15, 2021, Renewables entered into an agreement with CIP to restructure Vineyard Wind, which closed on January 10, 2022. Following the restructuring agreement closing, Vineyard Wind 1 remains a 50-50 joint venture, Renewables has full ownership of the project company containing Lease Area 534, including the Park City Wind and Commonwealth Wind projects along with any remaining non-contracted area in Lease Area 534, and CIP has full ownership of the project company containing Lease Area 522. The consideration exchanged resulted in Renewables making a payment of approximately $168 million to CIP, and Renewables will recognize a gain ranging from $175 million to $200 million in 2022, driven by the increase in the market value of the leases and related development activities over its carrying value. The purchase price accounting is preliminary and subject to change.

Networks is a party to a 50-50 joint venture with Clearway Energy, Inc. in GenConn, which operates two peaking generation plants in Connecticut. The investment in GenConn is accounted for as an equity investment. As of December 31, 2021 and 2020, the carrying value of our GenConn investment was $99 million and $104 million, respectively.

Networks holds an approximate 20% ownership interest in New York TransCo. Through New York TransCo, Networks has formed a partnership with Central Hudson Gas and Electric Corporation, Consolidated Edison, Inc., National Grid, plc and Orange and Rockland Utilities, Inc. to develop a portfolio of interconnected transmission lines and substations to fulfill the objectives of the New York energy highway initiative, which is a proposal to install up to 3,200 MW of new electric generation and transmission capacity in order to deliver more power generated from upstate New York power plants to downstate New York. On April 8, 2019, New York Transco was selected as the developer for Segment B of the AC Transmission Public Policy Project by the NYISO. The selected project, New York Energy Solution (NYES), replaces nearly 80-year old transmission assets located in the upper to mid-Hudson Valley with streamlined, modernized technology, to enable surplus clean energy resources in upstate New York and help achieve the State’s energy goals. The total project cost is $600 million plus interconnection costs. New York Transco is subject to regulatory approval of its rates, terms and conditions with the FERC. As of both December 31, 2021 and 2020, the amount receivable from New York TransCo was $0. The investment in New York TransCo is accounted for as an equity investment. As of December 31, 2021 and 2020, the carrying value of our New York TransCo investment was $49 million and $30 million, respectively.

None of our joint ventures have any contingent liabilities or capital commitments, except for those disclosed above. Distributions received from equity method investments, excluding the return of capital as part of the Vineyard Wind 1 financial close disclosed above, amounted to $21 million, $22 million and $17 million for the years ended December 31, 2021, 2020 and 2019 respectively, which are reflected as either distributions of earnings or as returns of capital in the operating and investing sections of the consolidated statements of cash flows, respectively. In addition, during the years ended December 31, 2021, 2020 and 2019, we received $11 million, $14 million and $9 million of distributions in RECs from our equity method investments. As of December 31, 2021, there was $10 million of undistributed earnings from our equity method investments. Capitalized interest costs related to equity method investments were $6 million, $8 million and $7 million for the years ended December 31, 2021, 2020 and 2019, respectively.

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Other Financial Statements Items

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Other Financial Statements Items

Other Financial Statements Items

Other income (expense)

Other income (expense) for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years ended December 31,	2021		2020		2019
(Millions)
Gain on sale of assets (a)	$	—	$	20	$	148
Allowance for funds used during construction	88		56		46
Carrying costs on regulatory assets	17		28		21
Non-service component of net periodic benefit cost	(37)		(62)		(79)
Other	(8)		(24)		(15)
Total Other Income (Expense)	$	60	$	18	$	121

(a) 2020 includes a $16 million gain from the Tatanka sale and 2019 includes a $134 million gain from the Poseidon sale (see Note 22).

Accounts receivable and unbilled revenues, net

Accounts receivable and unbilled revenues, net as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Trade receivables and unbilled revenues	$	1,420	$	1,295
Allowance for credit losses	(151)		(108)
Total Accounts receivable and unbilled revenues, net	$	1,269	$	1,187

The change in the allowance for credit losses as of December 31, 2021 and 2020 consisted of:

(Millions)
As of December 31, 2018	$	62
Current period provision	92
Write-off as uncollectible	(85)
As of December 31, 2019	$	69
Current period provision	83
Write-off as uncollectible	(44)
As of December 31, 2020	$	108
Current period provision	110
Write-off as uncollectible	(67)
As of December 31, 2021	$	151

DPA receivable balances were $108 million and $78 million as of December 31, 2021 and 2020, respectively. As of December 31, 2021 and 2020, our allowance for credit losses for DPAs was $68 million and $48 million, respectively.

Prepayments and Other Current Assets

Prepayments and other current assets as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Prepaid other taxes	$	95	$	135
Short-term investment (a)	—		300
Broker margin and collateral accounts	87		30
Other pledged deposits	4		2
Prepaid expenses	58		41
Other	1		17
Total	$	245	$	525

(a) Short-term investment from proceeds of the Iberdrola Loan.

Other current liabilities

Other current liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Advances received	$	204	$	141
Accrued salaries	127		109
Short-term environmental provisions	52		49
Collateral deposits received	58		42
Pension and other postretirement	5		5
Finance leases	4		8
Other	34		14
Total	$	484	$	368

Disposition

On May 13, 2021, Renewables sold 100% of its ownership interest in two solar projects located in Nevada to Primergy Hot Pot Holdings LLC for total consideration of $35 million and recognized a gain of $11 million, net of tax. The pre-tax gain of $15 million is recorded in "Operating revenues" in our consolidated statements of income. The total consideration includes variable consideration that Renewables could receive based on the achievement of certain regulatory and project development milestones. The transaction was accounted for as an asset sale.

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Segment Information

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Segment Information

Segment Information

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

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

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

The chief operating decision maker evaluates segment performance based on segment adjusted net income defined as net income adjusted to exclude restructuring charges, mark-to-market earnings from changes in the fair value of derivative instruments, accelerated depreciation derived from repowering of wind farms, a legal settlement, costs incurred in connection with the COVID-19 pandemic and costs incurred related to the PNMR Merger.

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

Segment information as of and for the year ended December 31, 2021 consisted of:

For the year ended December 31, 2021	Networks		Renewables		Other(a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,753	$	1,220	$	1	$	6,974
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	616		397		1		1,014
Operating income	876		26		(7)		895
Earnings (losses) from equity method investments	12		(5)		—		7
Interest expense, net of capitalization	217		1		80		298
Income tax expense (benefit)	98		(48)		(29)		21
Capital expenditures	2,294		680		2		2,976
Adjusted net income	661		170		(51)		780
As of December 31, 2021
Property, plant and equipment	18,737		10,118		11		28,866
Equity method investments	148		412		—		560
Total assets	$	26,126	$	12,578	$	800	$	39,504

(a)Includes Corporate and intersegment eliminations.

Segment information as of and for the year ended December 31, 2020 consisted of:

For the year ended December 31, 2020	Networks		Renewables		Other(a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,187	$	1,132	$	1	$	6,320
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	592		394		1		987
Operating income	877		(16)		8		869
Earnings (losses) from equity method investments	10		(13)		—		(3)
Interest expense, net of capitalization	234		7		75		316
Income tax expense (benefit)	120		(80)		(11)		29
Capital expenditures	1,838		943		—		2,781
Adjusted net income	568		115		(58)		625
As of December 31, 2020
Property, plant and equipment	17,079		9,662		10		26,751
Equity method investments	134		534		—		668
Total assets	$	24,592	$	12,867	$	364	$	37,823

(a)Includes Corporate and intersegment eliminations.

Segment information for the year ended December 31, 2019 consisted of:

For the year ended December 31, 2019	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,150	$	1,184	$	2	$	6,336
Revenue - intersegment	14		—		(14)		—
Depreciation and amortization	549		383		1		933
Operating income	890		93		15		998
Earnings (losses) from equity method investments	11		(8)		—		3
Interest expense, net of capitalization	269		14		27		310
Income tax expense (benefit)	152		28		(11)		169
Capital expenditures	1,610		1,122		3		2,735
Adjusted net income	$	465	$	193	$	(17)	$	640

(a)Includes Corporate and intersegment eliminations.

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019 is as follows:

Years Ended December 31,	2021		2020		2019
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	780	$	625	$	640
Adjustments:
Mark-to-market adjustments - Renewables (1)	(53)		(5)		76
Restructuring charges (2)	—		(6)		(6)
Accelerated depreciation from repowering (3)	—		(9)		(33)
Impact of COVID-19 (4)	(34)		(29)		—
Merger costs (5)	(12)		(6)		—
Legal settlement - Gas storage (6)	—		(5)		—
Income tax impact of adjustments	26		16		(10)
Net Income Attributable to Avangrid, Inc.	$	707	$	581	$	667

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

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

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

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

(5)Pre-merger costs incurred.

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

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Related Party Transactions

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Related Party Transactions

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

Related party transactions for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Years Ended December 31,	2021				2020				2019
(Millions)	Sales To		Purchases From		Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(52)	$	1	$	(43)	$	1	$	(42)
Iberdrola Renovables Energia, S.L.	$	—	$	(10)	$	—	$	(9)	$	—	$	(9)
Iberdrola Financiación, S.A.	$	—	$	(9)	$	—	$	(7)	$	—	$	(3)
Vineyard Wind	$	14	$	—	$	9	$	—	$	13	$	—
Iberdrola Solutions	$	7	$	(39)	$	2	$	—	$	1	$	—
Other	$	2	$	(3)	$	—	$	—	$	1	$	(3)

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

Related party balances as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021				2020
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	3	$	(43)	$	2	$	(43)
Iberdrola Financiacion	$	—	$	(9)	$	—	$	(6)
Vineyard Wind	$	8	$	(8)	$	4	$	—
Iberdrola Solutions	$	—	$	(2)	$	5	$	—
Other	$	—	$	(1)	$	1	$	(1)

Transactions with Iberdrola, our majority shareholder, relate predominantly to the provision and allocation of corporate services and management fees. All costs that can be specifically allocated, to the extent possible, are charged directly to the company receiving such services. In situations when Iberdrola corporate services are provided to two or more companies of AVANGRID, any costs remaining after direct charges are allocated using agreed upon cost allocation methods designed to allocate such costs. We believe that the allocation method used is reasonable. See Note 10 for a discussion of the Iberdrola Loan.

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 December 31, 2021 and 2020 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 both December 31, 2021 and 2020, there was no outstanding amount under this credit facility.

We have a bi-lateral demand note agreement with Iberdrola Solutions, LLC, which had notes payable and notes receivable balances of $2 million and $5 million for the years ended December 31, 2021 and 2020, respectively. Renewables also had financial forward power contracts with Iberdrola Solutions to hedge Renewables' uncontracted wind exposure in Texas.

See Note 22 - Equity Method Investments for more information on transactions with our equity method investees.

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

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Stock-Based Compensation

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Stock-Based Compensation

Stock-Based CompensationThe 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). As of December 31, 2021, the total number of shares authorized for stock-based compensation plans was 2,500,000.

Performance Stock Units

During 2016, 1,298,683 performance stock units (PSUs) were granted to certain officers and employees of AVANGRID. In 2017, 2018 and 2019, an additional 85,759, 75,350 and 3,881 PSUs, respectively, were granted to officers and employees of AVANGRID under the Plan with achievement measured based on certain performance and market-based metrics for the 2016 to 2019 time period.

The fair value of the PSUs on the grant date was $31.80 per share, which is expensed on a straight-line basis over the requisite service period of approximately seven years based on expected achievement. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recent quarterly dividend payment and the stock price as of the grant date.

In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved as earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes. The remaining unvested PSUs were forfeited. In May 2020, 42,777 shares of common stock were issued to settle the first installment payment and 2,605 PSUs were forfeited from the originally approved total number of PSUs. In March 2021, 45,661 shares of common stock were issued to settle the second installment payment. The final payment will occur in 2022.

During 2021, 1,336,787 PSUs, were granted to certain officers and employees of AVANGRID with achievement measured based on certain performance and market-based metrics for the 2021 to 2022 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The fair value of the PSUs on the grant date was $36.22 per share. The fair value of the PSUs was determined using valuation techniques to forecast possible future stock prices, applying a weighted average historical stock price volatility of AVANGRID and industry companies, a risk-free rate of interest that is equal, as of the grant date, to the yield of the zero-coupon U.S. Treasury bill and a reduction for the respective dividend yield calculated based on the most recently quarterly dividend payment and the stock price as of the grant date. The expense is recognized on a straight-line basis over the requisite service period of approximately four years based on expected achievement.

Restricted Stock Units

In June and October 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan two restricted stock units (RSUs) awards of 60,000 and 8,000 RSUs, respectively, were granted to certain officers of AVANGRID. The RSUs vested in full in one installment in June and December 2020, respectively for each award. The fair value on the grant date was determined based on a price of $50.40 per share for the June 2018 awards and $47.59 per share for the October 2018 awards. In June 2020, 60,000 RSUs, plus dividend equivalents accrued through the vesting period, were settled for $3 million in cash. In March 2021, the October 2018 RSU grant was settled, net of applicable taxes, by issuing 5,953 shares of common stock.

In August 2020, 5,000 RSUs were granted to an officer of AVANGRID. The RSUs vest in three equal installments in 2021, 2022 and 2023, provided that the grantee remains continuously employed with AVANGRID through the applicable vesting dates. The fair value on the grant date was determined based on a price of $48.99 per share. In February 2021, the first installment of the RSU grant was settled by issuing 1,697 shares of common stock. In October 2021, this RSU grant was cancelled and the remaining unvested RSUs were forfeited.

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.

In June 2021, 17,500 RSUs were granted to an officer of AVANGRID with immediate vesting. The fair value on the grant date was determined based on a price of $53.59 per share. The RSU grant was settled, net of applicable taxes, by issuing 9,390 shares of common stock.

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

Phantom Share Units

In March 2020, 167,060 Phantom Shares were granted to certain AVANGRID executives and employees. These awards will vest in three equal installments in 2020, 2021 and 2022 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of AVANGRID’s common stock on the respective vesting dates, subject to

continued employment. The liability of these awards is measured based on the closing share price of AVANGRID’s common stock at each reporting date until the date of settlement. In both June 2020 and March 2021, $2 million was paid to settle, respectively, the first and the second installments under this plan. As of both December 31, 2021 and 2020, the total liability was $2 million, which is included in other current and non-current liabilities.

The total stock-based compensation expense, which is included in "Operations and maintenance" of our consolidated statements of income for the years ended December 31, 2021, 2020 and 2019 was $18 million, $14 million and $3 million, respectively. The total income tax benefits recognized for stock-based compensation arrangements for each of the years ended December 31, 2021, 2020 and 2019, were $5 million, $4 million and $1 million, respectively.

A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2021, and changes during the fiscal year ended December 31, 2021, is presented below:

	Number of PSUs and RSUs	Weighted Average Grant Date Fair Value
Nonvested Balance – December 31, 2020	142,167	$	32.42
Granted	1,359,516	$	36.49
Forfeited	(90,603)	$	36.63
Vested	(87,751)	$	47.70
Nonvested Balance – December 31, 2021	1,323,328	$	36.05

As of December 31, 2021, total unrecognized costs for non-vested PSUs, RSUs and Phantom Shares was $25 million. The weighted-average period over which the PSU, RSU and Phantom Shares costs will be recognized is approximately 3 years.

The weighted-average grant date fair value of PSUs and RSUs granted during the year was $36.49 per share for the year ended December 31, 2021.

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Subsequent events	12 Months Ended
	Dec. 31, 2021
Subsequent Events [Abstract]
Subsequent events	Subsequent eventsOn February 16, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2022 to shareholders of record at the close of business on March 1, 2022.On January 10, 2022 Renewables closed an agreement with CIP to restructure Vineyard Wind. See Note 22 - Equity Method Investments for more information on this transaction.

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CONDENSED FINANCIAL INFORMATION OF PARENT

12 Months Ended

Dec. 31, 2021

Condensed Financial Information Disclosure [Abstract]

CONDENSED FINANCIAL INFORMATION OF PARENT

Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF INCOME

FOR THE YEARS ENDED December 31, 2021, 2020 AND 2019

Years Ended December 31,	2021		2020		2019
(Millions)
Operating Revenues	$	—	$	—	$	—
Operating Expenses
Operating expense	19		10		3
Taxes other than income taxes	(11)		(11)		(12)
Total Operating Expenses	8		(1)		(9)
Operating (Loss) Income	(8)		1		9
Other Income
Other income	22		35		59
Equity earnings of subsidiaries	756		641		678
Interest expense	(93)		(109)		(93)
Income Before Income Tax	677		568		653
Income tax benefit	(30)		(13)		(14)
Net Income	$	707	$	581	$	667

See accompanying notes to Schedule I.

Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF COMPREHENSIVE INCOME

FOR THE YEARS ENDED December 31, 2021, 2020, AND 2019

Years Ended December 31,	2021		2020		2019
(Millions)
Net Income	$	707	$	581	$	667
Other comprehensive loss of subsidiaries	(162)		(16)		(11)
Comprehensive Income	$	545	$	565	$	656

See accompanying notes to Schedule I.

Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

BALANCE SHEETS

AS OF December 31, 2021 AND 2020

As of December 31,	2021		2020
(Millions)
Assets
Current Assets
Cash and cash equivalents	$	1,424	$	1,438
Accounts receivable from subsidiaries	128		124
Notes receivable from subsidiaries	1,475		1,489
Prepayments and other current assets	52		357
Total current assets	3,079		3,408
Investments in subsidiaries	18,500		18,356
Other assets
Deferred income taxes	413		388
Other	3		3
Total other assets	416		391
Total Assets	$	21,995	$	22,155
Liabilities
Current Liabilities
Notes payable	—		308
Notes payable to subsidiaries	643		1,375
Accounts payable and accrued liabilities	3		12
Accounts payable to subsidiaries	9		9
Interest accrued	9		9
Interest accrued subsidiaries	1		10
Dividends payable	170		136
Total current liabilities	835		1,859
Derivative liabilities	19		—
Non-current debt	2,065		2,087
Non-current debt with affiliate	—		3,000
Total non-current liabilities	2,084		5,087
Total Liabilities	2,919		6,946
Equity
Stockholders' Equity:
Common stock	3		3
Additional paid-in capital	17,679		13,665
Treasury stock	(47)		(14)
Retained earnings	1,714		1,666
Accumulated other comprehensive loss	(273)		(111)
Total Equity	19,076		15,209
Total Liabilities and Equity	$	21,995	$	22,155

See accompanying notes to Schedule I.

Schedule I –Financial Statements of Parent

AVANGRID, INC. (PARENT)

CONDENSED FINANCIAL INFORMATION OF PARENT

STATEMENTS OF CASH FLOWS

FOR THE YEARS ENDED December 31, 2021, 2020, AND 2019

Years Ended December 31,	2021		2020		2019
(Millions)
Net Cash used in Operating Activities	$	(397)	$	(142)	$	(1,299)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	130		(73)		633
Investments in subsidiaries	(1,026)		(591)		(399)
Return of capital from investments in subsidiaries	1,122		419		433
Other investments	300		(300)		—
Net Cash provided by (used in) Investing Activities	526		(545)		667
Cash Flow from Financing Activities
(Repayments) receipts of short-term notes payable from subsidiaries, net	(186)		(14)		107
Repayments of short-term notes payable	(309)		(253)		(27)
Proceeds from non-current debt	—		744		1,243
(Repayments) proceeds from non-current debt with affiliate	(3,000)		3,000		—
Repayments of non-current debt	—		(950)		—
Repurchase of common stock	(33)		(2)		—
Issuance of common stock	3,998		(1)		—
Dividends paid	(613)		(545)		(545)
Net Cash (used in) provided by Financing Activities	(143)		1,979		778
Net (Decrease) Increase in Cash and Cash Equivalents	(14)		1,292		146
Cash and Cash Equivalents, Beginning of Year	1,438		146		—
Cash and Cash Equivalents, End of Year	$	1,424	$	1,438	$	146

Supplemental Cash Flow Information
Cash paid for interest	$	74	$	111	$	85
Cash paid (refunded) payment for income taxes	$	(15)	$	65	$	43

See accompanying notes to Schedule I.

Basis of Presentation

Avangrid, Inc. (AVANGRID) is a holding company and we conduct substantially all of our business through our subsidiaries. Substantially all of our consolidated assets are held by our subsidiaries. Accordingly, our cash flow and ability to meet our obligations are largely dependent upon the earnings of our subsidiaries and the distribution or other payment of their earnings to us in the form of dividends, loans or advances or repayment of loans and advances from us. Our condensed financial statements and related footnotes have been prepared in accordance with regulatory statute 210.12-04 of Regulation S-X. Our condensed financial statements should be read in conjunction with the consolidated financial statements and notes thereto of AVANGRID and subsidiaries (AVANGRID Group).

AVANGRID indirectly or directly owns all of the ownership interests of our significant subsidiaries. AVANGRID relies on dividends or loans from our subsidiaries to fund dividends to our primary shareholder.

AVANGRID’s significant accounting policies are consistent with those of the AVANGRID Group. For the purposes of these condensed financial statements, AVANGRID’s wholly owned and majority owned subsidiaries are recorded based upon our proportionate share of the subsidiaries net assets.

AVANGRID files a consolidated federal income tax return that includes the taxable income or loss of all our subsidiaries. Each subsidiary company is treated as a member of the consolidated group and determines its current and deferred taxes separately

and settles its current tax liability or benefit each year directly with AVANGRID pursuant to a tax sharing agreement between AVANGRID and our members.

Proposed Merger with PNMR

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

Consummation of the Merger (Closing) is subject to the satisfaction or waiver of certain customary closing conditions, including, without limitation, the approval of the Merger Agreement by the holders of at least a majority of the outstanding shares of PNMR common stock entitled to vote thereon, the absence of any material adverse effect on PNMR, the receipt of certain required regulatory approvals (including approvals from the Public Utility Commission of Texas (PUCT), the New Mexico Public Regulation Commission (NMPRC), the Federal Energy Regulatory Commission (FERC), the Federal Communications Commission (FCC), the Committee on Foreign Investment in the United States (CFIUS), the Nuclear Regulatory Commission (NRC) and approval under the Hart-Scott-Rodino Antitrust Improvements Act of 1976), the Four Corners Divestiture Agreements (as defined below) being in full force and effect and all applicable regulatory filings associated therewith being made, as well as holders of no more than 15% of the outstanding shares of PNMR common stock validly exercising their dissenters’ rights. On February 12, 2021, the shareholders of PNMR approved the proposed Merger. As of November 1, the Merger had obtained all regulatory approvals other than from the NMPRC. On November 1, 2021, after public hearing and briefing on the matter, the hearing examiner in the Merger proceeding at the NMPRC issued an unfavorable recommendation related to the amended stipulated agreement entered into by PNMR, AVANGRID and several interveners in the NMPRC proceeding with respect to consideration of the joint Merger application in June 2021. On December 8, 2021, the NMPRC issued an order rejecting the amended stipulated agreement. On January 3, 2022, AVANGRID and PNMR filed a notice of appeal of the December 8, 2021 decision of the NMPRC with the New Mexico Supreme Court. During the pendency of this appeal certain required regulatory approvals and consents may expire and AVANGRID and PNMR will reapply and/or apply for extensions of such approvals, as the case may be. In addition, on January 3, 2022, Avangrid, PNMR and Merger Sub entered into an Amendment to the Merger Agreement (the Amendment), pursuant to which Avangrid, PNMR and Merger Sub each agreed to extend the “End Date” for consummation of the Merger until April 20, 2023. The parties acknowledge in the Amendment that the required regulatory approval from the NMPRC has not been obtained and that the parties have reasonably determined that such outstanding approval will not be obtained by April 20, 2022. In light of this outstanding approval, the parties determined to approve the Amendment. As amended, the Merger agreement may be terminated by each of Avangrid and PNMR under certain circumstances, including if the Merger is not consummated by April 20, 2023 (subject to a three-month extension by Avangrid and PNMR by mutual consent if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). It is anticipated that, prior to the amended "End Date" occurring that amendments to, or refilings of, certain previously obtained regulatory approvals will be necessary. We cannot predict the outcome of this proceeding for the outstanding approvals.

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

The Merger Agreement provides for certain customary termination rights including the right of either party to terminate the Merger Agreement if the Merger is not completed on or before April 20, 2023, as amended (subject to a three-month extension by either party if all of the conditions to the closing, other than the conditions related to obtaining regulatory approvals, have been satisfied or waived). The Merger Agreement further provides that, upon termination of the Merger Agreement under certain specified circumstances (including if AVANGRID terminates the Merger Agreement due to a change in recommendation of the board of directors of PNMR or if PNMR terminates the Merger Agreement to accept a superior proposal (as defined in the Merger Agreement)), PNMR will be required to pay AVANGRID a termination fee of $130 million. In addition, the Merger Agreement provides that (i) if the Merger Agreement is terminated by either party due to a failure of a regulatory closing condition and such failure is the result of AVANGRID’s breach of its regulatory covenants, or (ii)

AVANGRID fails to effect the Closing when all closing conditions have been satisfied and it is otherwise obligated to do so under the Merger Agreement, then, in either such case, upon termination of the Merger Agreement, AVANGRID will be required to pay PNMR a termination fee of $184 million as the sole and exclusive remedy. Upon the termination of the Merger Agreement under certain specified circumstances involving a breach of the Merger Agreement, either PNMR or AVANGRID will be required to reimburse the other party’s reasonable and documented out-of-pocket fees and expenses up to $10 million (which amount will be credited toward, and offset against, the payment of any applicable termination fee).

In connection with the Merger, Iberdrola has provided AVANGRID a commitment letter (Iberdrola Funding Commitment Letter), pursuant to which Iberdrola has unilaterally agreed to provide to AVANGRID, or arrange the provision to AVANGRID of, funds to the extent necessary for AVANGRID to consummate the Merger, including the payment of the aggregate Merger Consideration.

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

On May 18, 2021, we issued 77,821,012 shares of common stock in two private placements. Iberdrola purchased 63,424,125 shares and Hyde Member LLC, a Delaware limited liability company and a wholly owned subsidiary of Qatar Investment Authority, purchased 14,396,887 shares of our common stock, par value $0.01 per share, at the purchase price of $51.40 per share, which was the closing price of the shares of our common stock on the NYSE as of May 11, 2021. Proceeds of the private placements were $4,000 million. $3,000 million of the proceeds were used to repay the Iberdrola Loan. After the effect of the private placements, Iberdrola retained its 81.5% ownership interest in AVANGRID.

Common Stock

As of December 31, 2021, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 387,678,630 shares issued and 386,568,104 shares outstanding, 81.6% of which are owned by Iberdrola, each having a par value of $0.01, for a total value of common stock of $3 million and additional paid in capital of $17,679 million. As of December 31, 2020, AVANGRID share capital consisted of 500,000,000 shares of common stock authorized, 309,794,917 shares issued and 309,077,300 shares outstanding, 81.5% of which were owned by Iberdrola, each having a par value of $ $0.01, for a total value of common stock capital of $3 million and additional paid in of $13,665 million. As of December 31, 2021 and 2020, we had 112,543 and 413,782 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2021 and 2020, we issued 77,883,713 and 42,777 shares of common stock, respectively, and released 301,239 and 72,028 shares of common stock held in trust, respectively, each having a par value of $0.01.

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 target relative ownership percentage at 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2021, 694,148 shares were repurchased pursuant to the stock repurchase program. As of December 31, 2021, a total of 997,983 shares have been repurchased in the open market, all of which are included as AVANGRID treasury shares. As of December 31, 2021, the total cost of all repurchases, including commissions, was $47 million.

On February 16, 2022, the board of directors of AVANGRID declared a quarterly dividend of $0.44 per share on its common stock. This dividend is payable on April 1, 2022 to shareholders of record at the close of business on March 1, 2022.

Long-Term Debt

In 2017, AVANGRID issued $600 million aggregate principal amount of its 3.15% notes maturing in 2024.

On May 16, 2019, AVANGRID issued $750 million aggregate principal amount of its 3.80% notes maturing in 2029. Proceeds of the offering were used to finance and/or refinance, in whole or in part, one or more eligible renewable energy generation facilities. Net proceeds of the offering after the price discount and issuance-related expenses were $743 million.

On April 9, 2020, AVANGRID issued $750 million aggregate principal amount of unsecured notes maturing in 2025 at a fixed interest rate of 3.20%. Net proceeds of the offering after the price discount and issuance-related expenses were $744 million.

On December 14, 2020, AVANGRID and Iberdrola entered into an intra-group loan agreement which provided AVANGRID with an unsecured subordinated loan in an aggregate principal amount of $3,000 million (the Iberdrola Loan). The Iberdrola Loan was repaid in 2021 with the proceeds of the common share issuance described in Note 1.Cash Dividends Paid by Subsidiaries

Cash dividends paid by subsidiary are as follows:

Years ended December 31,	2021		2020		2019
(millions)
AVANGRID Networks	$	970	$	419	$	433
AVANGRID Renewables	$	152	$	—	$	—

For the years ended December 31, 2021, 2020 and 2019, AVANGRID made capital contributions to Networks of $1,011 million, $590 million and $158 million, respectively.

During 2021 and 2020, AVANGRID recorded a net non-cash contribution and dividend of $674 million and $423 million, respectively, to and from its subsidiaries to zero out their account balances of notes receivable and payable.

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Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Policies)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Principles of consolidation

Principles of consolidationWe consolidate the entities in which we have a controlling financial interest, after the elimination of intercompany transactions. We account for investments in common stock where we have the ability to exercise significant influence, but not control, using the equity method of accounting.

Revenue recognition

Revenue recognitionWe recognize revenues when we transfer control of promised goods or services to our customers in an amount that reflects the consideration we expect to be entitled to in exchange for those goods or services.

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 24.

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 including intersegment eliminations.

Contract Costs, Contract Liabilities and Practical Expedient

We recognize an asset for incremental costs of obtaining a contract with a customer when we expect the benefit of those costs to be longer than one year. We have contract assets for costs from development success fees, which we paid during the solar asset development period in 2018, and will amortize ratably into expense over the 15-year life of the power purchase agreement (PPA), expected to commence in December 2022 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2021 and 2020, and are presented in "Other non-current assets" on our 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 $9 million at December 31, 2021 and 2020, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $22 million for the year ended December 31, 2021, and $21 million for both of the years ended December 31, 2020 and 2019 as revenue related to contract liabilities.

We apply a practical expedient to expense as incurred costs to obtain a contract when the amortization period is one year or less. We record costs incurred to obtain a contract within operating expenses, including amortization of capitalized costs.

Regulatory accounting

Regulatory accounting

We account for our regulated utilities' operations in accordance with the authoritative guidance applicable to entities with regulated operations that meet the following criteria: (i) rates are established or approved by an independent, third-party regulator; (ii) rates are designed to recover the entity’s specific costs of providing the regulated services or products and; (iii) there is a reasonable expectation that rates are set at levels that will recover the entity’s costs and can be collected from customers. Regulatory assets represent incurred costs that have been deferred because of their probable future recovery from customers through regulated rates. Regulatory liabilities represent: (i) the excess recovery of costs or accrued credits that have been deferred because it is probable such amounts will be returned to customers through future regulated rates; or (ii) billings in advance of expenditures for approved regulatory programs.

We amortize regulatory assets and liabilities and recognize the related expense or revenue in our consolidated statements of income consistent with the recovery or refund included in customer rates. We believe it is probable that our currently recorded regulatory assets and liabilities will be recovered or settled in future rates.

Business combinations and assets acquisitions (disposals)

Business combinations and assets acquisitions (disposals)

We apply the acquisition method of accounting to account for business combinations. The consideration transferred for an acquisition is the fair value of the assets transferred, the liabilities incurred, including contingent consideration, and the equity interests issued by the acquirer. We measure identifiable assets acquired and liabilities and contingent liabilities assumed in a business combination initially at their fair values at the acquisition date. We record as goodwill the excess of the consideration transferred over the fair value of the identifiable net assets acquired. We recognize adjustments to provisional amounts relating to a business combination that are identified during the measurement period in the reporting period in which the adjustment amounts are determined. For business combinations, we expense acquisition-related costs as incurred.

In contrast to a business combination (disposal), we classify a transaction as an asset acquisition (disposal) when substantially all the fair value of the gross assets acquired (disposed) is concentrated in a single identifiable asset or group of similar identifiable assets or otherwise does not meet the definition of a business. For asset acquisitions, we capitalize acquisition-related costs as a component of the cost of the assets acquired and liabilities assumed.

Noncontrolling interests

Noncontrolling interestsNoncontrolling interests represent the portion of our net income (loss), comprehensive income (loss) and net assets that is not allocable to us and is calculated based on our ownership percentage. For holdings where the economic allocations are not based pro rata on ownership percentages, we use the balance sheet-oriented hypothetical liquidation at book value (HLBV) method, to reflect the substantive profit sharing arrangement.Under the HLBV method, the amounts we report as "Noncontrolling interests" and "Net income (loss) attributable to noncontrolling interests" in our consolidated balance sheets and consolidated statements of income represent the amounts the noncontrolling interest would hypothetically receive at each balance sheet reporting date under the liquidation provisions of each holding’s ownership agreement assuming we were to liquidate the net assets of the projects at recorded amounts determined in accordance with U.S. GAAP and distribute those amounts to the investors. We determine the noncontrolling interest in our statements of income and comprehensive income as the difference in noncontrolling interests on our consolidated balance sheets at the start, or at inception of the noncontrolling interest if applicable, and end of each reporting period, after taking into account any capital transactions between the holdings and the third party. We report the noncontrolling interest balances in the holdings as a component of equity on our consolidated balance sheets.

Equity method investments

Equity method investmentsWe account for joint ventures that do not meet consolidation criteria using the equity method. We reflect earnings (losses) recognized under the equity method in the consolidated statements of income as "Earnings (losses) from equity method investments." We recognize dividends received from joint ventures as a reduction in the carrying amount of the investment and not as dividend income. We assess and record an impairment of our equity method investments in earnings for a decline in value that we determine to be other than temporary.

Goodwill and other intangible assets

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

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

Intangible assets acquired separately are measured on initial recognition at cost. The cost of intangible assets acquired in a business combination is their fair value at the date of acquisition. Following initial recognition, intangible assets are carried at cost less any accumulated amortization and impairment losses. The useful lives of intangible assets are assessed as either finite or indefinite.

Intangible assets with finite lives are amortized on a straight-line basis over the useful economic life, which ranges from four to forty years, and assessed for impairment whenever there is an indication that the intangible asset may be impaired. The amortization expense on intangible assets with finite lives is recognized in our consolidated statements of income within the expense category that is consistent with the function of the intangible assets.

Property, plant and equipment

Property, plant and equipment

We account for property, plant and equipment at historical cost. In cases where we are required to dismantle installations or to recondition the site on which they are located, we record the estimated cost of removal or reconditioning as an asset retirement obligation (ARO) and add an equal amount to the carrying amount of the asset.

Development and construction of our various facilities are carried out in stages. We expense project costs during early stage development activities. Once we achieve certain development milestones and it is probable that we can obtain future economic benefits from a project, we capitalize salaries and wages for persons directly involved in the project, and engineering, permits, licenses, wind measurement and insurance costs. We periodically review development projects in construction for any indications of impairment.

We transfer assets from “Construction work in progress” to “Property, plant and equipment” when they are available for service.

We capitalize wind turbine and related equipment costs, other project construction costs and interest costs related to the project during the construction period through substantial completion. We record AROs at the date projects achieve commercial operation.

We depreciate the cost of plant and equipment in use on a straight-line basis, less any estimated residual value. The main asset categories are depreciated over the following estimated useful lives:

Major class	Asset Category	Estimated Useful Life (years)
Plant	Combined cycle plants	35-75
	Hydroelectric power stations	45-90
	Wind power stations	25-40
	Solar power stations	25
	Transmission and transport facilities	41-80
	Distribution facilities	4-80
Equipment	Conventional meters and measuring devices	7-85
	Computer software	3-37
Other	Buildings	30-82
	Operations offices	3-75

Networks determines depreciation expense using the straight-line method, based on the average service lives of groups of depreciable property, which include estimated cost of removal, in service at each operating company. Consistent with FERC accounting requirements, Networks charges the original cost of utility plant retired or otherwise disposed to accumulated

depreciation. Networks' composite rate of depreciation were 2.8% and 2.9% of average depreciable property for 2021 and 2020, respectively.

We charge repairs and minor replacements to operating expenses, and capitalize renewals and betterments, including certain indirect costs.

Allowance for funds used during construction (AFUDC), applicable to Networks' entities that apply regulatory accounting, is a noncash item that represents the allowed cost of capital, including a return on equity (ROE), used to finance construction projects. We record the portion of AFUDC attributable to borrowed funds as a reduction of interest expense and record the remainder as other income.

Leases

Leases

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

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

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

Impairment of long-lived assets

Impairment of long-lived assets

We evaluate property, plant and equipment and other long-lived assets for impairment when events or changes in circumstances indicate that the carrying amount may not be recoverable. An impairment evaluation is based on undiscounted cash flow analysis at the lowest level to which cash flows of the long-lived assets or asset groups are largely independent of the cash flows of other assets and liabilities. We are required to recognize an impairment loss if the carrying amount of the asset exceeds the undiscounted future net cash flows associated with that asset.

The impairment loss to be recognized is the amount by which the carrying amount of the long-lived asset exceeds the asset’s fair value. Depending on the asset, fair value may be determined by use of a discounted cash flow (DCF) model, with assumptions consistent with a market participant’s view of the exit price of the asset.

Fair value measurement

Fair value measurement

Fair value is the price that would be received to sell an asset or paid to transfer a liability in an orderly transaction between market participants as of the measurement date. The fair value measurement is based on the presumption that the transaction to sell the asset or transfer the liability takes place in either the principal market for the asset or liability, or, in the absence of a principal market, in the most advantageous market for the asset or liability.

The fair value of an asset or a liability is measured using the assumptions that market participants would use when pricing the asset or liability, assuming that market participants act in their economic best interest. A fair value measurement of a non-financial asset takes into account a market participant’s ability to generate economic benefits by using the asset according to its highest and best use, or by selling it to another market participant that would use the asset according to its highest and best use.

We use valuation techniques that are appropriate in the circumstances and for which sufficient data is available to measure fair value, maximizing the use of relevant observable inputs and minimizing the use of unobservable inputs. All assets and liabilities for which fair value is measured or disclosed in the consolidated financial statements are categorized within the fair value hierarchy based on the transparency of input to the valuation of an asset or liability as of the measurement date.

The three input levels of the fair value hierarchy are as follows:

•Level 1 - inputs to the valuation methodology are quoted prices (unadjusted) for identical assets or liabilities in active markets.

•Level 2 - inputs to the valuation methodology include quoted prices for similar assets and liabilities in active markets, and inputs that are observable for the asset or liability either directly or indirectly, for substantially the full term of the contract.

•Level 3 - one or more inputs to the valuation methodology are unobservable or cannot be corroborated with market data.

Categorization within the fair value hierarchy is based on the lowest level of input that is significant to the fair value measurement. Certain investments are not categorized within the fair value hierarchy. These investments are measured based on the fair value of the underlying investments but may not be readily redeemable at that fair value.

Equity investments with readily determinable fair values

Equity investments with readily determinable fair valuesWe measure equity investments with readily determinable fair values at fair value, with changes in fair value reported in net income.

Derivatives and hedge accounting

Derivatives and hedge accounting

Derivatives are recognized on our consolidated balance sheets at their fair value, except for certain electricity commodity purchases and sales contracts for both capacity and energy (physical contracts) that qualify for, and are elected under, the normal purchases and normal sales exception. To be a derivative under the accounting standards for derivatives and hedging, an agreement would need to have a notional and an underlying, require little or no initial net investment and could be net settled. We recognize changes in the fair value of a derivative contract in earnings unless specific hedge accounting criteria are met.

Certain derivatives hedge specific cash flows that qualify and are designated for hedge accounting are classified as cash flow hedges. We report the gain or loss on the derivative instrument as a component of Other Comprehensive Income (OCI) and later reclassify amounts into earnings when the underlying transaction occurs, which we present in the same income statement line item as the earnings effect of the hedged item. Certain interest rate derivatives hedge a liability (i.e. debt) that qualify and are designated for hedge accounting are classified as fair value hedges. Changes in the fair value of interest rate derivatives designated as a fair value hedge and the offsetting changes in the fair value of the underlying hedged exposure (i.e. debt) are recorded in Interest expense. For all designated and qualifying hedges, we maintain formal documentation of the hedge and effectiveness testing in accordance with the accounting standards for derivatives and hedging. If we determine that the derivative is no longer highly effective as a hedge, we will discontinue hedge accounting prospectively. For cash flow hedges of forecasted transactions, we estimate the future cash flows of the forecasted transactions and evaluate the probability of the occurrence and timing of such transactions. If we determine it is probable that the forecasted transaction will not occur, we immediately recognize in earnings hedge gains and losses previously recorded in OCI.

Changes in conditions or the occurrence of unforeseen events could require discontinuance of the hedge accounting or could affect the timing of the reclassification of gains or losses on cash flow hedges from OCI into earnings. For our regulated operations, we record changes in the fair value of electric and natural gas hedge contracts derivative assets or liabilities with an offset to regulatory assets or regulatory liabilities.

We offset fair value amounts recognized for derivative instruments and fair value amounts recognized for the right to reclaim cash collateral or the obligation to return cash collateral arising from derivative instruments executed with the same counterparty under a master netting arrangement.

Cash and cash equivalents

Cash and cash equivalentsCash and cash equivalents include cash, bank accounts and other highly-liquid short-term investments. We consider all highly liquid investments with a maturity date of three months or less when acquired to be cash equivalents and include those investments in “Cash and cash equivalents.” Restricted cash represents cash legally set aside for a specified purpose or as part of an agreement with a third party. Restricted cash is included in “Other non-current assets” on our consolidated balance sheets. We classify book overdrafts representing outstanding checks in excess of funds on deposit as “Accounts payable and accrued liabilities” on our consolidated balance sheets. We report changes in book overdrafts in the operating activities section of our consolidated statements of cash flows.

Trade receivable and unbilled revenue, net of allowance for credit losses

Trade receivable and unbilled revenue, net of allowance for credit losses

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

Trade receivables include amounts due under Deferred Payment Arrangements (DPA). A DPA allows the account balance to be paid in installments over an extended period without interest, which generally exceeds one year, by negotiating mutually acceptable payment terms. The utility companies generally must continue to serve a customer who cannot pay an account balance in full if the customer (i) pays a reasonable portion of the balance; (ii) agrees to pay the balance in installments; and (iii) agrees to pay future bills within 30 days until the DPA is paid in full. Failure to make payments on a DPA results in the full amount of a receivable under a DPA being due. These accounts are part of the regular operating cycle and we classify them as short term. Due to COVID-19, the UIL companies’ regulators require them to offer to customers, through early February 2022, a 24-month repayment plan.

We establish our allowance for credit losses, including for unbilled revenue (also referred to as contract assets), by using both historical average loss percentages to project future losses, and by establishing a specific allowance for known credit issues or for specific items not considered in the historical average calculation. We consider whether we need to adjust historical loss rates to reflect the effects of current conditions and forecasted changes considering various economic indicators (e.g., Gross Domestic Product, Personal Income, Consumer Price Index, Unemployment Rate) over the contractual life of the trade receivables. We write off amounts when we have exhausted reasonable collection efforts.

Variable interest entities

Variable interest entities

An entity is considered to be a variable interest entity (VIE) when its total equity investment at risk is not sufficient to permit the entity to finance its activities without additional subordinated financial support, or its equity investors, as a group, lack the characteristics of having a controlling financial interest. A reporting company is required to consolidate a VIE as its primary beneficiary when it has both the power to direct the activities of the VIE that most significantly impact the VIE's economic performance, and the obligation to absorb losses of or the right to receive benefits from the VIE that could potentially be significant to the VIE. We evaluate whether an entity is a VIE whenever reconsideration events occur as defined by the accounting guidance (See Note 20).

We have undertaken several structured institutional partnership investment transactions that bring in external investors in certain of our wind farms in exchange for cash. Following an analysis of the economic substance of these transactions, we classify the consideration received at the inception of the arrangement as noncontrolling interests on our consolidated balance sheets. Subsequently, we use the HLBV method to allocate earnings to the noncontrolling interest, taking into consideration the cash and tax benefits provided to the tax equity investors.

Debentures, bonds and bank borrowings

Debentures, bonds and bank borrowingsWe record bonds, debentures and bank borrowings as a liability equal to the proceeds of the borrowings. We treat the difference between the proceeds and the face amount of the issued liability as discount or premium and accrete the amounts as interest expense or income over the life of the instrument. We defer incremental costs associated with the issuance of debt instruments and amortize them over the same period as debt discount or premium. We present bonds, debentures and bank borrowings net of unamortized discount, premium and debt issuance costs on our consolidated balance sheets.

Inventory

InventoryInventory comprises fuel and gas in storage and materials and supplies. Through our gas operations, we own natural gas that is stored in third-party owned underground storage facilities, which we record as inventory. We price injections of inventory into storage at the market purchase cost at the time of injection, and price withdrawals of working gas from storage at the weighted-average cost in storage. We continuously monitor the weighted-average cost of gas value to ensure it remains at the lower of cost and net realizable value. We report inventories to support gas operations on our consolidated balance sheets within “Fuel and gas in storage.”

We also have materials and supplies inventories that we use for construction of new facilities and repairs of existing facilities. These inventories are carried and withdrawn at the lower of cost and net realizable value and reported on our consolidated balance sheets within “Materials and supplies.”

In addition, stand-alone renewable energy credits that are generated or purchased and held for sale are recorded at the lower of cost or net realizable value and are reported on our consolidated balance sheets within “Materials and supplies.”

Government grants and Deferred income

Government grants

Our unregulated subsidiaries record government grants related to depreciable assets within deferred income and subsequently amortize them to earnings as an offset to depreciation and amortization expense over the useful life of the related asset. Our regulated subsidiaries record government grants as a reduction to the related utility plant to be recovered through rate base, in accordance with the prescribed FERC accounting.

In accounting for government grants related to operating and maintenance costs, we recognize amounts receivable as an offset to expenses in our consolidated statements of income in the period in which we incur the expenses.

(t) Deferred income

Apart from government grants, we occasionally receive revenues from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such revenues on our consolidated balance sheets and amortize them into earnings when revenue recognition criteria are met.

Asset retirement obligations

Asset retirement obligations

We record the fair value of the liability for an ARO and a conditional ARO in the period in which it is incurred, capitalizing the cost by increasing the carrying amount of the related long-lived asset. The ARO is associated with our long-lived assets and primarily consists of obligations related to removal or retirement of asbestos, polychlorinated biphenyl-contaminated equipment, gas pipeline, cast iron gas mains and electricity generation facilities. We adjust the liability periodically to reflect revisions to either the timing or amount of the original estimated undiscounted cash flows over time. The liability is accreted to its present value each period and the capitalized cost is depreciated over the useful life of the related asset. Upon settlement, we will either settle the obligation at its recorded amount or incur a gain or a loss. Our regulated utilities defer any timing differences between rate recovery and depreciation expense and accretion as either a regulatory asset or a regulatory liability.

The term conditional ARO refers to an entity’s legal obligation to perform an asset retirement activity in which the timing or method of settlement are conditional on a future event that may or may not be within the entity’s control. If an entity has sufficient information to reasonably estimate the fair value of the liability for a conditional ARO, it must recognize that liability at the time the liability is incurred.

Our regulated utilities meet the requirements concerning accounting for regulated operations and we recognize a regulatory liability for the difference between removal costs collected in rates and actual costs incurred. We classify these as accrued removal obligations.

Environmental remediation liability

Environmental remediation liabilityIn recording our liabilities for environmental remediation costs the amount of liability for a site is the best estimate, when determinable; otherwise it is based on the minimum liability or the lower end of the range when there is a range of estimated losses. We record our environmental liabilities on an undiscounted basis.

Post-employment and other employee benefits

Post-employment and other employee benefits

We sponsor defined benefit pension plans that cover eligible employees. We also provide health care and life insurance benefits through various postretirement plans for eligible retirees.

We evaluate our actuarial assumptions on an annual basis and consider changes based on market conditions and other factors. All of our qualified defined benefit plans are funded in amounts calculated by independent actuaries, based on actuarial assumptions proposed by management.

We account for defined benefit pension or other postretirement plans, recognizing an asset or liability for the overfunded or underfunded plan status. For a pension plan, the asset or liability is the difference between the fair value of the plan’s assets and the projected benefit obligation. For any other postretirement benefit plan, the asset or liability is the difference between the fair value of the plan’s assets and the accumulated postretirement benefit obligation. Our utility operations generally reflect all unrecognized prior service costs and credits and unrecognized actuarial gains and losses as regulatory assets rather than in other comprehensive income, as management believes it is probable that such items will be recoverable through the ratemaking

process. Certain nonqualified plan expenses are not recoverable through the ratemaking process and we present the unrecognized prior service costs and credits and unrecognized actuarial gains and losses in Accumulated Other Comprehensive Loss. We use a December 31st measurement date for our benefits plans.

We amortize prior service costs for both the pension and other postretirement benefits plans on a straight-line basis over the average remaining service period of participants expected to receive benefits. Unrecognized actuarial gains and losses related to the pension and other postretirement benefits plans are amortized over the average remaining service period or 10 years, considering any requirement by the regulators for our Networks subsidiaries. Our policy is to calculate the expected return on plan assets using the market related value of assets. That value is determined by recognizing the difference between actual returns and expected returns over a five-year period.

Income taxes

Income taxes

We use the asset and liability method of accounting for income taxes. Deferred tax assets and liabilities reflect the expected future tax consequences, based on enacted tax laws, of temporary differences between the tax basis of assets and liabilities and their financial reporting amounts. In accordance with U.S. GAAP for regulated industries, certain of our regulated subsidiaries have established a regulatory asset for the net revenue requirements to be recovered from customers for the related future tax expense associated with certain of these temporary differences. We defer the investment tax credits (ITCs) when earned and amortize them over the estimated lives of the related assets. We also recognize the income tax consequences of intra-entity transfers of assets other than inventory when the transfer occurs.

Deferred tax assets and liabilities are measured at the expected tax rate for the period in which the asset or liability will be realized or settled, based on legislation enacted as of the balance sheet date. Changes in deferred income tax assets and liabilities that are associated with components of OCI are charged or credited directly to OCI. Significant judgment is required in determining income tax provisions and evaluating tax positions. Our tax positions are evaluated under a more-likely-than-not recognition threshold before they are recognized for financial reporting purposes. We record valuation allowances to reduce deferred tax assets when it is more likely than not that we will not realize all or a portion of a tax benefit. Deferred tax assets and liabilities are netted and classified as non-current on our consolidated balance sheets.

We record the excess of state franchise tax computed as the higher of a tax based on income or a tax based on capital in “Taxes other than income taxes” and “Taxes accrued” in our consolidated financial statements.

Positions taken or expected to be taken on tax returns, including the decision to exclude certain income or transactions from a return, are recognized in the financial statements when it is more likely than not the tax position can be sustained based solely on the technical merits of the position. The amount of a tax return position that is not recognized in the financial statements is disclosed as an unrecognized tax benefit. Changes in assumptions on tax benefits may also impact interest expense or interest income and may result in the recognition of tax penalties. Interest and penalties related to unrecognized tax benefits are recorded within “Interest expense, net of capitalization” and “Other income and (expense)” in our consolidated statements of income.

Uncertain tax positions have been classified as non-current unless expected to be paid within one year. Our policy is to recognize interest and penalties on uncertain tax positions as a component of interest expense in the consolidated statements of income.

Federal production tax credits applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in income tax expense with a corresponding reduction in deferred income tax liabilities.

Our income tax expense, deferred tax assets and liabilities, and liabilities for unrecognized tax benefits reflect management’s best assessment of estimated current and future taxes to be paid. Significant judgments and estimates are required in determining the consolidated income tax components of the financial statements.

Stock-based compensation

Stock-based compensationStock-based compensation represents costs related to stock-based awards granted to employees. We account for stock-based payment transactions based on the estimated fair value of awards reflecting forfeitures when they occur. The recognition period for these costs begins at either the applicable service inception date or grant date and continues throughout the requisite service period, or until the employee becomes retirement eligible, if earlier.

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

Adoption of New Accounting Pronouncements

(a) Simplifying the accounting for income taxes

In December 2019, the FASB issued an accounting standards update that is intended to reduce complexity in accounting for income taxes. The amendments remove specific exceptions to the general principles in ASC 740, Income Taxes, eliminating the need for an entity to analyze whether the following apply in a given period: (1) exception to the incremental approach for intra-period tax allocation; (2) exceptions to accounting for basis differences in equity method investments when there are ownership changes in foreign investments; and (3) exception in interim period income tax accounting for year-to-date losses that exceed anticipated losses. The amendments also improve financial statement preparers’ application of income-tax related guidance and simplify U. S. GAAP for: (1) franchise taxes that are partially based on income; (2) transactions with a government that result in a step up in the tax basis of goodwill; (3) separate financial statements of legal entities that are not subject to tax; and (4) enacted changes in tax laws in interim periods. We adopted the amendments effective January 1, 2021, with no material effect to our consolidated results of operations, financial position, cash flows and disclosures. We are applying the amendments on a retrospective and/or modified retrospective basis, or a prospective basis, depending on the amendment requirement.

(b) Improvements to lessor accounting for certain leases with variable lease payments

In July 2021, the FASB issued amendments to make targeted improvements to ASC 842 for lessor’s accounting for certain leases with variable lease payments, which affect lease classification. The amendments require a lessor to classify and account for a lease with variable lease payments as an operating lease if (a) the lease would have been classified as a sales-type lease or a direct financing lease and (b) the lessor would have otherwise recognized a day-one loss. The amendments are effective for fiscal years beginning after December 15, 2021, for all entities, and interim periods within those fiscal years for public business entities, with early application permitted. We have elected to early apply the amendments effective October 1, 2021, and apply the amendments prospectively to leases that commence or are modified on or after that date. Our adoption does not materially affect our consolidated results of operations, financial position and cash flows.

(c) Accounting for revenue contracts with customers acquired in a business combination

In October 2021, the FASB issued amendments related to the accounting for revenue contracts acquired in a business combination. The amendments require an entity (acquirer) to recognize and measure contract assets and contract liabilities acquired in a business combination in accordance with ASC 606, Revenue from Contracts with Customers. At the acquisition date, an acquirer should account for the related revenue contract in accordance with ASC 606 as if it had originated the contracts. Generally, this should result in an acquirer recognizing and measuring the acquired contract assets and contract liabilities consistent with how they were recognized and measured in the acquiree’s financial statements. The amendments also provide certain practical expedients for acquirers when recognizing and measuring acquired contract assets and contract liabilities from revenue contracts in a business combination. For public business entities, the amendments are effective for fiscal years beginning after December 15, 2022, including interim periods within those fiscal years. The amendments should be applied prospectively to business combinations occurring on or after the effective date of the amendments. Early adoption is permitted. We have elected to early apply the amendments effective October 1, 2021. Our adoption did not materially affect our consolidated results of operations, financial position and cash flows.

Accounting Pronouncements Issued But Not Yet Adopted

The following are new accounting pronouncements not yet adopted that we have evaluated or are evaluating to determine their effect on our consolidated financial statements.

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

In March 2020, the FASB issued amendments and created ASC 848 to provide temporary optional guidance to entities to ease the potential burden in accounting for, or recognizing the effects of, reference rate reform on financial reporting. The amendments respond to concerns about structural risks of interbank offered rates, and particularly, the risk of cessation of the London Interbank Offered Rate (LIBOR). The guidance is elective and applies to all entities, subject to meeting certain criteria, that have contracts, hedging relationships, and other transactions that reference LIBOR or another reference rate expected to be discontinued due to reference rate reform, around the end of 2021. The guidance applies to contracts that have modified terms that affect, or have the potential to affect, the amount or timing of contractual cash flows resulting from the discontinuance of the reference rate reform. The amendments are effective for all entities as of March 12, 2020, through December 31, 2022, although the FASB has indicated it will monitor developments in the marketplace and consider whether developments warrant an extension.

In January 2021, the FASB issued amendments to clarify the scope of ASC 848 and respond to questions from stakeholders about whether ASC 848 can be applied to derivative instruments that do not reference a rate that is expected to be discontinued but that use an interest rate for margining, discounting, or contract price alignment that is modified because of reference rate

reform. The modification, commonly referred to as the “discounting transition,” may have accounting implications, raising concerns about the need to reassess previous accounting determinations related to those derivatives and about the possible hedge accounting consequences of the discounting transition. The amendments clarify that certain optional expedients and exceptions in ASC 848 for contract modifications and hedge accounting apply to derivatives that are affected by the discounting transition, capture the incremental consequences of the scope clarification and tailor the existing guidance to derivative instruments affected by the discounting transition. The amendments were effective immediately, and may be elected retrospectively to eligible modifications as of any date from the beginning of the interim period that includes March 12, 2020, or prospectively to new modifications made on or after any date within the interim period that includes January 7, 2021.

Our prospective adoption of ASC 848 on January 1, 2022 will not materially affect our consolidated results of operations, financial position and cash flows.

(b) Disclosures by business entities about government assistance

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

Use of Estimates and Assumptions

Use of Estimates and Assumptions

The preparation of our consolidated financial statements in conformity with U.S. GAAP requires the use of estimates and assumptions that affect the reported amounts of assets and liabilities, the disclosure of contingent assets and liabilities at the date of the consolidated financial statements, and the reported amounts of revenues and expenses during the reporting periods. Significant estimates and assumptions are used for, but not limited to: (1) allowance for credit losses and unbilled revenues; (2) asset impairments, including goodwill; (3) investments in equity instruments; (4) depreciable lives of assets; (5) income tax valuation allowances; (6) uncertain tax positions; (7) reserves for professional, workers’ compensation and comprehensive general insurance liability risks; (8) contingency and litigation reserves; (9) fair value measurements; (10) earnings sharing mechanisms; (11) environmental remediation liabilities; (12) AROs; (13) pension and other postretirement employee benefits and (14) noncontrolling interest balances. Future events and their effects cannot be predicted with certainty; accordingly, our accounting estimates require the exercise of judgment. The accounting estimates we use in the preparation of our consolidated financial statements will change as new events occur, as more experience is acquired, as additional information is obtained and as our operating environment changes. We evaluate and update our assumptions and estimates on an ongoing basis and may employ outside specialists to assist in our evaluations, as necessary. Actual results could differ from those estimates.

We continue to utilize information reasonably available to us; however, the business and economic uncertainty resulting from COVID-19 has made such estimates and assumptions more difficult to assess and calculate. Affected estimates include, but are not limited to, evaluations of certain long-lived assets and goodwill for impairment, expected credit losses and potential regulatory deferral or recovery of certain costs. While we have not yet had material effects of COVID-19 on our financial results, actual results could differ from those estimates, which could result in material effects to our consolidated financial statements in future reporting periods.

Union collective bargaining agreements

Union collective bargaining agreements

We have approximately 47.7% of our employees covered by a collective bargaining agreement. Agreements expiring in the coming year apply to approximately 18.8% of our employees.

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Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates (Tables)

12 Months Ended

Dec. 31, 2021

Accounting Policies [Abstract]

Schedule of Estimated Useful Lives

The main asset categories are depreciated over the following estimated useful lives:

Major class	Asset Category	Estimated Useful Life (years)
Plant	Combined cycle plants	35-75
	Hydroelectric power stations	45-90
	Wind power stations	25-40
	Solar power stations	25
	Transmission and transport facilities	41-80
	Distribution facilities	4-80
Equipment	Conventional meters and measuring devices	7-85
	Computer software	3-37
Other	Buildings	30-82
	Operations offices	3-75

Property, plant and equipment as of December 31, 2021, consisted of:

As of December 31, 2021	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	17,392	$	13,446	$	30,838
Natural gas transportation, distribution and other	5,032		13		5,045
Other common operating property	—		286		286
Total Property, Plant and Equipment in Service	22,424		13,745		36,169
Total accumulated depreciation	(5,806)		(4,783)		(10,589)
Total Net Property, Plant and Equipment in Service	16,618		8,962		25,580
Construction work in progress	2,064		1,222		3,286
Total Property, Plant and Equipment	$	18,682	$	10,184	$	28,866

Property, plant and equipment as of December 31, 2020, consisted of:

As of December 31, 2020	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	16,364	$	12,854	$	29,218
Natural gas transportation, distribution and other	4,637		13		4,650
Other common operating property	—		274		274
Total Property, Plant and Equipment in Service	21,001		13,141		34,142
Total accumulated depreciation	(5,363)		(4,436)		(9,799)
Total Net Property, Plant and Equipment in Service	15,638		8,705		24,343
Construction work in progress	1,384		1,024		2,408
Total Property, Plant and Equipment	$	17,022	$	9,729	$	26,751

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Revenue (Tables)

12 Months Ended

Dec. 31, 2021

Revenue from Contract with Customer [Abstract]

Schedule of Revenues Disaggregated by Major Source for Reportable Segments

Revenues disaggregated by major source for our reportable segments for the years ended December 31, 2021, 2020 and 2019 are as follows:

	Year Ended December 31, 2021
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	4,015	$	—	$	—	$	4,015
Regulated operations – natural gas	1,516		—		—		1,516
Nonregulated operations – wind	—		1,028		—		1028
Nonregulated operations – solar	—		20		—		20
Nonregulated operations – thermal	—		63		—		63
Other (a)	67		84		—		151
Revenue from contracts with customers	5,598		1,195		—		6,793
Leasing revenue	7		—		—		7
Derivative revenue	—		3		—		3
Alternative revenue programs	115		—		—		115
Other revenue	34		22		—		56
Total operating revenues	$	5,754	$	1,220	$	—	$	6,974

	Year Ended December 31, 2020
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	3,642	$	—	$	—	$	3,642
Regulated operations – natural gas	1,311		—		—		1,311
Nonregulated operations – wind	—		822		—		822
Nonregulated operations – solar	—		19		—		19
Nonregulated operations – thermal	—		39		—		39
Other (a)	58		101		—		159
Revenue from contracts with customers	5,011		981		—		5,992
Leasing revenue	6		—		—		6
Derivative revenue	—		136		—		136
Alternative revenue programs	157		—		—		157
Other revenue	14		15		—		29
Total operating revenues	$	5,188	$	1,132	$	—	$	6,320

	Year Ended December 31, 2019
	Networks		Renewables		Other (b)		Total
(Millions)
Regulated operations – electricity	$	3,485	$	—	$	—	$	3,485
Regulated operations – natural gas	1,479		—		—		1,479
Nonregulated operations – wind	—		803		—		803
Nonregulated operations – solar	—		26		—		26
Nonregulated operations – thermal	—		29		—		29
Other (a)	91		62		(12)		141
Revenue from contracts with customers	5,055		920		(12)		5,963
Leasing revenue	6		—		—		6
Derivative revenue	—		244		—		244
Alternative revenue programs	75		—		—		75
Other revenue	28		20		—		48
Total operating revenues	$	5,164	$	1,184	$	(12)	$	6,336

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

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

Schedule of Aggregate Transaction Price Allocations

As of December 31, 2021, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:

As of December 31, 2021	2022		2023		2024		2025		2026		Thereafter		Total
(Millions)
Revenue expected to be recognized on multiyear retail energy sales contracts in place	$	6	$	1	$	1	$	—	$	—	$	—	$	8
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts	39		24		9		2		3		2		79
Revenue expected to be recognized on multiyear renewable energy credit sale contracts	26		18		14		12		10		65		145
Total operating revenues	$	71	$	43	$	24	$	14	$	13	$	67	$	232

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Industry Regulation (Tables)

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Schedule of Delivery Rate Increases

The delivery rate increases for the last year of the 2016 Joint Proposal can be summarized as follows:

	May 1, 2018
	Rate Increase		Delivery Rate Increase
Utility	(Millions)		%
NYSEG Electric	$	30	4.10	%
NYSEG Gas	$	15	7.30	%
RG&E Electric	$	26	5.70	%
RG&E Gas	$	10	5.20	%

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 Increase		Rate Increase		Delivery Rate Increase		Rate Increase		Delivery Rate Increase
Utility	(Millions)		%		(Millions)		%		(Millions)		%
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	%

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Regulatory Assets and Liabilities (Tables)

12 Months Ended

Dec. 31, 2021

Regulated Operations [Abstract]

Schedule of Regulatory Assets

Regulatory assets as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Pension and other post-retirement benefits	$	545	$	927
Pension and other post-retirement benefits cost deferrals	95		105
Storm costs	448		451
Rate adjustment mechanism	68		33
Revenue decoupling mechanism	68		58
Transmission revenue reconciliation mechanism	15		31
Contracts for differences	73		86
Hardship programs	24		20
Plant decommissioning	2		3
Deferred purchased gas	52		30
Deferred transmission expense	13		26
Environmental remediation costs	256		247
Debt premium	71		83
Unamortized losses on reacquired debt	23		26
Unfunded future income taxes	424		373
Federal tax depreciation normalization adjustment	142		148
Asset retirement obligation	20		21
Deferred meter replacement costs	46		33
COVID-19 cost recovery	21		1
Other	241		180
Total regulatory assets	2,647		2,882
Less: current portion	400		310
Total non-current regulatory assets	$	2,247	$	2,572

Schedule of Regulatory Liabilities

Regulatory liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Energy efficiency portfolio standard	$	45	$	58
Gas supply charge and deferred natural gas cost	7		3
Pension and other post-retirement benefits cost deferrals	73		59
Carrying costs on deferred income tax bonus depreciation	23		34
Carrying costs on deferred income tax - Mixed Services 263(a)	7		11
2017 Tax Act	1,327		1,435
Rate change levelization	99		55
Revenue decoupling mechanism	13		9
Accrued removal obligations	1,192		1,184
Asset sale gain account	2		7
Economic development	26		28
Positive benefit adjustment	22		30
Theoretical reserve flow thru impact	6		10
Deferred property tax	22		31
Net plant reconciliation	16		20
Debt rate reconciliation	49		63
Rate refund – FERC ROE proceeding	35		33
Transmission congestion contracts	23		22
Merger-related rate credits	12		14
Accumulated deferred investment tax credits	24		25
Asset retirement obligation	18		18
Earnings sharing provisions	13		17
Middletown/Norwalk local transmission network service collections	17		18
Low income programs	25		28
Non-firm margin sharing credits	15		14
New York 2018 winter storm settlement	5		9
Hedges gains	19		—
Other	194		176
Total regulatory liabilities	3,329		3,411
Less: current portion	307		274
Total non-current regulatory liabilities	$	3,022	$	3,137

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Goodwill and Intangible assets (Tables)

12 Months Ended

Dec. 31, 2021

Goodwill and Intangible Assets Disclosure [Abstract]

Schedule of Goodwill by Reportable Segment

Goodwill by reportable segment as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Networks	$	2,747	$	2,747
Renewables	372		372
Total	$	3,119	$	3,119

Schedule of Intangible Assets Acquired and Developed

Intangible assets include those assets acquired in business acquisitions and intangible assets acquired and developed from external third parties and from affiliated companies. Following is a summary of intangible assets as of December 31, 2021 and 2020:

As of December 31, 2021	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
(Millions)
Wind development	$	592	$	(301)	$	291
Other	18		(16)		2
Total Intangible Assets	$	610	$	(317)	$	293

As of December 31, 2020	Gross Carrying Amount		Accumulated Amortization		Net Carrying Amount
(Millions)
Wind development	$	593	$	(290)	$	303
Other	31		(29)		2
Total Intangible Assets	$	624	$	(319)	$	305

Schedule of Expect Amortization Expense

We expect amortization expense for the five years subsequent to December 31, 2021, to be as follows:

Year ending December 31,	Amount
(Millions)
2022	$	14
2023	$	13
2024	$	13
2025	$	12
2026	$	12

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Property, Plant and Equipment (Tables)

12 Months Ended

Dec. 31, 2021

Property, Plant and Equipment [Abstract]

Schedule of Property, Plant and Equipment

The main asset categories are depreciated over the following estimated useful lives:

Major class	Asset Category	Estimated Useful Life (years)
Plant	Combined cycle plants	35-75
	Hydroelectric power stations	45-90
	Wind power stations	25-40
	Solar power stations	25
	Transmission and transport facilities	41-80
	Distribution facilities	4-80
Equipment	Conventional meters and measuring devices	7-85
	Computer software	3-37
Other	Buildings	30-82
	Operations offices	3-75

Property, plant and equipment as of December 31, 2021, consisted of:

As of December 31, 2021	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	17,392	$	13,446	$	30,838
Natural gas transportation, distribution and other	5,032		13		5,045
Other common operating property	—		286		286
Total Property, Plant and Equipment in Service	22,424		13,745		36,169
Total accumulated depreciation	(5,806)		(4,783)		(10,589)
Total Net Property, Plant and Equipment in Service	16,618		8,962		25,580
Construction work in progress	2,064		1,222		3,286
Total Property, Plant and Equipment	$	18,682	$	10,184	$	28,866

Property, plant and equipment as of December 31, 2020, consisted of:

As of December 31, 2020	Regulated		Nonregulated		Total
(Millions)
Electric generation, distribution, transmission and other	$	16,364	$	12,854	$	29,218
Natural gas transportation, distribution and other	4,637		13		4,650
Other common operating property	—		274		274
Total Property, Plant and Equipment in Service	21,001		13,141		34,142
Total accumulated depreciation	(5,363)		(4,436)		(9,799)
Total Net Property, Plant and Equipment in Service	15,638		8,705		24,343
Construction work in progress	1,384		1,024		2,408
Total Property, Plant and Equipment	$	17,022	$	9,729	$	26,751

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Asset retirement obligations (Tables)

12 Months Ended

Dec. 31, 2021

Table Text Block Supplement [Abstract]

Schedule of Asset Retirement Obligations

The reconciliation of ARO carrying amounts for the years ended December 31, 2021 and 2020 consisted of:

(Millions)
As of December 31, 2019	$	190
Liabilities settled during the year	(2)
Liabilities incurred during the year	9
Accretion expense	11
Revisions in estimated cash flows (a)	2
As of December 31, 2020	$	210
Liabilities settled during the year	(2)
Liabilities incurred during the year	7
Accretion expense	12
Revisions in estimated cash flows (a)	26
As of December 31, 2021	$	253

(a)Represents an increase in our estimate of expected cash flows required for retirement activities related to our renewable energy facilities.

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Debt (Tables)

12 Months Ended

Dec. 31, 2021

Debt Disclosure [Abstract]

Schedule of Long-term Debt

Long-term debt as of December 31, 2021 and 2020 consisted of:

As of December 31,		2021			2020
	Maturity Dates	Balances		Interest Rates	Balances		Interest Rates
(Millions)
First mortgage bonds - fixed (a)	2022-2051	$	2,759	1.85%-8.00%	$	2,575	1.85%-8.00%
Unsecured pollution control notes - fixed	2023-2029	478		1.40%-3.50%	478		1.40%-3.50%
Other various non-current debt - fixed	2022-2050	5,110		1.95%-6.66%	4,785		1.95%-7.80%
Unamortized debt issuance costs and discount		(53)			(47)
Total Debt		8,294			7,791
Less: debt due within one year, included in current liabilities		372			313
Total Non-current Debt		$	7,922		$	7,478

(a)The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $7,871 million.

Other 2021 Long-Term Debt Issuances

Company	Issue Date	Type	Amount (Millions)		Interest rate		Maturity
NYSEG	9/24/2021	Unsecured Notes	$	350	2.15	%	2031
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.91	%	2051
RG&E	12/15/2021	First Mortgage Bonds	$	125	2.10	%	2031
CMP	12/15/2021	First Mortgage Bonds	$	200	2.05	%	2031
SCG	12/15/2021	First Mortgage Bonds	$	40	2.05	%	2031

Schedule of Maturities and Repayments of Long-term Debt

Long-term debt maturities, including sinking fund obligations, due over the next five years consist of:

2022		2023		2024		2025		2026		Total
(Millions)
$	372	$	439	$	612	$	1,107	$	660	$	3,190

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

12 Months Ended

Dec. 31, 2021

Fair Value Disclosures [Abstract]

Schedule of Fair Value Measurements

The financial instruments measured at fair value as of December 31, 2021 and 2020 consisted of:

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

As of December 31, 2020	Level 1		Level 2		Level 3		Netting		Total
(Millions)
Equity and other investments with readily determinable fair values	$	49	$	14	$	—	$	—	$	63
Derivative assets
Derivative financial instruments - power	$	5	$	31	$	105	$	(54)	$	87
Derivative financial instruments - gas	—		24		19		(35)		8
Contracts for differences	—		—		2		—		2
Total	$	5	$	55	$	126	$	(89)	$	97
Derivative liabilities
Derivative financial instruments - power	$	(23)	$	(31)	$	(23)	$	72	$	(5)
Derivative financial instruments - gas	(1)		(9)		(2)		9		(3)
Contracts for differences	—		—		(88)		—		(88)
Derivative financial instruments – Other	—		—		—		—		—
Total	$	(24)	$	(40)	$	(113)	$	81	$	(96)

Fair Value, Financial instrument Based on Level 3 Reconciliation

The reconciliation of changes in the fair value of financial instruments based on Level 3 inputs for the years ended December 31, 2021, 2020 and 2019 consisted of:

(Millions)	2021		2020		2019
Fair value as of January 1,	$	13	$	25	$	(15)
Gains for the year recognized in operating revenues	21		8		53
Losses for the year recognized in operating revenues	(34)		(2)		(2)
Total gains or losses for the period recognized in operating revenues	(13)		6		51
Gains recognized in OCI	2		1		2
Losses recognized in OCI	(52)		(3)		(3)
Total gains or losses recognized in OCI	(50)		(2)		(1)
Net change recognized in regulatory assets and liabilities	13		6		5
Purchases	(17)		(2)		(22)
Settlements	(13)		(15)		4
Transfers out of Level 3 (a)	(2)		(5)		3
Fair value as of December 31,	$	(69)	$	13	$	25
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$	(13)	$	6	$	51

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

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

	Range at
Unobservable Input	December 31, 2021
Risk of non-performance	0.39% - 0.51%
Discount rate	0.97% - 1.26%
Forward pricing ($ per KW-month)	$2.00 - $4.80

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

The table below illustrates the significant sources of unobservable inputs used in the fair value measurement of our Level 3 derivatives and the variability in prices for those transactions classified as Level 3 derivatives as of December 31, 2021.

Index	Avg.		Max.		Min.
NYMEX ($/MMBtu)	$	3.18	$	6.52	$	2.27
AECO ($/MMBtu)	$	2.41	$	5.69	$	1.53
Ameren ($/MWh)	$	32.23	$	93.59	$	18.01
COB ($/MWh)	$	46.83	$	231.90	$	9.15
ComEd ($/MWh)	$	29.60	$	86.32	$	14.98
ERCOT N hub ($/MWh)	$	35.05	$	140.00	$	13.66
ERCOT S hub ($/MWh)	$	34.24	$	140.00	$	13.88
Indiana hub ($/MWh)	$	34.20	$	93.81	$	20.74
Mid C ($/MWh)	$	43.53	$	229.90	$	5.15
Minn hub ($/MWh)	$	28.82	$	90.99	$	15.23
NoIL hub ($/MWh)	$	29.35	$	84.00	$	14.64
PJM W hub ($/MWh)	$	33.49	$	113.93	$	17.78

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Derivative Instruments and Hedging (Tables)

12 Months Ended

Dec. 31, 2021

Derivative Instruments and Hedging Activities Disclosure [Abstract]

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

The tables below present Networks' derivative positions as of December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative positions on our consolidated balance sheets:

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

As of December 31, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	3	$	5	$	3	$	3
Derivative liabilities	(3)		(4)		(34)		(78)
	—		1		(31)		(75)
Designated as hedging instruments
Derivative assets	—		—		—		—
Derivative liabilities	—		—		(1)		—
	—		—		(1)		—
Total derivatives before offset of cash collateral	—		1		(32)		(75)
Cash collateral receivable	—		—		18		1
Total derivatives as presented in the balance sheet	$	—	$	1	$	(14)	$	(74)

The tables below present Renewables' derivative positions as of December 31, 2021 and 2020, respectively, including those subject to master netting agreements and the location of the net derivative position on our consolidated balance sheets:

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

As of December 31, 2020	Current Assets		Noncurrent Assets		Current Liabilities		Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets	$	47	$	89	$	2	$	9
Derivative liabilities	(23)		(2)		(4)		(11)
	24		87		(2)		(2)
Designated as hedging instruments
Derivative assets	8		15		2		7
Derivative liabilities	(5)		(6)		(3)		(10)
	3		9		(1)		(3)
Total derivatives before offset of cash collateral	27		96		(3)		(5)
Cash collateral (payable) receivable	(9)		(18)		—		—
Total derivatives as presented in the balance sheet	$	18	$	78	$	(3)	$	(5)

Schedule of Notional Volumes of Outstanding Derivative Positions

The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021	2020
(Millions)
Wholesale electricity purchase contracts (MWh)	5.7	5.6
Natural gas purchase contracts (Dth)	9.4	9.5
Fleet fuel purchase contracts (Gallons)	2.0	2.5

The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021	2020
(MWh/Dth in Millions)
Wholesale electricity purchase contracts	4	3
Wholesale electricity sales contracts	10	7
Natural gas and other fuel purchase contracts	20	24
Financial power contracts	9	12
Basis swaps - purchases	30	35
Basis swaps - sales	—	2

Summary of Unrealized Gains and Losses from Fair Value Adjustments

The amounts for electricity hedge contracts and natural gas hedge contracts recognized in regulatory liabilities and assets as of December 31, 2021 and 2020 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2021, 2020 and 2019 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						For the Year Ended December 31,
December 31, 2021	Electricity		Natural Gas		2021	Electricity		Natural Gas
Regulatory assets	$	—	$	—	Purchased power, natural gas and fuel used	$	(23)	$	(11)
Regulatory liabilities	$	(16)	$	(3)
December 31, 2020					2020
Regulatory assets	$	17	$	1	Purchased power, natural gas and fuel used	$	55	$	4
Regulatory liabilities	$	—	$	—
					2019
					Purchased power, natural gas and fuel used	$	25	$	1

The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2021, 2020 and 2019, respectively, were as follows:

	Years Ended December 31,
	2021		2020		2019
(Millions)
Derivative Assets	$	—	$	—	$	(3)
Derivative Liabilities	$	13	$	6	$	8

Derivative Instruments, Gain (Loss)

The effect of derivatives in cash flow hedging relationships on OCI and income for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Year Ended December 31,	(Loss) Gain Recognized in OCI on Derivatives (a)		Location of Loss Reclassified from Accumulated OCI into Income	Loss (Gain) Reclassified from Accumulated OCI into Income		Total amount per Income Statement
(Millions)
2021
Interest rate contracts	$	—	Interest expense	$	4	$	298
Commodity contracts	2		Purchased power, natural gas and fuel used	(1)		1,719
Foreign currency exchange contracts	(5)			—
Total	$	(3)		$	3
2020
Interest rate contracts	$	—	Interest expense	$	4	$	316
Commodity contracts	(1)		Purchased power, natural gas and fuel used	1		1,379
Foreign currency exchange contracts	1			—
Total	$	—		$	5
2019
Interest rate contracts	$	—	Interest expense	$	6	$	310
Commodity contracts	—		Purchased power, natural gas and fuel used	1		1,509
Foreign currency exchange contracts	(1)			—
Total	$	(1)		$	7

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

The effect of derivatives in cash flow hedging relationships on accumulated OCI and income for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 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)
2021
Interest rate contracts	$	(58)	Interest Expense	$	—	$	298
Commodity contracts	$	(142)	Operating revenues	$	(3)	$	6,974
Total	$	(200)		$	(3)
2020
Commodity contracts	$	1	Operating revenues	$	6	$	6,320
2019
Commodity contracts	$	(5)	Operating revenues	$	3	$	6,336

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

The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 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)
2021
Interest rate contracts	$	—	Interest expense	$	9	$	298
2020
Interest rate contracts	$	(27)	Interest expense	$	8	$	316
2019
Interest rate contracts	$	(24)	Interest expense	$	2	$	310

(a)Changes in OCI are reported on a pre-tax basis. The amounts in accumulated OCI are being reclassified into earnings over the underlying debt maturity periods which end in 2025 and 2029.

Schedule of Fair Value, Net Derivative Contracts

The fair values of derivative contracts associated with Renewables' activities as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021		2020
(Millions)
Wholesale electricity purchase contracts	$	36	$	4
Wholesale electricity sales contracts	(77)		11
Natural gas and other fuel purchase contracts	6		—
Financial power contracts	35		66
Basis swaps - purchases	—		7
Total	$	—	$	88

Schedule of Effects of Trading and Non-Trading Derivatives

The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Year Ended December 31, 2021
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	1	$	(1)
Wholesale electricity sales contracts	(2)		(33)
Financial power contracts	4		(42)
Financial and natural gas contracts	(1)		(25)
Total loss included in operating revenues	$	2	$	(101)	$	6,974
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	32
Financial and natural gas contracts	—		12
Total gain included in purchased power, natural gas and fuel used	$	—	$	44	$	1,719
Total Gain (Loss)	$	2	$	(57)

	Year Ended December 31, 2020
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	—
Wholesale electricity sales contracts	(1)		6
Financial power contracts	2		—
Financial and natural gas contracts	—		(13)
Total (loss) gain included in operating revenues	$	—	$	(7)	$	6,320
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts	$	—	$	(4)
Financial and natural gas contracts	—		6
Total gain included in purchased power, natural gas and fuel used	$	—	$	2	$	1,379
Total Loss	$	—	$	(5)

	Year Ended December 31, 2019
	Trading		Non-trading		Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts	$	(1)	$	—
Wholesale electricity sales contracts	3		40
Financial power contracts	(3)		23
Financial and natural gas contracts	(1)		1
Total (loss) gain included in operating revenues	$	(2)	$	64	$	6,336
Purchased power, natural gas and fuel used
Financial power contracts	—		(1)
Financial and natural gas contracts	—		15
Total gain included in purchased power, natural gas and fuel used	$	—	$	14	$	1,509
Total (Loss) Gain	$	(2)	$	78

Schedule of Fair Value Hedging Instruments

The effects on our consolidated financial statements as of and for the year ended December 31, 2021 are as follows:

(millions)	Fair value of hedge		Location of (Gain) Recognized in Income Statement	(Gain) Recognized in Income Statement		Year to date total per Income Statement
As of December 31, 2021				Year Ended December 31, 2021
Current Assets	$	—	Interest Expense	$	(3)	$	298
Non-current liabilities	$	(19)
	Cumulative effect on hedged debt
Current debt	$	—
Non-current debt	$	19

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Leases (Tables)

12 Months Ended

Dec. 31, 2021

Leases [Abstract]

Lease, Cost

The components of lease cost for the years ended December 31, 2021, 2020 and 2019 were as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Lease cost
Finance lease cost
Amortization of right-of-use assets	$	8	$	17	$	12
Interest on lease liabilities	3		4		3
Total finance lease cost	11		21		15
Operating lease cost	14		16		18
Short-term lease cost	4		3		5
Variable lease cost	4		—		2
Sublease income	—		—		—
Total lease cost	$	33	$	40	$	40

For the years ended December 31, 2021, 2020 and 2019 supplemental cash flow information related to leases was as follows:

For the Year Ended December 31,	2021		2020		2019
(Millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$	16	$	13	$	13
Operating cash flows from finance leases	$	3	$	3	$	3
Financing cash flows from finance leases	$	6	$	9	$	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	$	—	$	46	$	1
Operating leases	$	10	$	94	$	3

Assets And Liabilities, Lessee

Balance sheet and other information as of December 31, 2021 and 2020 was as follows:

As of December 31,	2021			2020
(Millions, except lease term and discount rate)
Operating Leases
Operating lease right-of-use assets	$	148		$	153
Operating lease liabilities, current	12			8
Operating lease liabilities, long-term	149			154
Total operating lease liabilities	$	161		$	162
Finance Leases
Other assets	$	156		$	162
Other current liabilities	4			8
Other non-current liabilities	91			91
Total finance lease liabilities	$	95		$	99
Weighted-average Remaining Lease Term (years)
Finance leases	7.3			8.12
Operating leases	20.5			21.38
Weighted-average Discount Rate
Finance leases	3.49		%	3.71		%
Operating leases	3.06		%	3.21		%

Finance Lease Maturity

As of December 31, 2021, maturities of lease liabilities were as follows:

	Finance Leases		Operating Leases
(Millions)
Year ending December 31,
2022	$	5	$	14
2023	53		14
2024	23		12
2025	2		11
2026	2		11
Thereafter	19		160
Total lease payments	104		223
Less: imputed interest	(9)		(62)
Total	$	95	161

Operating Lease Maturity

As of December 31, 2021, maturities of lease liabilities were as follows:

	Finance Leases		Operating Leases
(Millions)
Year ending December 31,
2022	$	5	$	14
2023	53		14
2024	23		12
2025	2		11
2026	2		11
Thereafter	19		160
Total lease payments	104		223
Less: imputed interest	(9)		(62)
Total	$	95	161

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Commitments and Contingent Liabilities (Tables)

12 Months Ended

Dec. 31, 2021

Commitments and Contingencies Disclosure [Abstract]

Forward Purchase and Sales Commitment Arrangement

Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2021 consisted of:

Year	Purchases		Sales
	(Millions)
2022	$	1,069	$	227
2023	168		122
2024	111		75
2025	65		28
2026	49		37
Thereafter	971		72
Totals	$	2,433	$	561

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Income Taxes (Tables)

12 Months Ended

Dec. 31, 2021

Income Tax Disclosure [Abstract]

Schedule of Current and Deferred Taxes Charged to (Benefit) Expense

Current and deferred taxes charged to expense for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 31,	2021		2020		2019
(Millions)
Current
Federal	$	6	$	3	$	11
State	4		9		(6)
Current taxes charged to expense	10		12		5
Deferred
Federal	49		67		164
State	72		38		58
Deferred taxes charged to expense	121		105		222
Production tax credits	(109)		(87)		(57)
Investment tax credits	(1)		(1)		(1)
Total Income Tax Expense	$	21	$	29	$	169

Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate

The differences between tax expense per the statements of income and tax expense at the 21% statutory federal tax rate for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years Ended December 31,	2021		2020		2019
(Millions)
Tax expense at federal statutory rate	$	140	$	119	$	170
Depreciation and amortization not normalized	(19)		(13)		(23)
Investment tax credit amortization	(1)		(1)		(1)
Tax return related adjustments	—		1		(2)
Production tax credits	(109)		(87)		(57)
Tax equity financing arrangements	14		1		8
State tax expense (benefit), net of federal benefit	61		37		41
Excess ADIT amortization	(65)		(42)		—
Valuation allowance	21		12		4
Other, net	(21)		2		29
Total Income Tax Expense	$	21	$	29	$	169

Schedule of Deferred Tax Assets and Liabilities

Deferred tax assets and liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Deferred Income Tax Liabilities (Assets)
Property related	$	4,257	$	4,147
Unfunded future income taxes	104		100
Federal and state tax credits	(844)		(731)
Federal and state NOL’s	(998)		(1,047)
Joint ventures/partnerships	188		167
Nontaxable grant revenue	(292)		(311)
Pension and other post-retirement benefits	1		22
Tax Act - tax on regulatory remeasurement	(352)		(382)
Valuation allowance	110		81
Other	(158)		(127)
Deferred Income Tax Liabilities	$	2,016	$	1,919
Deferred tax assets	$	2,644	$	2,598
Deferred tax liabilities	4,660		4,517
Net Accumulated Deferred Income Tax Liabilities	$	2,016	$	1,919

Schedule of Reconciliation of Unrecognized Income Tax Benefits

The reconciliation of unrecognized income tax benefits for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years ended December 31,	2021		2020		2019
(Millions)
Beginning Balance	$	127	$	148	$	153
Increases for tax positions related to prior years	3		11		14
Increases for tax positions related to current year	—		—		16
Decreases for tax positions related to prior years	(3)		(32)		(18)
Reduction for tax position related to settlements with taxing authorities	—		—		(17)
Ending Balance	$	127	$	127	$	148

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Post-retirement and Similar Obligations (Tables)

12 Months Ended

Dec. 31, 2021

Retirement Benefits [Abstract]

Obligations and Funded Status

As of December 31, 2021 and 2020, our obligations and funded status consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
(Millions)
Change in benefit obligation
Benefit Obligation as of January 1,	$	3,819	$	3,669	$	452	$	439
Service cost	40		47		3		3
Interest cost	87		107		10		13
Plan amendments	2		7		—		—
Actuarial loss (gain)	(184)		236		(23)		29
Curtailments	(38)		(21)		—		—
Benefits paid	(239)		(226)		(34)		(32)
Benefit Obligation as of December 31,	3,487		3,819		408		452
Change in plan assets
Fair Value of Plan Assets as of January 1,	3,092		2,848		167		155
Actual return on plan assets	237		388		15		26
Employer contributions	27		84		12		18
Curtailments	(38)		(2)		—		—
Benefits paid	(239)		(226)		(67)		(32)
Fair Value of Plan Assets as of December 31,	3,079		3,092		127		167
Funded Status as of December 31,	$	(408)	$	(727)	$	(281)	$	(285)

Schedule of Amounts Recognized in Balance Sheet

As of December 31, 2021 and 2020, funded status amounts recognized on our consolidated balance sheets consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
(Millions)
Current liabilities	$	—	$	—	$	(5)	$	(5)
Non-current liabilities	(408)		(727)		(276)		(280)
Total	$	(408)	$	(727)	$	(281)	$	(285)

Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations

Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2021 and 2020 consisted of:

	Pension Benefits				Postretirement Benefits
Years Ended December 31,	2021		2020		2021		2020
(Millions)
Net loss (gain)	$	271	$	610	$	(18)	$	14
Prior service cost (credit)	$	10	$	10	$	(1)	$	(8)

Components of Networks’ net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and regulatory assets and liabilities for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
For the years ended December 31,	2021		2020		2019		2021		2020		2019
(Millions)
Net Periodic Benefit Cost:
Service cost	$	39	$	46	$	41	$	3	$	3	$	3
Interest cost	86		106		128		10		13		16
Expected return on plan assets	(199)		(198)		(190)		(7)		(8)		(7)
Amortization of prior service cost (benefit)	2		1		(1)		(5)		(9)		(10)
Amortization of net loss	115		124		113		2		2		1
Settlement charge	6						—
Net Periodic Benefit Cost	49		79		91		3		1		3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	—		(18)		—		—		—		—
Settlement charge	(6)		—		—		—		—		—
Net loss (gain)	(218)		46		80		(31)		11		13
Amortization of net loss	(115)		(124)		(113)		(2)		(2)		(1)
Current year prior service cost (credit)	2		7		(2)		1		—		—
Amortization of prior service (cost) benefit	(2)		(1)		1		5		9		10
Total Other Changes	(339)		(90)		(34)		(27)		18		22
Total Recognized	$	(290)	$	(11)	$	57	$	(24)	$	19	$	25

Components of ARHI’s net periodic benefit cost and other changes in plan assets and benefit obligations recognized in income and OCI for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
For the years ended December 31,	2021		2020		2019		2021		2020		2019
(Millions)
Net Periodic Benefit Cost:
Service cost	$	1	$	1	$	1	$	—	$	—	$	—
Interest cost	1		1		2		—		—		—
Expected return on plan assets	(2)		(2)		(2)		—		—		—
Amortization of net loss (gain)	2		2		1		(1)		(1)		(1)
Settlement charge	1		1		—		—		—		—
Net Periodic Benefit Cost	3		3		2		(1)		(1)		(1)
Other Changes in plan assets and benefit obligations recognized in OCI:
Settlement charge	(1)		—		—		(1)		—		—
Net loss (gain)	(3)		1		—		1		—		—
Amortization of net (loss) gain	(2)		(2)		(1)		1		1		1
Amortization of prior service cost	—		—		—		—		—		(2)
Total Other Changes	(6)		(1)		(1)		1		1		(1)
Total Recognized	$	(3)	$	2	$	1	$	—	$	—	$	(2)

Summary of Amounts Recognized in OCI

Amounts recognized in OCI for ARHI for the years ended December 31, 2021 and 2020, consisted of:

	Pension Benefits				Postretirement Benefits
Years Ended December 31,	2021		2020		2021		2020
(Millions)
Net loss (gain)	$	16	$	21	$	(5)	$	(7)

Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans

	PBO in excess of plan assets
As of December 31,	2021		2020
(Millions)
Projected benefit obligation	$	3,487	$	3,819
Fair value of plan assets	$	3,079	$	3,092
	ABO in excess of plan assets
As of December 31,	2021		2020
(Millions)
Accumulated benefit obligation	$	1,790	$	3,629
Fair value of plan assets	$	1,536	$	3,092

Weighted Average Assumptions Used to Determine Benefit Obligations and Net periodic Benefit Cost

The weighted-average assumptions used to determine our benefit obligations as of December 31, 2021 and 2020 consisted of:

	Pension Benefits				Postretirement Benefits
As of December 31,	2021		2020		2021		2020
Discount rate	2.85	%	2.34	%	2.66	%	2.19	%
Rate of compensation increase	3.53	%	3.52	%	3.50	%	3.50	%
Interest crediting rate	2.87	%	2.87	%	N/A		N/A

The weighted-average assumptions used to determine our net periodic benefit cost for the years ended December 31, 2021, 2020 and 2019 consisted of:

	Pension Benefits						Postretirement Benefits
Years Ended December 31,	2021		2020		2019		2021		2020		2019
Discount rate	2.34	%	3.01	%	3.98	%	2.19	%	2.99	%	3.97	%
Expected long-term return on plan assets	7.30	%	7.30	%	7.30	%	4.05	%	5.09	%	5.08	%
Rate of compensation increase	3.52	%	3.66	%	3.79	%	3.50	%	3.48	%	3.50	%

Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations

Assumed health care cost trend rates used to determine benefit obligations as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
Health care cost trend rate assumed for next year	5.00%/7.00%		5.25%/7.25%
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50	%	4.50	%
Year that the rate reaches the ultimate trend rate	2029 / 2025		2029 / 2025

Expected Future Benefits Payments

Expected benefit payments as of December 31, 2021 consisted of:

(Millions)	Pension Benefits		Postretirement Benefits
2022	$	217	$	30
2023	$	212	$	29
2024	$	214	$	29
2025	$	213	$	28
2026	$	215	$	27
2027 - 2031	$	1,057	$	122

Fair Values of Pension Plan Assets, by Asset Category

The fair values of pension plan assets, by asset category, as of December 31, 2021, consisted of:

As of December 31, 2021			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	69	$	20	$	49	$	—
U.S. government securities	298		298		—		—
Common stocks	138		138		—		—
Registered investment companies	276		276		—		—
Corporate bonds	837		—		837		—
Preferred stocks	1		1		—		—
Common collective trusts	862		—		862		—
Other, principally annuity, fixed income	51		—		51		—
	$	2,532	$	733	$	1,799	$	—
Other investments measured at net asset value	547
Total	$	3,079

The fair values of pension plan assets, by asset category, as of December 31, 2020, consisted of:

As of December 31, 2020			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	120	$	—	$	120	$	—
U.S. government securities	177		177		—		—
Common stocks	107		107		—		—
Registered investment companies	301		301		—		—
Corporate bonds	710		—		710		—
Preferred stocks	1		1		—		—
Common collective trusts	1,018		—		1,018		—
Other, principally annuity, fixed income	50		6		44		—
	$	2,484	$	592	$	1,892	$	—
Other investments measured at net asset value	608
Total	$	3,092

Fair Value of Other Postretirement Plan Assets, by Asset Category

The fair values of other postretirement plan assets, by asset category, as of December 31, 2021 consisted of:

As of December 31, 2021			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	5	$	—	$	5	$	—
U.S. government securities	1		1		—		—
Common stocks	1		1		—		—
Registered investment companies	101		101		—		—
Corporate bonds	3		—		3		—
Preferred stocks	—		—		—		—
Common collective trusts	5		—		5		—
Other, principally annuity, fixed income	9		—		9		—
	$	125	$	103	$	22	$	—
Other investments measured at net asset value	2
Total	$	127

The fair values of other postretirement plan assets, by asset category, as of December 31, 2020 consisted of:

As of December 31, 2020			Fair Value Measurements
(Millions)	Total		Level 1		Level 2		Level 3
Asset Category
Cash and cash equivalents	$	6	$	—	$	6	$	—
U.S. government securities	1		1		—		—
Registered investment companies	141		141		—		—
Corporate bonds	3		—		3		—
Common collective trusts	4		—		4		—
Other, principally annuity, fixed income	9		—		9		—
	$	164	$	142	$	22	$	—
Other investments measured at net asset value	3
Total	$	167

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Equity (Tables)

12 Months Ended

Dec. 31, 2021

Equity [Abstract]

Accumulated Other Comprehensive Income (Loss)

Accumulated OCI (Loss) for the years ended December 31, 2021, 2020 and 2019 consisted of:

Accumulated Other Comprehensive Income (Loss)	As of December 31, 2018		Adoption of new accounting standard		2019 Change		As of December 31, 2019		2020 Change		As of December 31, 2020		2021 Change		As of December 31, 2021
(Millions)
Change in revaluation of defined benefit plans, net of income tax expense (benefit) of $0 for 2019, $0 for 2020 and $0 for 2021	$	(11)	$	(2)	$	1	$	(12)	$	—	$	(12)	$	2	$	(10)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) of $(1) for 2019, $3 for 2020 and $(1) for 2021	(6)		—		(1)		(7)		(13)		(20)		(8)		(28)
Unrealized loss from equity method investment, net of income tax benefit of $(3) for 2021 (a)	$	—	$	—	$	—	$	—	$	—	$	—	$	(9)	$	(9)
Unrealized (loss) gain on derivatives qualifying as cash flow hedges:
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) of $(9) for 2019, $(7) for 2020 and $(44) for 2021	9		—		(22)		(13)		(22)		(35)		(159)		(194)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) of $3 for 2019, $2 for 2020 and $(3) for 2021 (b)	(64)		(10)		11		(63)		19		(44)		12		(32)
Loss on derivatives qualifying as cash flow hedges	(55)		(10)		(11)		(76)		(3)		(79)		(147)		(226)
Accumulated Other Comprehensive Loss	$	(72)	$	(12)	$	(11)	$	(95)	$	(16)	$	(111)	$	(162)	$	(273)

(a)Foreign currency and interest rate contracts.

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

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Earnings Per Share (Tables)

12 Months Ended

Dec. 31, 2021

Earnings Per Share [Abstract]

Schedule of Earnings Per Share, Basic and Diluted

The calculations of basic and diluted earnings per share attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Years Ended December 31,	2021		2020		2019
(Millions, except for number of shares and per share data)
Numerator:
Net income attributable to AVANGRID	$	707	$	581	$	667
Denominator:
Weighted average number of shares outstanding - basic	358,086,621		309,494,939		309,491,082
Weighted average number of shares outstanding - diluted	358,578,608		309,559,387		309,514,910
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic	$	1.97	$	1.88	$	2.16
Earnings Per Common Share, Diluted	$	1.97	$	1.88	$	2.16

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Grants, Government Incentives and Deferred Income (Tables)

12 Months Ended

Dec. 31, 2021

Other Liabilities Disclosure [Abstract]

Schedule of Changes in Deferred Income

The changes in deferred income as of December 31, 2021 and 2020 consisted of:

(Millions)	Government grants		Other deferred income		Total
As of December 31, 2019	$	1,258	$	16	$	1,274
Disposals	(2)		—		(2)
Recognized in income	(66)		(2)		(68)
As of December 31, 2020	1,190		14		1,204
Disposals	—		—		—
Recognized in income	(65)		(9)		(74)
As of December 31, 2021	$	1,125	$	5	$	1,130

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Other Financial Statements Items (Tables)

12 Months Ended

Dec. 31, 2021

Organization, Consolidation and Presentation of Financial Statements [Abstract]

Schedule of Other Income and (Expense)

Other income (expense) for the years ended December 31, 2021, 2020 and 2019 consisted of:

Years ended December 31,	2021		2020		2019
(Millions)
Gain on sale of assets (a)	$	—	$	20	$	148
Allowance for funds used during construction	88		56		46
Carrying costs on regulatory assets	17		28		21
Non-service component of net periodic benefit cost	(37)		(62)		(79)
Other	(8)		(24)		(15)
Total Other Income (Expense)	$	60	$	18	$	121

(a) 2020 includes a $16 million gain from the Tatanka sale and 2019 includes a $134 million gain from the Poseidon sale (see Note 22).

Schedule of Accounts Receivable and Change in Allowance For Bad Debts

Accounts receivable and unbilled revenues, net as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Trade receivables and unbilled revenues	$	1,420	$	1,295
Allowance for credit losses	(151)		(108)
Total Accounts receivable and unbilled revenues, net	$	1,269	$	1,187

The change in the allowance for credit losses as of December 31, 2021 and 2020 consisted of:

(Millions)
As of December 31, 2018	$	62
Current period provision	92
Write-off as uncollectible	(85)
As of December 31, 2019	$	69
Current period provision	83
Write-off as uncollectible	(44)
As of December 31, 2020	$	108
Current period provision	110
Write-off as uncollectible	(67)
As of December 31, 2021	$	151

Schedule of Prepayments and Other Current Assets

Prepayments and other current assets as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Prepaid other taxes	$	95	$	135
Short-term investment (a)	—		300
Broker margin and collateral accounts	87		30
Other pledged deposits	4		2
Prepaid expenses	58		41
Other	1		17
Total	$	245	$	525

(a) Short-term investment from proceeds of the Iberdrola Loan.

Schedule of Other Current Liabilities

Other current liabilities as of December 31, 2021 and 2020 consisted of:

As of December 31,	2021		2020
(Millions)
Advances received	$	204	$	141
Accrued salaries	127		109
Short-term environmental provisions	52		49
Collateral deposits received	58		42
Pension and other postretirement	5		5
Finance leases	4		8
Other	34		14
Total	$	484	$	368

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Segment Information (Tables)

12 Months Ended

Dec. 31, 2021

Segment Reporting [Abstract]

Schedule of Segment Information

Segment information as of and for the year ended December 31, 2021 consisted of:

For the year ended December 31, 2021	Networks		Renewables		Other(a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,753	$	1,220	$	1	$	6,974
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	616		397		1		1,014
Operating income	876		26		(7)		895
Earnings (losses) from equity method investments	12		(5)		—		7
Interest expense, net of capitalization	217		1		80		298
Income tax expense (benefit)	98		(48)		(29)		21
Capital expenditures	2,294		680		2		2,976
Adjusted net income	661		170		(51)		780
As of December 31, 2021
Property, plant and equipment	18,737		10,118		11		28,866
Equity method investments	148		412		—		560
Total assets	$	26,126	$	12,578	$	800	$	39,504

(a)Includes Corporate and intersegment eliminations.

Segment information as of and for the year ended December 31, 2020 consisted of:

For the year ended December 31, 2020	Networks		Renewables		Other(a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,187	$	1,132	$	1	$	6,320
Revenue - intersegment	1		—		(1)		—
Depreciation and amortization	592		394		1		987
Operating income	877		(16)		8		869
Earnings (losses) from equity method investments	10		(13)		—		(3)
Interest expense, net of capitalization	234		7		75		316
Income tax expense (benefit)	120		(80)		(11)		29
Capital expenditures	1,838		943		—		2,781
Adjusted net income	568		115		(58)		625
As of December 31, 2020
Property, plant and equipment	17,079		9,662		10		26,751
Equity method investments	134		534		—		668
Total assets	$	24,592	$	12,867	$	364	$	37,823

(a)Includes Corporate and intersegment eliminations.

Segment information for the year ended December 31, 2019 consisted of:

For the year ended December 31, 2019	Networks		Renewables		Other (a)		AVANGRID Consolidated
(Millions)
Revenue - external	$	5,150	$	1,184	$	2	$	6,336
Revenue - intersegment	14		—		(14)		—
Depreciation and amortization	549		383		1		933
Operating income	890		93		15		998
Earnings (losses) from equity method investments	11		(8)		—		3
Interest expense, net of capitalization	269		14		27		310
Income tax expense (benefit)	152		28		(11)		169
Capital expenditures	1,610		1,122		3		2,735
Adjusted net income	$	465	$	193	$	(17)	$	640

(a)Includes Corporate and intersegment eliminations.

Schedule of Reconciliation of Consolidated EBITDA to Consolidated Net Income

Reconciliation of Adjusted Net Income to Net Income attributable to AVANGRID for the years ended December 31, 2021, 2020 and 2019 is as follows:

Years Ended December 31,	2021		2020		2019
(Millions)
Adjusted Net Income Attributable to Avangrid, Inc.	$	780	$	625	$	640
Adjustments:
Mark-to-market adjustments - Renewables (1)	(53)		(5)		76
Restructuring charges (2)	—		(6)		(6)
Accelerated depreciation from repowering (3)	—		(9)		(33)
Impact of COVID-19 (4)	(34)		(29)		—
Merger costs (5)	(12)		(6)		—
Legal settlement - Gas storage (6)	—		(5)		—
Income tax impact of adjustments	26		16		(10)
Net Income Attributable to Avangrid, Inc.	$	707	$	581	$	667

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

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

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

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

(5)Pre-merger costs incurred.

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

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Related Party Transactions (Tables)

12 Months Ended

Dec. 31, 2021

Related Party Transactions [Abstract]

Schedule of Related Party Transactions and Balances

Related party transactions for the years ended December 31, 2021, 2020 and 2019, respectively, consisted of:

Years Ended December 31,	2021				2020				2019
(Millions)	Sales To		Purchases From		Sales To		Purchases From		Sales To		Purchases From
Iberdrola, S.A.	$	—	$	(52)	$	1	$	(43)	$	1	$	(42)
Iberdrola Renovables Energia, S.L.	$	—	$	(10)	$	—	$	(9)	$	—	$	(9)
Iberdrola Financiación, S.A.	$	—	$	(9)	$	—	$	(7)	$	—	$	(3)
Vineyard Wind	$	14	$	—	$	9	$	—	$	13	$	—
Iberdrola Solutions	$	7	$	(39)	$	2	$	—	$	1	$	—
Other	$	2	$	(3)	$	—	$	—	$	1	$	(3)

Related party balances as of December 31, 2021 and 2020, respectively, consisted of:

As of December 31,	2021				2020
(Millions)	Owed By		Owed To		Owed By		Owed To
Iberdrola, S.A.	$	3	$	(43)	$	2	$	(43)
Iberdrola Financiacion	$	—	$	(9)	$	—	$	(6)
Vineyard Wind	$	8	$	(8)	$	4	$	—
Iberdrola Solutions	$	—	$	(2)	$	5	$	—
Other	$	—	$	(1)	$	1	$	(1)

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Stock-Based Compensation (Tables)

12 Months Ended

Dec. 31, 2021

Share-based Payment Arrangement [Abstract]

Schedule of Nonvested PSUs

A summary of the status of the AVANGRID's nonvested PSUs and RSUs as of December 31, 2021, and changes during the fiscal year ended December 31, 2021, is presented below:

	Number of PSUs and RSUs	Weighted Average Grant Date Fair Value
Nonvested Balance – December 31, 2020	142,167	$	32.42
Granted	1,359,516	$	36.49
Forfeited	(90,603)	$	36.63
Vested	(87,751)	$	47.70
Nonvested Balance – December 31, 2021	1,323,328	$	36.05

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Background and Nature of Operations (Details) $ / shares in Units, $ in Millions	May 18, 2021 USD ($) placement $ / shares shares	Apr. 15, 2021	Oct. 20, 2020 USD ($) $ / shares	Dec. 31, 2021 $ / shares	Dec. 31, 2020 $ / shares	Dec. 31, 2019 $ / shares
Noncontrolling Interest [Line Items]
Sale of stock, number of shares issued (in shares) | shares	77,821,012
Sale of stock, number of placements | placement	2
Common stock, par value (in dollars per share) | $ / shares	$ 0.01			$ 0.01	$ 0.01	$ 0.01
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	$ 3,000
NM Green Holdings, Inc.
Noncontrolling Interest [Line Items]
Merger agreement, share price (in dollars per share) | $ / shares			$ 50.30
Merger agreement term, ownership percentage benchmark			15.00%
Merger agreement, termination rights term, extension period			3 months
Merger agreement, termination rights term, termination fees			$ 130
Merger agreement, termination rights term, termination fees as remedy			184
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			$ 10
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger
Noncontrolling Interest [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%
Hyde Member LLC and Subsidiary of Qatar Investment Authority
Noncontrolling Interest [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
Iberdrola S.A.
Noncontrolling Interest [Line Items]
Sale of stock, number of shares issued (in shares) | shares	63,424,125
Avangrid | Iberdrola S.A.
Noncontrolling Interest [Line Items]
Parent company, ownership percentage				81.60%
Avangrid | Various Shareholders
Noncontrolling Interest [Line Items]
Ownership percentage by noncontrolling owners				14.80%

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Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Composite rate	2.80%	2.90%
Average remaining service period	10 years
Expected return on plan assets, period	5 years
Unionized Employees Concentration Risk | Employees covered by a collective bargaining agreement
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	47.70%
Unionized Employees Concentration Risk | Agreements which will expire within the coming year
Finite-Lived Intangible Assets [Line Items]
Percentage of employees covered by collective bargaining agreement	18.80%
Min.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	4 years
Max.
Finite-Lived Intangible Assets [Line Items]
Useful economic life	40 years

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Summary of Significant Accounting Policies, New Accounting Pronouncements and Use of Estimates - Property, Plant and Equipment (Details)	12 Months Ended
	Dec. 31, 2021
Plant | Solar power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	35 years
Min. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	45 years
Min. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	25 years
Min. | Plant | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	41 years
Min. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	4 years
Min. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	7 years
Min. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	3 years
Min. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	30 years
Min. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	3 years
Max. | Plant | Combined cycle plants
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years
Max. | Plant | Hydroelectric power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	90 years
Max. | Plant | Wind power stations
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	40 years
Max. | Plant | Transmission and transport facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Plant | Distribution facilities
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	80 years
Max. | Equipment | Conventional meters and measuring devices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	85 years
Max. | Equipment | Computer software
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	37 years
Max. | Other | Buildings
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	82 years
Max. | Other | Operations offices
Property, Plant and Equipment [Line Items]
Estimated Useful Life (years)	75 years

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Revenue - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Disaggregation of Revenue [Line Items]
Contract assets	$ 9	$ 9
Contract liabilities	16	9
Contract liabilities, revenue recognized	22	21	$ 21
Accounts receivable related to contracts with customers	1,220	1,151
Unbilled contracts receivable	$ 405	$ 341
Min. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	6 months
Max. | Transmission Congestion Contracts
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	2 years
Networks
Disaggregation of Revenue [Line Items]
Revenue performance obligation, timing	1 year
Renewables
Disaggregation of Revenue [Line Items]
Capitalized contract cost amortization term	15 years

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Revenue - Schedule of Revenues Disaggregated by Major Source for Reportable Segments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 6,793	$ 5,992	$ 5,963
Leasing revenue	7	6	6
Derivative revenue	3	136	244
Alternative revenue programs	115	157	75
Other revenue	56	29	48
Total operating revenues	6,974	6,320	6,336
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	(12)
Leasing revenue	0	0	0
Derivative revenue	0	0	0
Alternative revenue programs	0	0	0
Other revenue	0	0	0
Total operating revenues	0	0	(12)
Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,015	3,642	3,485
Regulated operations – electricity | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,516	1,311	1,479
Regulated operations – natural gas | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,028	822	803
Nonregulated operations – wind | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	20	19	26
Nonregulated operations – solar | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	63	39	29
Nonregulated operations – thermal | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	151	159	141
Other | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	(12)
Networks
Segment Reporting Information [Line Items]
Revenue from contracts with customers	5,598	5,011	5,055
Leasing revenue	7	6	6
Derivative revenue	0	0	0
Alternative revenue programs	115	157	75
Other revenue	34	14	28
Total operating revenues	5,754	5,188	5,164
Networks | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	4,015	3,642	3,485
Networks | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,516	1,311	1,479
Networks | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Networks | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	67	58	91
Renewables
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,195	981	920
Leasing revenue	0	0	0
Derivative revenue	3	136	244
Alternative revenue programs	0	0	0
Other revenue	22	15	20
Total operating revenues	1,220	1,132	1,184
Renewables | Regulated operations – electricity
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Regulated operations – natural gas
Segment Reporting Information [Line Items]
Revenue from contracts with customers	0	0	0
Renewables | Nonregulated operations – wind
Segment Reporting Information [Line Items]
Revenue from contracts with customers	1,028	822	803
Renewables | Nonregulated operations – solar
Segment Reporting Information [Line Items]
Revenue from contracts with customers	20	19	26
Renewables | Nonregulated operations – thermal
Segment Reporting Information [Line Items]
Revenue from contracts with customers	63	39	29
Renewables | Other
Segment Reporting Information [Line Items]
Revenue from contracts with customers	$ 84	$ 101	$ 62

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Revenue - Schedule of Aggregate Transaction Price Allocated to Unsatisfied Performance Obligations and Expected Time to Recognize Revenue (Details) $ in Millions	Dec. 31, 2021 USD ($)
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 232
Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	8
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	79
Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	145
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	71
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 6
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 39
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2022-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 26
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 43
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 24
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2023-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 18
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 24
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 1
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 9
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2024-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 14
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 2
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2025-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 12
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 13
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 3
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2026-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 10
Remaining performance obligation, period	1 year
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 67
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear retail energy sales contracts in place
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 0
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 2
Remaining performance obligation, period
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction, Start Date [Axis]: 2027-01-01 | Revenue expected to be recognized on multiyear renewable energy credit sale contracts
Revenue, Remaining Performance Obligation, Expected Timing of Satisfaction [Line Items]
Total operating revenues	$ 65
Remaining performance obligation, period

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Industry Regulation - Additional Information (Details) MWh in Millions																1 Months Ended					12 Months Ended
	Jul. 14, 2021 USD ($)	Jun. 23, 2021 USD ($)	May 06, 2021 USD ($)	Apr. 15, 2021	Dec. 31, 2020 USD ($) MW	Nov. 19, 2020	May 21, 2020	Feb. 19, 2020 USD ($)	Jan. 21, 2020	Dec. 09, 2019 USD ($)	Nov. 21, 2019	Jan. 18, 2019	Sep. 10, 2018 USD ($)	Jan. 01, 2017	Mar. 31, 2010 USD ($) MW	Dec. 31, 2019 MWh project	Oct. 31, 2018 agreement MW	Dec. 31, 2017	Mar. 31, 2017 project order	Dec. 31, 2016	Dec. 31, 2021 USD ($) company	Apr. 30, 2019	Jun. 30, 2021 USD ($) hour	Jul. 16, 2020 USD ($)	Jan. 31, 2018 USD ($)
Public Utilities, General Disclosures [Line Items]
Number of networks supply companies | company																					8
Direct Current Fast Charger incentive program, approved amount																								$ 700,000,000
Approved return on equity							10.02%				9.88%
Equity ratio						50.00%						54.00%									3.00%
Rate plan modification, overall bill impact limit, percent						2.00%
Percentage of standard service customers with wholesale power supply agreements in place for the second half of 2021																					60.00%
Public utilities regulatory authority distribution rate												9.70%
Number of REV related orders issued | order																			3
Number of energy storage projects | project																			2
Regulatory assets					$ 2,882,000,000																$ 2,647,000,000				$ 11,000,000
Number of average months used to set rate																					13 months
Restricted net assets																					$ 5,808,000,000
Purchase obligation per year																					$ 2,433,000,000
Energy legislation settlement agreement, contribution amount		$ 5,000,000
Energy legislation settlement agreement, customers rate credits provided		50,000,000
Energy legislation settlement agreement, customers rate credits collected in rate adjustment mechanism		$ 52,000,000
Energy legislation settlement agreement, customers rate credits provided, period		22 months
Energy legislation, customer compensation and reimbursement provisions, power outage hours benchmark (more than) | hour																							96
Energy legislation, customer compensation and reimbursement provisions, customer payment per day																							$ 25
Energy legislation, customer compensation and reimbursement provisions, food and medicine reimbursement																							$ 250
Civil penalty amount	$ 1,000,000		$ 2,000,000
DEEP
Public Utilities, General Disclosures [Line Items]
PPA capacity (in MWH) | MWh																12
PURA
Public Utilities, General Disclosures [Line Items]
Equity ratio														50.00%
Percentage of return on equity (ROE)																				9.10%	9.30%
New distribution rate schedule, period																				3 years
Public utilities regulatory authority distribution rate														50.00%
Equity ratio, year one																					54.00%
Equity ratio, year two																					54.50%
Equity ratio, year three																					55.00%
Power Tax
Public Utilities, General Disclosures [Line Items]
Depreciation amortization period									32 years 6 months
Depreciation amortization period									32 years 6 months
Storm costs
Public Utilities, General Disclosures [Line Items]
Regulatory assets					451,000,000																$ 448,000,000
Federal tax depreciation normalization adjustment
Public Utilities, General Disclosures [Line Items]
Regulatory assets					$ 148,000,000																142,000,000
Central Maine Power
Public Utilities, General Disclosures [Line Items]
Distribution revenue requirement								$ 17,000,000
Annual distribution tariff increase percentage								7.00%
Distribution tariff rate increased based on ROE								9.25%
Distribution tariff rate increased based on equity capital								50.00%
ROE reduction								1.00%
Proposed distribution tariff rate decrease based on return on equity								8.25%
Customer service performance period								18 months
SCG
Public Utilities, General Disclosures [Line Items]
Equity ratio																		52.00%
Percentage of return on equity (ROE)																		9.25%
NYDPS
Public Utilities, General Disclosures [Line Items]
Equity ratio for earnings sharing						48.00%
Percentage of return on equity (ROE)						8.80%
United Illuminating Company (UI)
Public Utilities, General Disclosures [Line Items]
ROE reduction				0.15%
Maximum amount of commitment to purchase renewable energy credits (recs) from new facilities behind distribution customer meters																					$ 200,000,000
Period of purchase commitment																					21 years
Solicitation period																					6 years
Maximum annual commitment level obligation after year six																					$ 14,000,000
Additional maximum annual commitment																					$ 64,000,000
Number of power purchase agreements | agreement																	5
Proposed off shore wind capacity (in MW) | MW																	50
Number of projects | project																11
Vineyard Wind
Public Utilities, General Disclosures [Line Items]
Proposed off shore wind capacity (in MW) | MW					804
CMP
Public Utilities, General Disclosures [Line Items]
Period of purchase commitment					20 years										20 years
Wind farm capacity (in MW) | MW															60
Purchase obligation per year															$ 7,000,000
CMP | Dirigo Solar, LLC
Public Utilities, General Disclosures [Line Items]
Period of purchase commitment													20 years
Purchase obligation per year													$ 4,000,000
CMP | Maine Aqua Ventus I GP LLC
Public Utilities, General Disclosures [Line Items]
Period of purchase commitment										20 years
Purchase obligation per year										$ 12,000,000
NYSEG Electric
Public Utilities, General Disclosures [Line Items]
Approved return on equity																					9.00%
Equity ratio																					48.00%
Equity ratio for earnings sharing																					50.00%
Recovery of deferred storm costs																					$ 262,000,000
NYSEG Electric | Storm costs, ten year recovery
Public Utilities, General Disclosures [Line Items]
Amortization of deferred storm cost																					123,000,000
NYSEG Electric | Storm costs, five year recovery
Public Utilities, General Disclosures [Line Items]
Amortization of deferred storm cost																					139,000,000
NYSEG Electric | Deferred Storm Cost Amortization 1 Year
Public Utilities, General Disclosures [Line Items]
Amortization of deferred storm cost																					$ 26,000,000
NYSEG Electric | Storm costs
Public Utilities, General Disclosures [Line Items]
Depreciation amortization period																					10 years
Depreciation amortization period																					10 years
NYSEG Electric | Regulatory Items Other Than Storm Costs
Public Utilities, General Disclosures [Line Items]
Depreciation amortization period																					5 years
Depreciation amortization period																					5 years
NYSEG Gas
Public Utilities, General Disclosures [Line Items]
Percentage of earnings customers received																					50.00%
Percentage of return on equity (ROE)																						9.75%
RG&E Electric
Public Utilities, General Disclosures [Line Items]
Percentage of earnings customers received																					75.00%
Percentage of return on equity (ROE)																						10.25%
RG&E Electric | Deferred Storm Cost Amortization 1 Year
Public Utilities, General Disclosures [Line Items]
Amortization of deferred storm cost																					$ 3,000,000
RG&E Gas
Public Utilities, General Disclosures [Line Items]
Percentage of earnings customers received																					90.00%
Percentage of return on equity (ROE)																						10.75%
NYSEG and RG&E
Public Utilities, General Disclosures [Line Items]
Direct Current Fast Charger incentive program, approved amount																								$ 118,000,000

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Industry Regulation - Rate Increases and Delivery Rate Percentages (Details) - Year 3 - USD ($) $ in Millions	Jun. 22, 2020	Jun. 15, 2016
NYSEG Electric
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 36.0	$ 30.0
Delivery Rate Increase	4.20%	4.10%
NYSEG Gas
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 3.0	$ 15.0
Delivery Rate Increase	1.60%	7.30%
RG&E Electric
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 16.0	$ 26.0
Delivery Rate Increase	3.30%	5.70%
RG&E Gas
Public Utilities, General Disclosures [Line Items]
Rate Increase	$ 2.0	$ 10.0
Delivery Rate Increase	1.30%	5.20%

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Industry Regulation - Rate Increases (Details) - USD ($) $ in Millions	Jun. 22, 2020	Jun. 15, 2016
NYSEG Electric | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 34.0
Delivery Rate Increase	4.60%
NYSEG Electric | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 46.0
Delivery Rate Increase	5.90%
NYSEG Electric | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 36.0	$ 30.0
Delivery Rate Increase	4.20%	4.10%
NYSEG Gas | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 0.0
Delivery Rate Increase	0.00%
NYSEG Gas | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 2.0
Delivery Rate Increase	0.80%
NYSEG Gas | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 3.0	$ 15.0
Delivery Rate Increase	1.60%	7.30%
RG&E Electric | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 17.0
Delivery Rate Increase	3.80%
RG&E Electric | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 14.0
Delivery Rate Increase	3.20%
RG&E Electric | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 16.0	$ 26.0
Delivery Rate Increase	3.30%	5.70%
RG&E Gas | Year 1
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 0.0
Delivery Rate Increase	0.00%
RG&E Gas | Year 2
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 0.0
Delivery Rate Increase	0.00%
RG&E Gas | Year 3
Public Utility, Property, Plant and Equipment [Line Items]
Rate Increase	$ 2.0	$ 10.0
Delivery Rate Increase	1.30%	5.20%

XML

Regulatory Assets and Liabilities - Regulatory Assets Narrative (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Regulated Operations [Abstract]
Unrecorded regulatory assets	$ 1,136
Regulatory Assets [Line Items]
Unfunded future income tax expense collection period	46 years
Central Maine Power
Regulatory Assets [Line Items]
Deferred income tax recovery period	32 years 6 months

XML

Regulatory Assets and Liabilities - Schedule of Regulatory Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Jan. 31, 2018
Regulatory Assets [Line Items]
Total regulatory assets	$ 2,647	$ 2,882	$ 11
Less: current portion	400	310
Total non-current regulatory assets	2,247	2,572
Pension and other post-retirement benefits
Regulatory Assets [Line Items]
Total regulatory assets	545	927
Pension and other post-retirement benefits cost deferrals
Regulatory Assets [Line Items]
Total regulatory assets	95	105
Storm costs
Regulatory Assets [Line Items]
Total regulatory assets	448	451
Rate adjustment mechanism
Regulatory Assets [Line Items]
Total regulatory assets	68	33
Revenue decoupling mechanism
Regulatory Assets [Line Items]
Total regulatory assets	68	58
Transmission revenue reconciliation mechanism
Regulatory Assets [Line Items]
Total regulatory assets	15	31
Contracts for differences
Regulatory Assets [Line Items]
Total regulatory assets	73	86
Hardship programs
Regulatory Assets [Line Items]
Total regulatory assets	24	20
Plant decommissioning
Regulatory Assets [Line Items]
Total regulatory assets	2	3
Deferred purchased gas
Regulatory Assets [Line Items]
Total regulatory assets	52	30
Deferred transmission expense
Regulatory Assets [Line Items]
Total regulatory assets	13	26
Environmental remediation costs
Regulatory Assets [Line Items]
Total regulatory assets	256	247
Debt premium
Regulatory Assets [Line Items]
Total regulatory assets	71	83
Unamortized losses on reacquired debt
Regulatory Assets [Line Items]
Total regulatory assets	23	26
Unfunded future income taxes
Regulatory Assets [Line Items]
Total regulatory assets	424	373
Federal tax depreciation normalization adjustment
Regulatory Assets [Line Items]
Total regulatory assets	142	148
Asset retirement obligation
Regulatory Assets [Line Items]
Total regulatory assets	20	21
Deferred meter replacement costs
Regulatory Assets [Line Items]
Total regulatory assets	46	33
COVID-19 cost recovery
Regulatory Assets [Line Items]
Total regulatory assets	21	1
Other
Regulatory Assets [Line Items]
Total regulatory assets	$ 241	$ 180

XML

Regulatory Assets and Liabilities - Schedule of Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 3,329	$ 3,411
Less: current portion	307	274
Regulatory liabilities	3,022	3,137
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Total regulatory liabilities	45	58
Gas supply charge and deferred natural gas cost
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	3
Pension and other post-retirement benefits cost deferrals
Regulatory Liabilities [Line Items]
Total regulatory liabilities	73	59
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	34
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Total regulatory liabilities	7	11
2017 Tax Act
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,327	1,435
Rate change levelization
Regulatory Liabilities [Line Items]
Total regulatory liabilities	99	55
Revenue decoupling mechanism
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	9
Accrued removal obligations
Regulatory Liabilities [Line Items]
Total regulatory liabilities	1,192	1,184
Asset sale gain account
Regulatory Liabilities [Line Items]
Total regulatory liabilities	2	7
Economic development
Regulatory Liabilities [Line Items]
Total regulatory liabilities	26	28
Positive benefit adjustment
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	30
Theoretical reserve flow thru impact
Regulatory Liabilities [Line Items]
Total regulatory liabilities	6	10
Deferred property tax
Regulatory Liabilities [Line Items]
Total regulatory liabilities	22	31
Net plant reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	16	20
Debt rate reconciliation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	49	63
Rate refund – FERC ROE proceeding
Regulatory Liabilities [Line Items]
Total regulatory liabilities	35	33
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Total regulatory liabilities	23	22
Merger-related rate credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	12	14
Accumulated deferred investment tax credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	24	25
Asset retirement obligation
Regulatory Liabilities [Line Items]
Total regulatory liabilities	18	18
Earnings sharing provisions
Regulatory Liabilities [Line Items]
Total regulatory liabilities	13	17
Middletown/Norwalk local transmission network service collections
Regulatory Liabilities [Line Items]
Total regulatory liabilities	17	18
Low income programs
Regulatory Liabilities [Line Items]
Total regulatory liabilities	25	28
Non-firm margin sharing credits
Regulatory Liabilities [Line Items]
Total regulatory liabilities	15	14
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Total regulatory liabilities	5	9
Hedges gains
Regulatory Liabilities [Line Items]
Total regulatory liabilities	19	0
Other
Regulatory Liabilities [Line Items]
Total regulatory liabilities	$ 194	$ 176

XML

Regulatory Assets and Liabilities - Regulatory Liabilities Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
UIL Holdings
Regulatory Liabilities [Line Items]
Business combination merger related rate credits	$ 2	$ 2
Energy efficiency portfolio standard
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Carrying costs on deferred income tax bonus depreciation
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Carrying costs on deferred income tax - Mixed Services 263(a)
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Rate change levelization
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Positive benefit adjustment | Min.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Positive benefit adjustment | Max.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Theoretical reserve flow thru impact | Min.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
Theoretical reserve flow thru impact | Max.
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Deferred property tax
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Net plant reconciliation
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
Transmission congestion contracts
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	5 years
New York 2018 winter storm settlement
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
NYSEG and RG&E | Economic development
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
NYSEG | Asset sale gain account
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	3 years
RG&E | Asset sale gain account
Regulatory Liabilities [Line Items]
Regulatory liability, amortization period	2 years

XML

Goodwill and Intangible assets - Schedule of Goodwill by Reportable Segment (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Goodwill [Line Items]
Goodwill	$ 3,119	$ 3,119
Networks
Goodwill [Line Items]
Goodwill	2,747	2,747
Renewables
Goodwill [Line Items]
Goodwill	$ 372	$ 372

XML

Goodwill and Intangible assets - Additional Information (Details)		12 Months Ended
	Dec. 16, 2015 USD ($)	Dec. 31, 2021 USD ($) reportingUnit	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2002 USD ($)	Dec. 31, 2000 USD ($)
Goodwill [Line Items]
Impairment of goodwill		$ 0	$ 0
Amortization expense		$ 13,000,000	$ 14,000,000	$ 15,000,000
Maine Reporting Unit
Goodwill [Line Items]
Goodwill						$ 325,000,000
New York Reporting Unit
Goodwill [Line Items]
Goodwill					$ 654,000,000
UIL Reporting Unit
Goodwill [Line Items]
Goodwill	$ 1,768,000,000
Networks
Goodwill [Line Items]
Number of reporting units | reportingUnit		3

XML

Goodwill and Intangible assets - Summary of Intangible Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	$ 610	$ 624
Accumulated Amortization	(317)	(319)
Net Carrying Amount	293	305
Wind development
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	592	593
Accumulated Amortization	(301)	(290)
Net Carrying Amount	291	303
Other
Finite-Lived Intangible Assets [Line Items]
Gross Carrying Amount	18	31
Accumulated Amortization	(16)	(29)
Net Carrying Amount	$ 2	$ 2

XML

Goodwill and Intangible assets - Schedule of Amortization Expense (Details) $ in Millions	Dec. 31, 2021 USD ($)
Year ending December 31,
2022	$ 14
2023	13
2024	13
2025	12
2026	$ 12

XML

Property, Plant and Equipment - Schedule of Property, Plant and Equipment (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 36,169	$ 34,142
Total accumulated depreciation	(10,589)	(9,799)
Total Net Property, Plant and Equipment in Service	25,580	24,343
Construction work in progress	3,286	2,408
Total Property, Plant and Equipment	28,866	26,751
Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	30,838	29,218
Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,045	4,650
Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	286	274
Regulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	22,424	21,001
Total accumulated depreciation	(5,806)	(5,363)
Total Net Property, Plant and Equipment in Service	16,618	15,638
Construction work in progress	2,064	1,384
Total Property, Plant and Equipment	18,682	17,022
Regulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	17,392	16,364
Regulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	5,032	4,637
Regulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	0	0
Nonregulated
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13,745	13,141
Total accumulated depreciation	(4,783)	(4,436)
Total Net Property, Plant and Equipment in Service	8,962	8,705
Construction work in progress	1,222	1,024
Total Property, Plant and Equipment	10,184	9,729
Nonregulated | Electric generation, distribution, transmission and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13,446	12,854
Nonregulated | Natural gas transportation, distribution and other
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	13	13
Nonregulated | Other common operating property
Property, Plant and Equipment [Line Items]
Total Property, Plant and Equipment in Service	$ 286	$ 274

XML

Property, Plant and Equipment - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Property, Plant and Equipment [Abstract]
Interest costs capitalized	$ 33,000,000	$ 51,000,000	$ 51,000,000
Accrued liabilities for property, plant and equipment additions	297,000,000	285,000,000	357,000,000
Tangible asset impairment charges	20,000,000	7,000,000	11,000,000
Depreciation	1,001,000,000	973,000,000	$ 918,000,000
New England Clean Energy Connect (NECEC) project, impairment	0
New England Clean Energy Connect (NECEC) project, capitalized amount	$ 546,000,000	$ 180,000,000

XML

Asset retirement obligations - Reconciliation of ARO (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation, Roll Forward Analysis [Roll Forward]
Beginning Balance	$ 210	$ 190
Liabilities settled during the year	(2)	(2)
Liabilities incurred during the year	7	9
Accretion expense	12	11
Revisions in estimated cash flows	26	2
Ending Balance	$ 253	$ 210

XML

Asset retirement obligations - Additional Information (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Asset Retirement Obligation Disclosure [Abstract]
Asset retirement obligation, restricted cash	$ 3	$ 3

XML

Debt - Schedule of Long-term Debt (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Debt Instrument [Line Items]
Unamortized debt issuance costs and discount	$ (53)	$ (47)
Total Debt	8,294	7,791
Less: debt due within one year, included in current liabilities	372	313
Total Non-current Debt	7,922	7,478
First mortgage bonds - fixed
Debt Instrument [Line Items]
Long-term debt	2,759	$ 2,575
Bond pledged as collateral	$ 7,871
First mortgage bonds - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.85%	1.85%
First mortgage bonds - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	8.00%	8.00%
Unsecured pollution control notes - fixed
Debt Instrument [Line Items]
Long-term debt	$ 478	$ 478
Unsecured pollution control notes - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.40%	1.40%
Unsecured pollution control notes - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	3.50%	3.50%
Other various non-current debt - fixed
Debt Instrument [Line Items]
Long-term debt	$ 5,110	$ 4,785
Other various non-current debt - fixed | Min.
Debt Instrument [Line Items]
Debt instrument, interest rate	1.95%	1.95%
Other various non-current debt - fixed | Max.
Debt Instrument [Line Items]
Debt instrument, interest rate	6.66%	7.80%

XML

Debt - Additional Information (Details)		12 Months Ended
	Nov. 23, 2021 USD ($)	Dec. 31, 2021 USD ($)	Nov. 22, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 14, 2020 USD ($)
Debt Instrument [Line Items]
Estimated fair value of debt		$ 9,155,000,000		$ 12,166,000,000
Commercial paper		0		309,000,000
Notes payable		159,000,000		307,000,000
Supplier Financing Arrangements
Debt Instrument [Line Items]
Notes payable		$ 161,000,000		$ 0
Weighted-average interest rate		0.82%
Commercial Paper
Debt Instrument [Line Items]
Weighted-average interest rate				0.32%
Subordinated Debt | Iberdrola Loan
Debt Instrument [Line Items]
Debt instrument principal amount					$ 3,000,000,000
AVANGRID Credit Facility
Debt Instrument [Line Items]
Credit facility remaining borrowing capacity		$ 3,575,000,000
Line of credit facility, maximum borrowing capacity	$ 4,000,000,000
Debt covenant, ratio of consolidated debt to consolidated total capitalization	0.65
Line of credit borrowing outstanding		0
AVANGRID Credit Facility | Min.
Debt Instrument [Line Items]
Credit facility fees percentage	0.10%
AVANGRID Credit Facility | Max.
Debt Instrument [Line Items]
Credit facility fees percentage	0.225%
AVANGRID Credit Facility | Commercial Paper
Debt Instrument [Line Items]
Commercial paper		2,000,000,000
AVANGRID Credit Facility Sublimit
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity	$ 2,500,000,000		$ 1,500,000,000
2020 Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity				$ 500,000,000
Iberdrola Group Credit Facility
Debt Instrument [Line Items]
Line of credit facility, maximum borrowing capacity		$ 500,000,000
Credit facility fees percentage		0.105%
Credit facility amount drawn		$ 0		$ 0

XML

Debt - Other 2021 Long-Term Debt Issuances (Details) - USD ($) $ in Millions	Dec. 15, 2021	Sep. 24, 2021
Unsecured Notes | NYSEG | 2.15% Unsecured Notes Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount		$ 350
Debt instrument, interest rate		2.15%
First Mortgage Bonds | RG&E | 2.91% First Mortgage Bonds Due 2051
Debt Instrument [Line Items]
Debt instrument principal amount	$ 125
Debt instrument, interest rate	2.91%
First Mortgage Bonds | RG&E | 2.10% First Mortgage Bonds Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount	$ 125
Debt instrument, interest rate	2.10%
First Mortgage Bonds | CMP | 2.05% First Mortgage Bonds Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount	$ 200
Debt instrument, interest rate	2.05%
First Mortgage Bonds | SCG | 2.05% First Mortgage Bonds Due 2031
Debt Instrument [Line Items]
Debt instrument principal amount	$ 40
Debt instrument, interest rate	2.05%

XML

Debt - Schedule of Long-term Debt Maturities (Details) $ in Millions	Dec. 31, 2021 USD ($)
Debt Disclosure [Abstract]
2022	$ 372
2023	439
2024	612
2025	1,107
2026	660
Total	$ 3,190

XML

Fair Value of Financial Instruments and Fair Value Measurements - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative delivery period (in years)	2 years
Restricted cash	$ 3	$ 4
RG&E
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Percentage of electric load obligations using contracts for a NYISO location	70.00%

XML

Fair Value of Financial Instruments and Fair Value Measurements - Fair Value of Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	$ 60	$ 63
Netting adjustment	(110)	(89)
Derivative assets	94	97
Netting adjustment	194	81
Derivative liabilities	(224)	(96)
Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(78)	(54)
Derivative assets	77	87
Netting adjustment	176	72
Derivative liabilities	(67)	(5)
Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	(32)	(35)
Derivative assets	15	8
Netting adjustment	18	9
Derivative liabilities	(5)	(3)
Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0	0
Derivative assets	2	2
Netting adjustment	0	0
Derivative liabilities	(75)	(88)
Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Netting adjustment	0
Derivative assets	0
Netting adjustment	0	0
Derivative liabilities	(77)	0
Level 1
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	45	49
Derivative assets, before netting	35	5
Derivative liabilities, before netting	(17)	(24)
Level 1 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	31	5
Derivative liabilities, before netting	(16)	(23)
Level 1 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	4	0
Derivative liabilities, before netting	(1)	(1)
Level 1 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 1 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0
Derivative liabilities, before netting	0	0
Level 2
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	15	14
Derivative assets, before netting	73	55
Derivative liabilities, before netting	(236)	(40)
Level 2 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	39	31
Derivative liabilities, before netting	(137)	(31)
Level 2 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	34	24
Derivative liabilities, before netting	(22)	(9)
Level 2 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0	0
Derivative liabilities, before netting	0	0
Level 2 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0
Derivative liabilities, before netting	(77)	0
Level 3
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Equity and other investments with readily determinable fair values	0	0
Derivative assets, before netting	96	126
Derivative liabilities, before netting	(165)	(113)
Level 3 | Derivative financial instruments - power
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	85	105
Derivative liabilities, before netting	(90)	(23)
Level 3 | Derivative financial instruments - gas
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	9	19
Derivative liabilities, before netting	0	(2)
Level 3 | Contracts for differences
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	2	2
Derivative liabilities, before netting	(75)	(88)
Level 3 | Derivative financial instruments – Other
Fair Value, Assets and Liabilities Measured on Recurring and Nonrecurring Basis [Line Items]
Derivative assets, before netting	0
Derivative liabilities, before netting	$ 0	$ 0

XML

Fair Value of Financial Instruments and Fair Value Measurements - Reconciliation of Changes in Fair Value of Financial Instruments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Fair Value, Net Derivative Asset (Liability) Measured on Recurring Basis, Unobservable Input Reconciliation [Roll Forward]
Fair value as of January 1,	$ 13	$ 25	$ (15)
Gains for the year recognized in operating revenues	21	8	53
Losses for the year recognized in operating revenues	(34)	(2)	(2)
Total gains or losses for the period recognized in operating revenues	(13)	6	51
Gains recognized in OCI	2	1	2
Losses recognized in OCI	(52)	(3)	(3)
Total gains or losses recognized in OCI	(50)	(2)	(1)
Net change recognized in regulatory assets and liabilities	13	6	5
Purchases	(17)	(2)	(22)
Settlements	(13)	(15)	4
Transfers out of Level 3 (a)	(2)	(5)	3
Fair value as of December 31,	(69)	13	25
Gains for the year included in operating revenues attributable to the change in unrealized gains relating to financial instruments still held at the reporting date	$ (13)	$ 6	$ 51

XML

Fair Value of Financial Instruments and Fair Value Measurements - Valuation of Instruments (Details) - Measurement Input, Commodity Forward Price	Dec. 31, 2021 $ / MWh $ / kilowatt-MonthOfEnergy
Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate | $ / kilowatt-MonthOfEnergy	4.80
Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate | $ / kilowatt-MonthOfEnergy	2.00
NYMEX | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	3.18
NYMEX | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	6.52
NYMEX | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.27
AECO | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.41
AECO | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	5.69
AECO | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	1.53
Ameren | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	32.23
Ameren | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	93.59
Ameren | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	18.01
COB | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	46.83
COB | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	231.90
COB | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	9.15
ComEd | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	29.60
ComEd | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	86.32
ComEd | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	14.98
ERCOT N hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	35.05
ERCOT N hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	140.00
ERCOT N hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	13.66
ERCOT S hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	34.24
ERCOT S hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	140.00
ERCOT S hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	13.88
Indiana hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	34.20
Indiana hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	93.81
Indiana hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	20.74
Mid C | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	43.53
Mid C | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	229.90
Mid C | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	5.15
Minn hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	28.82
Minn hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	90.99
Minn hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	15.23
Noil hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	29.35
Noil hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	84.00
Noil hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	14.64
PJM W hub | Avg.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	33.49
PJM W hub | Max.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	113.93
PJM W hub | Min.
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	17.78

XML

Fair Value of Financial Instruments and Fair Value Measurements - Schedule of Fair Value Measurement (Details)	Dec. 31, 2021 $ / kilowatt-MonthOfEnergy
Min. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0039
Min. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0097
Min. | Measurement Input, Commodity Forward Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	2.00
Max. | Risk of non-performance
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0051
Max. | Discount rate
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	0.0126
Max. | Measurement Input, Commodity Forward Price
Fair Value Measurement Inputs and Valuation Techniques [Line Items]
Discount rate	4.80

XML

Derivative Instruments and Hedging - Offsetting of Derivatives, Locations in Consolidated Balance Sheet and Amounts of Derivatives (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative Asset	$ 94	$ 97
Derivative Liability	(224)	(96)
Cash collateral (payable) receivable, asset	(67)	(18)
Networks | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	17	0
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	17	0
Networks | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	29	3
Derivative liabilities	(12)	(3)
Derivative Asset	17	0
Networks | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	3	1
Cash collateral (payable) receivable, asset	0	0
Total derivatives as presented in the balance sheet	3	1
Networks | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	7	5
Derivative liabilities	(4)	(4)
Derivative Asset	3	1
Networks | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Asset	0	0
Networks | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(16)	(32)
Cash collateral (payable) receivable, liability	0	18
Total derivatives as presented in the balance sheet	(16)	(14)
Networks | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	12	3
Derivative liabilities	(27)	(34)
Derivative Liability	(15)	(31)
Networks | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	(1)	(1)
Derivative Liability	(1)	(1)
Networks | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(60)	(75)
Cash collateral (payable) receivable, liability	0	1
Total derivatives as presented in the balance sheet	(60)	(74)
Networks | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	4	3
Derivative liabilities	(64)	(78)
Derivative Liability	(60)	(75)
Networks | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	0
Derivative liabilities	0	0
Derivative Liability	0	0
Renewables | Current Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	18	27
Cash collateral (payable) receivable, asset	0	(9)
Total derivatives as presented in the balance sheet	18	18
Renewables | Current Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	29	47
Derivative liabilities	(11)	(23)
Derivative Asset	18	24
Renewables | Current Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	8
Derivative liabilities	0	(5)
Derivative Asset	0	3
Renewables | Noncurrent Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, asset	56	96
Cash collateral (payable) receivable, asset	0	(18)
Total derivatives as presented in the balance sheet	56	78
Renewables | Noncurrent Assets | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	70	89
Derivative liabilities	(14)	(2)
Derivative Asset	56	87
Renewables | Noncurrent Assets | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	0	15
Derivative liabilities	0	(6)
Derivative Asset	0	9
Renewables | Current Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(75)	(3)
Cash collateral (payable) receivable, liability	27	0
Total derivatives as presented in the balance sheet	(48)	(3)
Renewables | Current Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	52	2
Derivative liabilities	(65)	(4)
Derivative Liability	(13)	(2)
Renewables | Current Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	5	2
Derivative liabilities	(67)	(3)
Derivative Liability	(62)	(1)
Renewables | Noncurrent Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total derivatives before offset of cash collateral, liability	(138)	(5)
Cash collateral (payable) receivable, liability	57	0
Total derivatives as presented in the balance sheet	(81)	(5)
Renewables | Noncurrent Liabilities | Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	9	9
Derivative liabilities	(11)	(11)
Derivative Liability	(2)	(2)
Renewables | Noncurrent Liabilities | Designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets	6	7
Derivative liabilities	(142)	(10)
Derivative Liability	$ (136)	$ (3)

XML

Derivative Instruments and Hedging - Net Notional Volume (Details) gal in Millions, MWh in Millions, MMBTU in Millions, $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) MWh MMBTU gal	Dec. 31, 2020 USD ($) MMBTU MWh gal
Networks | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	5.7	5.6
Networks | Natural gas purchase contracts (Dth) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	9.4	9.5
Networks | Fleet fuel purchase contracts (Gallons) | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount | gal	2.0	2.5
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 0	$ 88
Renewables | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	4.0	3.0
Derivative assets (liabilities), fair value	$ 36	$ 4
Renewables | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MWh	10.0	7.0
Derivative assets (liabilities), fair value	$ (77)	$ 11
Renewables | Natural gas and other fuel purchase contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	20.0	24.0
Derivative assets (liabilities), fair value	$ 6	$ 0
Renewables | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	9.0	12.0
Derivative assets (liabilities), fair value	$ 35	$ 66
Renewables | Basis Swaps | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	30.0	35.0
Derivative assets (liabilities), fair value	$ 0	$ 7
Renewables | Basis Swaps | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative, non-monetary notional amount, energy measure | MMBTU	0.0	2.0

XML

Derivative Instruments and Hedging - Summary of Unrealized Gains and Losses from Fair Value Adjustments (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	$ 0	$ 0	$ (3)
Derivative Liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	13	6	8
Electricity
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			25
Electricity | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	17
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(23)	55
Electricity | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	(16)	0
Natural Gas
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income			$ 1
Natural Gas | Regulatory assets
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	0	1
Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income	(11)	4
Natural Gas | Regulatory liabilities
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss or Gain Recognized in Regulatory Assets/Liabilities	$ (3)	$ 0

XML

Derivative Instruments and Hedging - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021 USD ($) instrument	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Sep. 15, 2021 USD ($)	Jul. 15, 2021 USD ($)	May 27, 2021 USD ($)	Jun. 20, 2019 USD ($)	Jan. 31, 2018 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Regulatory assets	$ 2,647,000,000	$ 2,882,000,000						$ 11,000,000
Regulatory liabilities	3,329,000,000	3,411,000,000
Gain (loss) recognized in OCI on derivatives	(200,000,000)
Derivative liabilities	160,000,000	79,000,000
Gain on derivative			$ 43,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months	(9,000,000)
Loss (Gain) Reclassified from Accumulated OCI into Income	(3,000,000)
Derivative liability	224,000,000	96,000,000
Derivative collateral obligation to be paid in decrease in credit rating below investment grade	19,000,000
Cash collateral pledged	67,000,000	18,000,000
Derivative with credit risk contingent features, liability, fair value	0
Not designated as hedging instruments
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain on foreign currency contracts not designated as hedging instruments	$ 0	4,000,000
Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Number of instruments held | instrument	2
Derivative liability	$ 75,000,000	88,000,000
Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(9,000,000)	(8,000,000)	(2,000,000)
Cash Flow Hedging | Previously Settled Interest Rate Contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	48,000,000	57,000,000
Fair Value Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative liability					$ 750,000,000
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(3,000,000)	0	(1,000,000)
Loss (Gain) Reclassified from Accumulated OCI into Income	3,000,000	5,000,000	7,000,000
Networks | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Forward contract to hedge foreign currency exchange risk							$ 100,000,000
Gain (loss) recognized in OCI on derivatives	(4,000,000)	(4,000,000)	$ (6,000,000)
Expected amortization of discontinued cash flow hedges, next fiscal year	(4,000,000)
Unrealized loss	1,000,000
Cash flow hedge gain (loss) to be reclassified within twelve months	(5,000,000)
Networks | Cash Flow Hedging | Previously Settled Forward Starting Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Net loss related to previously settled forward starting swaps	$ 47,000,000	51,000,000
Networks | Cash Flow Hedging | Fuel Derivatives
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Maximum length of time hedged in cash flow hedge	12 months
Renewables | Cash Flow Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cash flow hedge gain (loss) to be reclassified within twelve months	$ 59,000,000
Renewables | Cash Flow Hedging | Interest Rate Swap
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Notional amount				$ 956,000,000		$ 935,000,000
Derivative liabilities	$ 58,000,000
UI | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	20.00%
Derivative assets	$ 2,000,000	2,000,000
Regulatory assets	73,000,000	86,000,000
Derivative liabilities	75,000,000	88,000,000
Regulatory liabilities	$ 0	0
CL&P | Contracts for differences
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Percentage of cost or benefit on contract allocated to customers	80.00%
Derivative assets	$ 0	0
Derivative liabilities	$ 72,000,000	$ 85,000,000

XML

Derivative Instruments and Hedging - Effect of Derivatives in Cash Flow Hedging (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	$ (200)
Loss (Gain) Reclassified from Accumulated OCI into Income	(3)
Interest expense	298	$ 316	$ 310
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Operating revenues	6,974	6,320	6,336
Networks
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(3)	0	(1)
Loss (Gain) Reclassified from Accumulated OCI into Income	3	5	7
Operating revenues	5,754	5,188	5,164
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,220	1,132	1,184
Interest rate contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	(27)	(24)
Interest rate contracts | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	9	8	2
Interest rate contracts | Networks | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	0	0	0
Loss (Gain) Reclassified from Accumulated OCI into Income	4	4	6
Interest rate contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(58)
Operating revenues	298
Interest rate contracts | Renewables | Interest expense
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	0
Commodity contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	2	(1)	0
Loss (Gain) Reclassified from Accumulated OCI into Income	(1)	1	1
Commodity contracts | Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(142)	1	(5)
Commodity contracts | Renewables | Revenue
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Loss (Gain) Reclassified from Accumulated OCI into Income	(3)	6	3
Operating revenues	6,974	6,320	6,336
Foreign currency exchange contracts | Networks | Purchased power, natural gas and fuel used
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Gain (loss) recognized in OCI on derivatives	(5)	1	(1)
Loss (Gain) Reclassified from Accumulated OCI into Income	$ 0	$ 0	$ 0

XML

Derivative Instruments and Hedging - Fair Value of Derivative Contract (Details) - Renewables - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ 0	$ 88
Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	35	66
Long | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	36	4
Long | Natural gas and other fuel purchase contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	6	0
Long | Basis Swaps
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	0	7
Short | Wholesale electricity contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Derivative assets (liabilities), fair value	$ (77)	$ 11

XML

Derivative Instruments and Hedging - Effect of Trading and Non Trading Derivatives (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)			$ 43
Operating revenues	$ 6,974	$ 6,320	6,336
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Renewables
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Operating revenues	1,220	1,132	1,184
Renewables | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	2	0	(2)
Renewables | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(57)	(5)	78
Renewables | Operating Revenues | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	2	0	(2)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	1	(1)	(1)
Renewables | Operating Revenues | Trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(2)	(1)	3
Renewables | Operating Revenues | Trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	4	2	(3)
Renewables | Operating Revenues | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(1)	0	(1)
Renewables | Operating Revenues | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(101)	(7)	64
Operating revenues	6,974	6,320	6,336
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(1)	0	0
Renewables | Operating Revenues | Non-trading | Wholesale electricity contracts | Short
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(33)	6	40
Renewables | Operating Revenues | Non-trading | Financial power contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(42)	0	23
Renewables | Operating Revenues | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	(25)	(13)	1
Renewables | Purchased power, natural gas and fuel used | Trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Purchased power, natural gas and fuel used | Trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	0	0	0
Renewables | Purchased power, natural gas and fuel used | Non-trading
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	44	2	14
Purchased power, natural gas and fuel used	1,719	1,379	1,509
Renewables | Purchased power, natural gas and fuel used | Non-trading | Wholesale electricity contracts | Long
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	32	(4)	(1)
Renewables | Purchased power, natural gas and fuel used | Non-trading | Financial and natural gas contracts
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Total Gain (Loss)	$ 12	$ 6	$ 15

XML

Derivative Instruments and Hedging - Schedule of Fair Value Hedge (Details) - Interest Rate Swap $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Hedged asset, fair value hedge	$ 0
Hedged liability, fair value hedge	(19)
(Gain) Recognized in Income Statement	(3)
Fair Value Hedging
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Year to date total per Income Statement	298
Current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	0
Non-current debt
Derivative Instruments and Hedging Activities Disclosures [Line Items]
Cumulative effect on hedged debt	$ 19

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Leases - Narrative (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Lessee, Lease, Description [Line Items]
Renewal term	40 years
Finance lease liabilities	$ 95	$ 99
Renewables
Lessee, Lease, Description [Line Items]
Finance lease liabilities	$ 45	$ 47
Finance lease term	15 years
Early buyout option term	10 years
Renewables | Generation Facility
Lessee, Lease, Description [Line Items]
Useful life of facility	25 years
Min.
Lessee, Lease, Description [Line Items]
Remaining lease term	1 year
Max.
Lessee, Lease, Description [Line Items]
Remaining lease term	62 years

XML

Leases - Lease Cost (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Finance lease cost
Amortization of right-of-use assets	$ 8	$ 17	$ 12
Interest on lease liabilities	3	4	3
Total finance lease cost	11	21	15
Operating lease cost	14	16	18
Short-term lease cost	4	3	5
Variable lease cost	4	0	2
Sublease income	0	0	0
Total lease cost	$ 33	$ 40	$ 40

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Leases - Supplemental Balance Sheet (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Operating Leases
Operating lease right-of-use assets	$ 148	$ 153
Operating lease liabilities, current	12	8
Operating lease liabilities, long-term	149	154
Total operating lease liabilities	161	162
Finance Leases
Other assets	$ 156	$ 162
Finance Lease, Right-of-Use Asset, Statement of Financial Position [Extensible Enumeration]	Other Assets, Noncurrent	Other Assets, Noncurrent
Other current liabilities	$ 4	$ 8
Finance Lease, Liability, Current, Statement of Financial Position [Extensible Enumeration]	Other current liabilities	Other current liabilities
Other non-current liabilities	$ 91	$ 91
Finance Lease, Liability, Noncurrent, Statement of Financial Position [Extensible Enumeration]	Other Liabilities, Noncurrent	Other Liabilities, Noncurrent
Total finance lease liabilities	$ 95	$ 99
Weighted-average Remaining Lease Term (years)
Finance leases	7 years 3 months 18 days	8 years 1 month 13 days
Operating leases	20 years 6 months	21 years 4 months 17 days
Weighted-average Discount Rate
Finance leases	3.49%	3.71%
Operating leases	3.06%	3.21%

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Leases - Supplemental Cash Flow (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases	$ 16	$ 13	$ 13
Operating cash flows from finance leases	3	3	3
Repayments of financing leases	6	9	27
Right-of-use assets obtained in exchange for lease obligations:
Finance leases	0	46	1
Operating leases	$ 10	$ 94	$ 3

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Leases - Lease Maturities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Finance Leases
2022	$ 5
2023	53
2024	23
2025	2
2026	2
Thereafter	19
Total lease payments	104
Less: imputed interest	(9)
Total	95	$ 99
Operating Leases
2022	14
2023	14
2024	12
2025	11
2026	11
Thereafter	160
Total lease payments	223
Less: imputed interest	(62)
Total	$ 161	$ 162

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Commitments and Contingent Liabilities - Additional Information (Details) violation in Thousands, $ in Millions									1 Months Ended	12 Months Ended
	Nov. 20, 2020 violation	May 21, 2020	Nov. 21, 2019 complaint	Jan. 11, 2019 complaint	Mar. 22, 2016	Mar. 03, 2015	Oct. 16, 2014	Sep. 30, 2011	Apr. 30, 2018	Dec. 31, 2021 USD ($) project MW	Dec. 31, 2001 plaintiff	Aug. 12, 2021 USD ($)	Jan. 04, 2021 USD ($)	Dec. 31, 2020 USD ($)	Apr. 12, 2016 USD ($)
Loss Contingencies [Line Items]
Refund period, term								15 months
Approved return on equity		10.02%	9.88%
Regulatory liabilities										$ 3,022				$ 3,137
Number of complaints | complaint			2
Estimated reduction in earnings per year provided effective of supplemental notice of proposed rulemaking										3
Number of plaintiffs | plaintiff											2
Show cause order, period	30 days
Show cause order, number of alleged violations with civil action for injunctive relief | violation	11
Show cause order settlement payment												$ 3
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding										$ 483
Payment in lieu of taxes (pilot) agreement, number of projects | project										2
Payment In Lieu of Taxes (PILOT) agreement, payment amount										$ 1
NECEC commitment, amount													$ 90
NECEC commitment, payment during period										9
Max.
Loss Contingencies [Line Items]
Show cause order settlement payment												$ 5
Complaint III
Loss Contingencies [Line Items]
Regulatory liabilities										8
Complaint II
Loss Contingencies [Line Items]
Regulatory liabilities										27
Complaint II and III
Loss Contingencies [Line Items]
Reasonably possible loss, in additional reserve, pre tax										$ 17
California Energy Crisis Litigation
Loss Contingencies [Line Items]
Price of the PPAs															$ 259
Requested renewables delay from preliminary proposed ruling period									2 years
Unfavorable Regulatory Action | Complaint I
Loss Contingencies [Line Items]
Approved return on equity							10.57%
Number of complaints | complaint				4
Unfavorable Regulatory Action | Complaint I | Max.
Loss Contingencies [Line Items]
Approved return on equity					10.42%	11.74%	11.74%
Unfavorable Regulatory Action | Complaint III
Loss Contingencies [Line Items]
Approved return on equity					10.90%
Unfavorable Regulatory Action | Complaint III | Max.
Loss Contingencies [Line Items]
Approved return on equity					12.19%
Unfavorable Regulatory Action | Complaint II
Loss Contingencies [Line Items]
Approved return on equity					9.59%
Refund period					15 months
Before Amendment
Loss Contingencies [Line Items]
Requested return on equity base percentage								11.14%
Beginning in 2019 and Expiring in 2021 | Power purchase commitments | Hydro Capacity And Energy
Loss Contingencies [Line Items]
Power purchase commitment | MW										95.6
Period of purchase commitment										3 years
Beginning in 2019 and Expiring in 2023 | Power purchase commitments | Hydro Capacity And Energy
Loss Contingencies [Line Items]
Power purchase commitment | MW										52
Period of purchase commitment										5 years
2042 | Power purchase commitments | Hydro Capacity And Energy
Loss Contingencies [Line Items]
Power purchase commitment | MW										150
Vineyard Wind
Loss Contingencies [Line Items]
Standby letters of credit, surety bonds, guarantees and indemnifications outstanding										$ 21

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Commitments and Contingent Liabilities - Schedule of Forward Purchases and Sales Commitments Under Power, Gas, and Other Arrangements (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($)
Purchases
2022	$ 1,069
2023	168
2024	111
2025	65
2026	49
Thereafter	971
Totals	2,433
Sales
2022	227
2023	122
2024	75
2025	28
2026	37
Thereafter	72
Totals	$ 561

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Environmental Liabilities (Details)	12 Months Ended			65 Months Ended
	Dec. 31, 2021 USD ($) site	Dec. 31, 2011 site	Dec. 31, 2008 site	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Aug. 04, 2016 USD ($)
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	26
Number of sites with liability recorded	11
Number of sites note expected to incur additional liabilities	15
Number of additional sites with liability recorded	12
Number of sites where gas was manufactured in the past	53
Number of sites for which we have entered into consent orders to investigate and remediate	41
Accrual related to investigation and remediation | $	$ 303,000,000			$ 303,000,000	$ 300,000,000
Accrual related to investigation and remediation, amount recorded to date | $				35,000,000
First Energy
Environmental Exit Cost [Line Items]
Number of sites in dispute		16
United Illuminating Company (UI)
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 22,000,000			22,000,000	22,000,000	$ 30,000,000
New York State Registry
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	16
Number of sites where gas was manufactured in the past	6
Maine's Uncontrolled Sites Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	5
Number of sites where gas was manufactured in the past	2
Massachusetts Non- Priority Confirmed Disposal Site List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
National Priorities List
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	6
Ten of Twenty-five Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 7,000,000			7,000,000
New York Voluntary Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past	3
Maine's Voluntary Response Action Program
Environmental Exit Cost [Line Items]
Number of sites where gas was manufactured in the past	3
Manufactured Gas Plants | Connecticut
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 113,000,000			113,000,000	$ 96,000,000
Manufactured Gas Plants | Min.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	162,000,000			162,000,000
Manufactured Gas Plants | Max.
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	276,000,000			276,000,000
Properties Where MGPs Had Historically Operated
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 0			0
MGP Sites | First Energy
Environmental Exit Cost [Line Items]
Number of sites in dispute			2
Brownfield Cleanup Program
Environmental Exit Cost [Line Items]
Number of sites with potential remediation obligations	1
Another Ten Sites
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	$ 9,000,000			9,000,000
Another Ten Sites | Min.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	14,000,000			14,000,000
Another Ten Sites | Max.
Environmental Exit Cost [Line Items]
Estimated environmental liability | $	22,000,000			22,000,000
NYSEG | First Energy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	14,000,000			14,000,000
RG&E | First Energy
Environmental Exit Cost [Line Items]
Accrual related to investigation and remediation | $	$ 7,000,000			$ 7,000,000

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Income Taxes - Schedule of Current and Deferred Taxes Charged to (Benefit) Expense (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Current
Federal	$ 6	$ 3	$ 11
State	4	9	(6)
Current taxes charged to expense	10	12	5
Deferred
Federal	49	67	164
State	72	38	58
Deferred taxes charged to expense	121	105	222
Production tax credits	(109)	(87)	(57)
Investment tax credits	(1)	(1)	(1)
Total Income Tax Expense	$ 21	$ 29	$ 169

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Income Taxes - Schedule of Differences between Tax Expense Per Statements of Income and Tax Expense at Statutory Federal Tax Rate (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Income Tax Disclosure [Abstract]
Tax expense at federal statutory rate	$ 140	$ 119	$ 170
Depreciation and amortization not normalized	(19)	(13)	(23)
Investment tax credit amortization	(1)	(1)	(1)
Tax return related adjustments	0	1	(2)
Production tax credits	(109)	(87)	(57)
Tax equity financing arrangements	14	1	8
State tax expense (benefit), net of federal benefit	61	37	41
Excess ADIT amortization	(65)	(42)	0
Valuation allowance	21	12	4
Other, net	(21)	2	29
Total Income Tax Expense	$ 21	$ 29	$ 169

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Income Taxes - Schedule of Deferred Tax Assets and Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Deferred Income Tax Liabilities (Assets)
Property related	$ 4,257	$ 4,147
Unfunded future income taxes	104	100
Federal and state tax credits	(844)	(731)
Federal and state NOL’s	(998)	(1,047)
Joint ventures/partnerships	188	167
Nontaxable grant revenue	(292)	(311)
Pension and other post-retirement benefits	1	22
Tax Act - tax on regulatory remeasurement	(352)	(382)
Valuation allowance	110	81
Other	(158)	(127)
Deferred Income Tax Liabilities	2,016	1,919
Deferred tax assets	2,644	2,598
Deferred tax liabilities	4,660	4,517
Net Accumulated Deferred Income Tax Liabilities	$ 2,016	$ 1,919

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Income Taxes - Additional Information (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Income Taxes [Line Items]
Operating loss carryforwards, valuation allowance	$ 73
Deferred tax assets, valuation allowance	110	$ 81
Increase in valuation allowance, deferred tax asset	29
Unrecognized tax benefits that would impact effective tax rate	107
Federal
Income Taxes [Line Items]
Net operating loss carry forwards	3,600
Increase in valuation allowance, deferred tax asset	21
Federal | Renewable Energy and Investment
Income Taxes [Line Items]
Tax credit carry forward	805
State
Income Taxes [Line Items]
Net operating loss carry forwards	314
Tax credit carry forward	146
Operating loss carryforwards, valuation allowance	37
Increase in valuation allowance, deferred tax asset	$ 8

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Income Taxes - Schedule of Reconciliation of Unrecognized Income Tax Benefits (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Reconciliation of Unrecognized Tax Benefits, Excluding Amounts Pertaining to Examined Tax Returns [Roll Forward]
Beginning Balance	$ 127	$ 148	$ 153
Increases for tax positions related to prior years	3	11	14
Increases for tax positions related to current year	0	0	16
Decreases for tax positions related to prior years	(3)	(32)	(18)
Reduction for tax position related to settlements with taxing authorities	0	0	(17)
Ending Balance	$ 127	$ 127	$ 148

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Post-retirement and Similar Obligations - Obligations and Funded Status (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	$ 3,819	$ 3,669
Service cost	40	47
Interest cost	87	107
Plan amendments	2	7
Actuarial loss (gain)	(184)	236
Curtailments	(38)	(21)
Benefits paid	(239)	(226)
Benefit Obligation as of December 31,	3,487	3,819
Change in plan assets
Fair Value of Plan Assets as of January 1,	3,092	2,848
Actual return on plan assets	237	388
Employer contributions	27	84
Curtailments	(38)	(2)
Benefits paid	(239)	(226)
Fair Value of Plan Assets as of December 31,	3,079	3,092
Funded Status as of December 31,	(408)	(727)
Postretirement Benefits
Change in benefit obligation
Benefit Obligation as of January 1,	452	439
Service cost	3	3
Interest cost	10	13
Plan amendments	0	0
Actuarial loss (gain)	(23)	29
Curtailments	0	0
Benefits paid	(34)	(32)
Benefit Obligation as of December 31,	408	452
Change in plan assets
Fair Value of Plan Assets as of January 1,	167	155
Actual return on plan assets	15	26
Employer contributions	12	18
Curtailments	0	0
Benefits paid	(67)	(32)
Fair Value of Plan Assets as of December 31,	127	167
Funded Status as of December 31,	$ (281)	$ (285)

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Post-retirement and Similar Obligations - Additional Information (Details) $ in Millions	12 Months Ended
	Dec. 31, 2021 USD ($) trust	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)
Defined Benefit Plan Disclosure [Line Items]
Actuarial gain(loss) due to change in discount rates	$ 205	$ 276
Accumulated benefit obligation	$ 1,790	3,629
Amortization period	10 years
Annual contributions made	$ 58	49	$ 40
Non-Qualified Pension Plans
Defined Benefit Plan Disclosure [Line Items]
Other current and other non-current liabilities	63	59
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	(184)	236
Expected contribution for pension benefit plans during 2021	22
Other current and other non-current liabilities	$ 408	$ 727
Plan assets, number of trust | trust	1
Pension Benefits | Return-Seeking assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	25.00%
Pension Benefits | Return-Seeking assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	60.00%
Pension Benefits | Liability-Hedging assets | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	40.00%
Pension Benefits | Liability-Hedging assets | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	75.00%
Pension Benefits | Equity Securities | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		49.00%
Pension Benefits | Equity Securities | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		69.00%
Pension Benefits | Fixed Income Investments | Min.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		31.00%
Pension Benefits | Fixed Income Investments | Max.
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation		51.00%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Actuarial loss (gain)	$ (23)	$ 29
Expected contribution for pension benefit plans during 2021	11
Other current and other non-current liabilities	$ 281	$ 285
Plan assets, number of trust | trust	1
Postretirement Benefits | VEBA and 401(h) arrangements
Defined Benefit Plan Disclosure [Line Items]
Benefits plan, target asset allocation	54.00%

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Post-retirement and Similar Obligations - Summary of Liabilities Amount Recognized (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	$ 0	$ 0
Non-current liabilities	(408)	(727)
Total	(408)	(727)
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Current liabilities	(5)	(5)
Non-current liabilities	(276)	(280)
Total	$ (281)	$ (285)

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Post-retirement and Similar Obligations - Summary of Recognized as Regulatory Assets or Regulatory Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 271	$ 610
Prior service cost (credit)	10	10
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	(18)	14
Prior service cost (credit)	$ (1)	$ (8)

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Post-retirement and Similar Obligations - Summary of Amounts Recognized in Other Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ 16	$ 21
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Net loss (gain)	$ (5)	$ (7)

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Post-retirement and Similar Obligations - Schedule of Aggregate PBO and ABO and Fair Value of Plan Assets for Underfunded Plans (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Retirement Benefits [Abstract]
Projected benefit obligation	$ 3,487	$ 3,819
Fair value of plan assets	3,079	3,092
Accumulated benefit obligation	1,790	3,629
Fair value of plan assets	$ 1,536	$ 3,092

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Post-retirement and Similar Obligations - Schedule of Net Periodic Benefit Cost and Other Changes in Plan Assets and Benefit Obligations Recognized (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Net Periodic Benefit Cost:
Service cost	$ 40	$ 47
Interest cost	87	107
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	16	21
Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	3
Interest cost	10	13
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Net loss (gain)	(5)	(7)
Networks | Pension Benefits
Net Periodic Benefit Cost:
Service cost	39	46	$ 41
Interest cost	86	106	128
Expected return on plan assets	(199)	(198)	(190)
Amortization of prior service cost (benefit)	2	1	(1)
Amortization of net loss	115	124	113
Settlement charge	6
Net Periodic Benefit Cost	49	79	91
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	0	(18)	0
Settlement charge	6	0	0
Net loss (gain)	(218)	46	80
Amortization of net loss	(115)	(124)	(113)
Current year prior service cost (credit)	2	7	(2)
Amortization of prior service (cost) benefit	(2)	(1)	1
Net loss (gain)	(339)	(90)	(34)
Total Recognized	(290)	(11)	57
Networks | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	3	3	3
Interest cost	10	13	16
Expected return on plan assets	(7)	(8)	(7)
Amortization of prior service cost (benefit)	(5)	(9)	(10)
Amortization of net loss	2	2	1
Settlement charge	0
Net Periodic Benefit Cost	3	1	3
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments	0	0	0
Settlement charge	0	0	0
Net loss (gain)	(31)	11	13
Amortization of net loss	(2)	(2)	(1)
Current year prior service cost (credit)	1	0	0
Amortization of prior service (cost) benefit	5	9	10
Net loss (gain)	(27)	18	22
Total Recognized	(24)	19	25
ARHI | Pension Benefits
Net Periodic Benefit Cost:
Service cost	1	1	1
Interest cost	1	1	2
Expected return on plan assets	(2)	(2)	(2)
Amortization of net loss	2	2	1
Settlement charge	1	1	0
Net Periodic Benefit Cost	3	3	2
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlement charge	1	0	0
Net loss (gain)	(3)	1	0
Amortization of net loss	(2)	(2)	(1)
Amortization of prior service (cost) benefit	0	0	0
Net loss (gain)	(6)	(1)	(1)
Total Recognized	(3)	2	1
ARHI | Postretirement Benefits
Net Periodic Benefit Cost:
Service cost	0	0	0
Interest cost	0	0	0
Expected return on plan assets	0	0	0
Amortization of net loss	(1)	(1)	(1)
Settlement charge	0	0	0
Net Periodic Benefit Cost	(1)	(1)	(1)
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Settlement charge	1	0	0
Net loss (gain)	1	0	0
Amortization of net loss	1	1	1
Amortization of prior service (cost) benefit	0	0	(2)
Net loss (gain)	1	1	(1)
Total Recognized	$ 0	$ 0	$ (2)

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Post-retirement and Similar Obligations - Schedule of Weighted-Average Assumptions Used to Determine Benefit Obligations and Net Periodic Benefit Cost (Details)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.85%	2.34%
Rate of compensation increase - benefit obligations	3.53%	3.52%
Interest crediting rate	2.87%	2.87%
Discount rate - net periodic benefit	2.34%	3.01%	3.98%
Expected long-term return on plan assets	7.30%	7.30%	7.30%
Rate of compensation increase - net periodic benefit	3.52%	3.66%	3.79%
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Discount rate - benefit obligations	2.66%	2.19%
Rate of compensation increase - benefit obligations	3.50%	3.50%
Discount rate - net periodic benefit	2.19%	2.99%	3.97%
Expected long-term return on plan assets	4.05%	5.09%	5.08%
Rate of compensation increase - net periodic benefit	3.50%	3.48%	3.50%

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Post-retirement and Similar Obligations - Schedule of Assumed Health Care Cost Trend Rates Used to Determine Benefit Obligations (Details)	Dec. 31, 2021	Dec. 31, 2020
Defined Benefit Plan Disclosure [Line Items]
Rate to which cost trend rate is assumed to decline (ultimate trend rate)	4.50%	4.50%
Min.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	5.00%	5.25%
Max.
Defined Benefit Plan Disclosure [Line Items]
Health care cost trend rate assumed for next year	7.00%	7.25%

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Post-retirement and Similar Obligations - Estimated Future Benefit Payments (Details) $ in Millions	Dec. 31, 2021 USD ($)
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	$ 217
2023	212
2024	214
2025	213
2026	215
2027 - 2031	1,057
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
2022	30
2023	29
2024	29
2025	28
2026	27
2027 - 2031	$ 122

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Post-retirement and Similar Obligations - Fair Values of Pension Plan Assets by Asset Category (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Pension Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 3,079	$ 3,092	$ 2,848
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	2,532	2,484
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	69	120
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	298	177
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	138	107
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	276	301
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	837	710
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	862	1,018
Pension Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	51	50
Pension Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	733	592
Pension Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	20	0
Pension Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	298	177
Pension Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	138	107
Pension Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	276	301
Pension Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Pension Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	6
Pension Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1,799	1,892
Pension Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	49	120
Pension Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	837	710
Pension Benefits | Level 2 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	862	1,018
Pension Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	51	44
Pension Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Pension Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	547	608
Postretirement Benefits
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	127	167	$ 155
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	125	164
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	6
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	101	141
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	3
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	4
Postretirement Benefits | Fair Value, Inputs, Level 1, 2 and 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	9	9
Postretirement Benefits | Level 1
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	103	142
Postretirement Benefits | Level 1 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1	1
Postretirement Benefits | Level 1 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	1
Postretirement Benefits | Level 1 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	101	141
Postretirement Benefits | Level 1 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 1 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 1 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	22	22
Postretirement Benefits | Level 2 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	6
Postretirement Benefits | Level 2 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 2 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 2 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	3	3
Postretirement Benefits | Level 2 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 2 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	5	4
Postretirement Benefits | Level 2 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	9	9
Postretirement Benefits | Level 3
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Cash and cash equivalents
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | U.S. government securities
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Common stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 3 | Registered investment companies
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Corporate bonds
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Preferred stocks
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0
Postretirement Benefits | Level 3 | Common collective trusts
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Level 3 | Other, principally annuity, fixed income
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	0	0
Postretirement Benefits | Other investments measured at net asset value
Defined Benefit Plan Disclosure [Line Items]
Defined benefit plan, plan assets, amount	$ 2	$ 3

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Equity - Additional Information (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	May 18, 2021	Dec. 31, 2019
Class of Stock [Line Items]
Treasury stock, shares (in shares)	112,543	413,782
Release of common stock held in trust (in shares)	301,239	72,028
Common stock, par value (in dollars per share)	$ 0.01	$ 0.01	$ 0.01	$ 0.01
Number of shares repurchased during period (in shares)	694,148
Treasury shares (in shares)	997,983
Repurchases of common stock	$ 47	$ 14
Convertible Preferred Stock
Class of Stock [Line Items]
Preferred stock, shares outstanding (in shares)	0	0
Common Stock
Class of Stock [Line Items]
Issuance of common stock (in shares)	77,883,713	42,777
Iberdrola Renewables Holding, Inc
Class of Stock [Line Items]
Percentage of equity owned by parent	81.50%

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Equity - Accumulated Other Comprehensive Income (Loss) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	$ 15,826	$ 15,539	$ 15,389
Change	(162)	(16)	(11)
Balance at end of period	19,961	15,826	15,539
Change in revaluation of defined benefit plans, net of income tax expense (benefit)	0	0	0
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit)	1	3	1
Unrealized loss from equity method investment, net of income tax benefit	(3)	0	0
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)	(44)	(7)	(9)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)	(3)	2	3
Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period		(1)	(1)
Balance at end of period			(1)
Change in revaluation of defined benefit plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(12)	(12)	(11)
Change	2	0	1
Balance at end of period	(10)	(12)	(12)
Change in revaluation of defined benefit plans, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			(2)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(20)	(7)	(6)
Change	(8)	(13)	(1)
Balance at end of period	(28)	(20)	(7)
Loss (gain) for nonqualified pension plans, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			0
Unrealized loss from equity method investment, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	0	0	0
Change	(9)	0	0
Balance at end of period	(9)	0	0
Unrealized loss from equity method investment, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			0
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(35)	(13)	9
Change	(159)	(22)	(22)
Balance at end of period	(194)	(35)	(13)
Unrealized gain (loss) during period on derivatives qualifying as cash flow hedges, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			0
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit)
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(44)	(63)	(64)
Change	12	19	11
Balance at end of period	(32)	(44)	(63)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax expense (benefit) | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			(10)
Loss on derivatives qualifying as cash flow hedges
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(79)	(76)	(55)
Change	(147)	(3)	(11)
Balance at end of period	(226)	(79)	(76)
Loss on derivatives qualifying as cash flow hedges | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			(10)
Accumulated Other Comprehensive Loss
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period	(111)	(95)	(72)
Change	(162)	(16)	(11)
Balance at end of period	$ (273)	$ (111)	(95)
Accumulated Other Comprehensive Loss | Cumulative Effect, Period of Adoption, Adjustment
Accumulated Other Comprehensive Income (Loss)
Balance at beginning of period			$ (12)

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Earnings Per Share (Details) - USD ($) $ / shares in Units, $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Numerator:
Net income attributable to AVANGRID, basic	$ 707	$ 581	$ 667
Net income attributable to AVANGRID, diluted	$ 707	$ 581	$ 667
Denominator:
Weighted average number of shares outstanding - basic (in shares)	358,086,621	309,494,939	309,491,082
Weighted average number of shares outstanding - diluted (in shares)	358,578,608	309,559,387	309,514,910
Earnings per share attributable to AVANGRID
Earnings Per Common Share, Basic (in dollars per share)	$ 1.97	$ 1.88	$ 2.16
Earnings Per Common Share, Diluted (in dollars per share)	$ 1.97	$ 1.88	$ 2.16

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Variable Interest Entities (Details) $ in Millions	Nov. 04, 2021 USD ($)	Sep. 09, 2021 USD ($)	Feb. 05, 2021 agreement MW	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)
Variable Interest Entity [Line Items]
Assets of variable interest entities (VIEs)				$ 39,504	$ 37,823
Liabilities of variable interest entities (VIEs)				19,543	21,997
Variable Interest Entity, Primary Beneficiary
Variable Interest Entity [Line Items]
Proceeds from Sale of Interest in Partnership Unit	$ 199	$ 131
Noncontrolling Interest, Increase from Sale of Parent Equity Interest		8
Noncontrolling interest in variable interest entity		$ 139
Proceeds from sale of interest in partnership unit, amount held in escrow	$ 8
Assets of variable interest entities (VIEs)				2,039	1,713
Liabilities of variable interest entities (VIEs)				$ 119	$ 107
Patriot Wind Farm LLC
Variable Interest Entity [Line Items]
Number of TEF agreements | agreement			4
Proposed wind farm and electricity transmission project capacity (in MW) | MW			688

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Grants, Government Incentives and Deferred Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	$ 1,204	$ 1,274
Disposals	0	(2)
Recognized in income	(74)	(68)
Balance at end of period	1,130	1,204
Government grants
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	1,190	1,258
Disposals	0	(2)
Recognized in income	(65)	(66)
Balance at end of period	1,125	1,190
Other deferred income
Deferred Credits and Other Liabilities [Roll Forward]
Balance at beginning of period	14	16
Disposals	0	0
Recognized in income	(9)	(2)
Balance at end of period	$ 5	$ 14

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Equity Method Investments (Details)			1 Months Ended				12 Months Ended
	Dec. 16, 2020 USD ($)	Dec. 13, 2019 USD ($)	Dec. 31, 2021 USD ($) a plant jointVenture MW	Dec. 31, 2020 USD ($)	Dec. 31, 2019 MW	Dec. 31, 2018 USD ($)	Dec. 31, 2021 USD ($) a plant jointVenture MW	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($) MW	Sep. 15, 2021 USD ($)
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 560,000,000	$ 668,000,000			$ 560,000,000	$ 668,000,000
Distribution of earnings from equity method investments							21,000,000	22,000,000	$ 17,000,000
Equity method investment, distributions received in RECs							11,000,000	14,000,000	9,000,000
Undistributed earnings from equity method investees			10,000,000				10,000,000
Capitalized interest costs							6,000,000	8,000,000	7,000,000
South Dokata Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments	$ 24,000,000		$ 23,000,000	24,000,000			23,000,000	24,000,000
Enterprise value	$ 298,000,000
Gain related to remeasurement of retained investment							$ 4,000,000
Equity method investment, ownership percentage			15.00%				15.00%
South Dokata Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold	85.00%
Consideration from disposition	$ 238,000,000
Gain on sale of business, net of tax	12,000,000
Gain on sale of business, pre-tax	$ 16,000,000
Effective percentage of economic benefits retained	7.97%
Arizona Wind Farm
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 96,000,000	104,000,000			$ 96,000,000	104,000,000
Equity method investment, ownership percentage			50.00%				50.00%
Arizona Wind Farm | Sale of Business
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold		50.00%
Consideration from disposition		$ 112,000,000
Gain on sale of business, net of tax		96,000,000
Gain on sale of business, pre-tax		134,000,000
Net gain related to remeasurement of retained investment		$ 50,000,000
Coyote Ridge Wind LLC
Schedule of Equity Method Investments [Line Items]
Percentage of ownership interest sold						80.00%				80.00%
Equity method investments			$ 15,000,000	16,000,000			$ 15,000,000	16,000,000
Equity method investment, ownership percentage			20.00%				20.00%
Proceeds from sale of portion of subsidiary						$ 144,000,000			84,000,000
Gain (loss) on sale of equity method investee									$ 4,000,000	$ 10,000,000
Horizon Wind Energy LLC
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%				50.00%
Number of joint ventures | jointVenture			2				2
Flat Rock Wind Power LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 93,000,000	98,000,000			$ 93,000,000	98,000,000
Leased are transmission capacity (in MW) | MW							231
Flat Rock Wind Power II LLC
Schedule of Equity Method Investments [Line Items]
Equity method investments			44,000,000	47,000,000			$ 44,000,000	47,000,000
Leased are transmission capacity (in MW) | MW							91
Vineyard Wind
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 141,000,000	$ 245,000,000			$ 141,000,000	$ 245,000,000
Equity method investment, ownership percentage			50.00%				50.00%
Area of land | a			166,886				166,886
Proposed wind farm and electricity transmission project capacity (in MW) | MW			1,232		804					800
Vineyard Wind | AVANGRID Renewables
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage				50.00%				50.00%
Amount funded to date				$ 33,000,000				$ 100,000,000
Joint Venture With CIP
Schedule of Equity Method Investments [Line Items]
Amount of guaranty issued											$ 827,000,000
Amount contributed to acquire easement contract, returned											152,000,000
Joint Venture With CIP | Letter of Credit
Schedule of Equity Method Investments [Line Items]
Credit facility maximum borrowing capacity											1,200,000,000
Joint Venture With CIP | Renewables
Schedule of Equity Method Investments [Line Items]
Equity method investment, ownership percentage			50.00%				50.00%
Joint venture restructuring agreement, payment amount											$ 168,000,000
Joint Venture With CIP | Renewables | Min.
Schedule of Equity Method Investments [Line Items]
Joint venture restructuring agreement, gain expected to recognize			$ 175,000,000				$ 175,000,000
Joint Venture With CIP | Renewables | Max.
Schedule of Equity Method Investments [Line Items]
Joint venture restructuring agreement, gain expected to recognize			200,000,000				200,000,000
Clearway Energy, Inc
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 99,000,000	104,000,000			$ 99,000,000	104,000,000
Equity method investment, ownership percentage			50.00%				50.00%
Number of peaking generation plants | plant			2				2
New York TransCo.
Schedule of Equity Method Investments [Line Items]
Equity method investments			$ 49,000,000	30,000,000			$ 49,000,000	30,000,000
Equity method investment, ownership percentage			20.00%				20.00%
Leased are transmission capacity (in MW) | MW							3,200
Amount funded to date							$ 600,000,000	600,000,000
Portion of amount receivable from related parties			$ 0	$ 0			$ 0	$ 0

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Other Financial Statements Items - Schedule of Other Income and (Expense) (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Gain on sale of assets	$ 0	$ 20	$ 148
Allowance for funds used during construction	88	56	46
Carrying costs on regulatory assets	17	28	21
Non-service component of net periodic benefit cost	(37)	(62)	(79)
Other	(8)	(24)	(15)
Total Other Income (Expense)	$ 60	18	121
Tatanka Project
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee		$ 16
Poseidon Project
Schedule of Investments [Line Items]
Gain (loss) on sale of equity method investee			$ 134

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Other Financial Statements Items - Schedule of Accounts Receivable (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Trade receivables and unbilled revenues	$ 1,420	$ 1,295
Allowance for credit losses	(151)	(108)	$ (69)	$ (62)
Total Accounts receivable and unbilled revenues, net	$ 1,269	$ 1,187

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Other Financial Statements Items - Schedule of Change in Allowance For Bad Debts (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Accounts Receivable, Allowance for Credit Loss [Roll Forward]
Beginning balance	$ 108	$ 69	$ 62
Current period provision	110	83	92
Write-off as uncollectible	(67)	(44)	(85)
Ending balance	$ 151	$ 108	$ 69

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Other Financial Statements Items - Additional Information (Details) $ in Millions	May 13, 2021 USD ($) project	Dec. 31, 2021 USD ($)	Dec. 31, 2020 USD ($)	Dec. 31, 2019 USD ($)	Dec. 31, 2018 USD ($)
Accounts, Notes, Loans and Financing Receivable [Line Items]
Allowance for credit losses		$ 151	$ 108	$ 69	$ 62
Sale of Business | Solar Projects In Nevada
Accounts, Notes, Loans and Financing Receivable [Line Items]
Percentage disposed	100.00%
Number of projects disposed | project	2
Consideration from disposition	$ 35
Gain on disposal, net of tax	11
Pre-tax gain on disposal	$ 15
Deferred Payment Arrangements
Accounts, Notes, Loans and Financing Receivable [Line Items]
Accounts receivable		108	78
Allowance for credit losses		$ 68	$ 48

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Other Financial Statements Items - Schedule of Prepayments and Other Current Assets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Organization, Consolidation and Presentation of Financial Statements [Abstract]
Prepaid other taxes	$ 95	$ 135
Short-term investment	0	300
Broker margin and collateral accounts	87	30
Other pledged deposits	4	2
Prepaid expenses	58	41
Other	1	17
Total	$ 245	$ 525

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Other Financial Statements Items - Schedule of Other Current Liabilities (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Payables and Accruals [Abstract]
Advances received	$ 204	$ 141
Accrued salaries	127	109
Short-term environmental provisions	52	49
Collateral deposits received	58	42
Pension and other postretirement	5	5
Finance leases	4	8
Other	34	14
Total	$ 484	$ 368

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Segment Information - Additional Information (Details)	12 Months Ended
	Dec. 31, 2021 segment
Segment Reporting Information [Line Items]
Number of reportable segments	2
Networks
Segment Reporting Information [Line Items]
Number of reportable segments	1
Number of operating segments	9

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Segment Information - By Segment (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting Information [Line Items]
Operating Revenues	$ 6,974	$ 6,320	$ 6,336
Depreciation and amortization	1,014	987	933
Operating income	895	869	998
(Losses) earnings from equity method investments	7	(3)	3
Interest expense, net of capitalization	298	316	310
Income tax expense (benefit)	21	29	169
Capital expenditures	2,976	2,781	2,735
Adjusted net income	780	625	640
Property, plant and equipment	28,866	26,751
Equity method investments	560	668
Total assets	39,504	37,823
Other
Segment Reporting Information [Line Items]
Operating Revenues	1	1	2
Depreciation and amortization	1	1	1
Operating income	(7)	8	15
(Losses) earnings from equity method investments	0	0	0
Interest expense, net of capitalization	80	75	27
Income tax expense (benefit)	(29)	(11)	(11)
Capital expenditures	2	0	3
Adjusted net income	(51)	(58)	(17)
Property, plant and equipment	11	10
Equity method investments	0	0
Total assets	800	364
Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	(1)	(1)	(14)
Networks
Segment Reporting Information [Line Items]
Operating Revenues	5,754	5,188	5,164
Networks | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	1	1	14
Networks | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	5,753	5,187	5,150
Depreciation and amortization	616	592	549
Operating income	876	877	890
(Losses) earnings from equity method investments	12	10	11
Interest expense, net of capitalization	217	234	269
Income tax expense (benefit)	98	120	152
Capital expenditures	2,294	1,838	1,610
Adjusted net income	661	568	465
Property, plant and equipment	18,737	17,079
Equity method investments	148	134
Total assets	26,126	24,592
Renewables
Segment Reporting Information [Line Items]
Operating Revenues	1,220	1,132	1,184
Renewables | Intersegment Eliminations
Segment Reporting Information [Line Items]
Operating Revenues	0	0	0
Renewables | Operating Segments
Segment Reporting Information [Line Items]
Operating Revenues	1,220	1,132	1,184
Depreciation and amortization	397	394	383
Operating income	26	(16)	93
(Losses) earnings from equity method investments	(5)	(13)	(8)
Interest expense, net of capitalization	1	7	14
Income tax expense (benefit)	(48)	(80)	28
Capital expenditures	680	943	1,122
Adjusted net income	170	115	$ 193
Property, plant and equipment	10,118	9,662
Equity method investments	412	534
Total assets	$ 12,578	$ 12,867

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Segment Information - Reconciliation of Consolidated EBITDA to Consolidated Net Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Segment Reporting [Abstract]
Adjusted Net Income Attributable to Avangrid, Inc.	$ 780	$ 625	$ 640
Adjustments:
Mark-to-market adjustments - Renewables	(53)	(5)	76
Restructuring charges	0	(6)	(6)
Accelerated depreciation from repowering	0	(9)	(33)
Impact of COVID-19	(34)	(29)	0
Merger costs	(12)	(6)	0
Proceeds from Legal Settlements	0	(5)	0
Income tax impact of adjustments	26	16	(10)
Net Income Attributable to Avangrid, Inc.	$ 707	$ 581	$ 667

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Related Party Transactions - Schedule of Related Party Transactions (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Iberdrola, S.A.
Related Party Transaction [Line Items]
Sales To	$ 0	$ 1	$ 1
Purchases From	(52)	(43)	(42)
Iberdrola Renovables Energia, S.L.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(10)	(9)	(9)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Sales To	0	0	0
Purchases From	(9)	(7)	(3)
Vineyard Wind
Related Party Transaction [Line Items]
Sales To	14	9	13
Purchases From	0	0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Sales To	7	2	1
Purchases From	(39)	0	0
Other
Related Party Transaction [Line Items]
Sales To	2	0	1
Purchases From	$ (3)	$ 0	$ (3)

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Related Party Transactions - Additional Information (Details) - USD ($)	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Jan. 31, 2020
Iberdrola
Related Party Transaction [Line Items]
Deposit balance	$ 0	$ 0
Iberdrola | Siemens Gamesa
Related Party Transaction [Line Items]
Ownership percentage by noncontrolling owners			8.10%
Iberdrola Financiacion S A U
Related Party Transaction [Line Items]
Line of credit facility, maximum borrowing capacity	$ 500,000,000
Credit facility fees percentage	0.105%
Credit facility, amount outstanding	$ 0	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Notes payable, related parties	2,000,000	5,000,000
Affiliated Entity
Related Party Transaction [Line Items]
Asset impairment charges	$ 0
Siemens Gamesa | Iberdrola
Related Party Transaction [Line Items]
Related party transaction, amount		$ 11,000,000

XML

Related Party Transactions - Schedule of Related Party Balances (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020
Iberdrola, S.A.
Related Party Transaction [Line Items]
Owed By	$ 3	$ 2
Owed To	(43)	(43)
Iberdrola Financiación, S.A.
Related Party Transaction [Line Items]
Owed By	0	0
Owed To	(9)	(6)
Siemens Gamesa
Related Party Transaction [Line Items]
Owed By	8	4
Owed To	(8)	0
Vineyard Wind
Related Party Transaction [Line Items]
Owed By	0	5
Owed To	(2)	0
Iberdrola Solutions
Related Party Transaction [Line Items]
Owed By	0	1
Owed To	$ (1)	$ (1)

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Stock-Based Compensation - Additional Information (Details) $ / shares in Units, $ in Millions	1 Months Ended												12 Months Ended
	Jan. 31, 2022 $ / shares shares	Jun. 30, 2021 $ / shares shares	Mar. 31, 2021 USD ($) installment $ / shares shares	Feb. 28, 2021 shares	Dec. 31, 2020 USD ($) installment $ / shares	Aug. 31, 2020 installment $ / shares shares	Jun. 30, 2020 USD ($) installment shares	May 31, 2020 shares	Mar. 31, 2020 installment shares	Feb. 29, 2020 installment shares	Oct. 31, 2018 set $ / shares shares	Jun. 30, 2018 set $ / shares shares	Dec. 31, 2021 USD ($) installment $ / shares shares	Dec. 31, 2020 USD ($) $ / shares	Dec. 31, 2019 USD ($) shares	Dec. 31, 2018 shares	Dec. 31, 2017 shares	Dec. 31, 2016 $ / shares shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares authorized for stock-based compensation plans (in shares)													2,500,000
Number of shares granted (in shares)													1,359,516
Share-based payment award grant date fair value (in dollars per share) | $ / shares													$ 36.49
Number of shares forfeited (in shares)								2,605					90,603
Number of vesting installments | installment													3
Grant date fair value (in dollars per share) | $ / shares					$ 32.42								$ 36.05	$ 32.42
Number of awards set granted | set											2	2
Stock-based compensation expense | $													$ 18	$ 14	$ 3
Income tax benefit recognized for stock-based compensation arrangements | $													5	4	$ 1
Unrecognized cost for non-vested PSUs | $													$ 25
Recognition of PSU costs, weighted-average period													3 years
Performance Shares Units
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)										208,268			1,336,787
Share-based payment award options requisite service period													4 years
Number of shares issued (in shares)			45,661					42,777
Grant date fair value (in dollars per share) | $ / shares													$ 36.22
Performance Shares Units | Officers and Employees
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)															3,881	75,350	85,759	1,298,683
Share-based payment award grant date fair value (in dollars per share) | $ / shares																		$ 31.80
Share-based payment award options requisite service period																		7 years
Number of vesting installments | installment										3
Restricted Stock Units (RSUs)
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares issued (in shares)			5,953				60,000
Cash used to settle award | $							$ 3
Restricted Stock Units (RSUs) | Executive Officer
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)		17,500	5,000			5,000					8,000	60,000
Share-based payment award grant date fair value (in dollars per share) | $ / shares											$ 47.59	$ 50.40
Number of vesting installments | installment			1		1	3	1
Number of shares issued (in shares)		9,390		1,697
Grant date fair value (in dollars per share) | $ / shares		$ 53.59	$ 48.83			$ 48.99
Restricted Stock Units (RSUs) | Executive Officer | Subsequent Event
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)	17,500
Number of shares issued (in shares)	9,390
Grant date fair value (in dollars per share) | $ / shares	$ 48.16
Phantom Shares
Share-based Compensation Arrangement by Share-based Payment Award [Line Items]
Number of shares granted (in shares)									167,060
Number of vesting installments | installment									3
Cash used to settle award | $			$ 2				$ 2
Share based compensation liability | $					$ 2								$ 2	$ 2

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Stock-Based Compensation - Summary of Nonvested PSUs and RSUs (Details) - $ / shares	1 Months Ended	12 Months Ended
	May 31, 2020	Dec. 31, 2021
Number of PSUs and RSUs
Nonvested Balance – beginning of year (in shares)		142,167
Granted (in shares)		1,359,516
Forfeited (in shares)	(2,605)	(90,603)
Vested (in shares)		(87,751)
Nonvested Balance – end of year (in shares)		1,323,328
Weighted Average Grant Date Fair Value
Nonvested Balance – beginning of year (in dollars per share)		$ 32.42
Granted (in dollars per share)		36.49
Forfeited (in dollars per share)		36.63
Vested (in dollars per share)		47.70
Nonvested Balance – end of year (in dollars per share)		$ 36.05

XML

Subsequent events (Details) - $ / shares		12 Months Ended
	Feb. 16, 2022	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Subsequent Event [Line Items]
Dividends declared (in dollars per share)		$ 1.76	$ 1.76	$ 1.76
Subsequent Event
Subsequent Event [Line Items]
Dividends declared (in dollars per share)	$ 0.44

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CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Income Statements, Captions [Line Items]
Operating Revenues	$ 6,974	$ 6,320	$ 6,336
Operating Expenses
Taxes other than income taxes	640	619	591
Total Operating Expenses	6,079	5,451	5,338
Operating Income	895	869	998
Other Income
Other income	60	18	121
Interest expense	(298)	(316)	(310)
Income Before Income Tax	664	568	812
Income tax expense (benefit)	21	29	169
Net Income Attributable to Avangrid, Inc.	707	581	667
AVANGRID
Condensed Income Statements, Captions [Line Items]
Operating Revenues	0	0	0
Operating Expenses
Operating expense	19	10	3
Taxes other than income taxes	(11)	(11)	(12)
Total Operating Expenses	8	(1)	(9)
Operating Income	(8)	1	9
Other Income
Other income	22	35	59
Equity earnings of subsidiaries	756	641	678
Interest expense	(93)	(109)	(93)
Income Before Income Tax	677	568	653
Income tax expense (benefit)	(30)	(13)	(14)
Net Income Attributable to Avangrid, Inc.	$ 707	$ 581	$ 667

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CONDENSED FINANCIAL INFORMATION OF PARENT - Statements of Comprehensive Income (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Statement of Income Captions [Line Items]
Net Income	$ 707	$ 581	$ 667
Comprehensive Income Attributable to Avangrid, Inc.	545	565	656
AVANGRID
Condensed Statement of Income Captions [Line Items]
Net Income	707	581	667
Other comprehensive loss of subsidiaries	(162)	(16)	(11)
Comprehensive Income Attributable to Avangrid, Inc.	$ 545	$ 565	$ 656

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CONDENSED FINANCIAL INFORMATION OF PARENT - Balance Sheets (Details) - USD ($) $ in Millions	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 31, 2018
Current Assets
Cash and cash equivalents	$ 1,474	$ 1,463
Accounts receivable from subsidiaries	11	12
Prepayments and other current assets	245	525
Total Current Assets	3,777	3,777
Other assets
Other	374	331
Total Other Assets	3,845	3,834
Total Assets	39,504	37,823
Current Liabilities
Accounts payable and accrued liabilities	1,586	1,453
Accounts payable to subsidiaries	61	50
Interest accrued	69	70
Dividends payable	170	136
Total Current Liabilities	3,329	3,069
Derivative liabilities	160	79
Non-current debt	7,922	7,478
Non-current debt to affiliate	0	3,000
Total non-current liabilities	16,214	18,928
Total Liabilities	19,543	21,997
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	17,679	13,665
Treasury stock	(47)	(14)
Retained earnings	1,714	1,666
Accumulated other comprehensive loss	(273)	(111)
Total Equity	19,961	15,826	$ 15,539	$ 15,389
Total Liabilities and Equity	39,504	37,823
AVANGRID
Current Assets
Cash and cash equivalents	1,424	1,438
Accounts receivable from subsidiaries	128	124
Notes receivable from subsidiaries	1,475	1,489
Prepayments and other current assets	52	357
Total Current Assets	3,079	3,408
Investments in subsidiaries	18,500	18,356
Other assets
Deferred income taxes	413	388
Other	3	3
Total Other Assets	416	391
Total Assets	21,995	22,155
Current Liabilities
Notes payable	0	308
Notes payable to subsidiaries	643	1,375
Accounts payable and accrued liabilities	3	12
Accounts payable to subsidiaries	9	9
Interest accrued	9	9
Interest accrued subsidiaries	1	10
Dividends payable	170	136
Total Current Liabilities	835	1,859
Derivative liabilities	19	0
Non-current debt	2,065	2,087
Non-current debt to affiliate	0	3,000
Total non-current liabilities	2,084	5,087
Total Liabilities	2,919	6,946
Stockholders' Equity:
Common stock	3	3
Additional paid-in capital	17,679	13,665
Treasury stock	(47)	(14)
Retained earnings	1,714	1,666
Accumulated other comprehensive loss	(273)	(111)
Total Equity	19,076	15,209
Total Liabilities and Equity	$ 21,995	$ 22,155

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CONDENSED FINANCIAL INFORMATION OF PARENT - Statement of Cash Flows (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	$ 1,561	$ 1,288	$ 1,588
Cash Flow from Investing Activities
Net Cash Used in Investing Activities	(2,440)	(2,858)	(2,708)
Cash Flow from Financing Activities
Proceeds from non-current debt	833	1,367	2,137
(Repayments) proceeds from non-current debt with affiliate	0	3,000	0
Repurchase of common stock	(33)	(2)	0
Dividends paid	(613)	(545)	(545)
Net Cash Provided by Financing Activities	889	2,853	1,261
Net Increase in Cash, Cash Equivalents and Restricted Cash	10	1,283	141
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,467	184	43
Cash, Cash Equivalents and Restricted Cash, End of Year	1,477	1,467	184
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	279	278	270
Cash paid for income taxes	2	8	2
AVANGRID
Condensed Cash Flow Statements, Captions [Line Items]
Net Cash used in Operating Activities	(397)	(142)	(1,299)
Cash Flow from Investing Activities
Notes receivable from subsidiaries	130	(73)	633
Investments in subsidiaries	(1,026)	(591)	(399)
Return of capital from investments in subsidiaries	1,122	419	433
Other investments	300	(300)	0
Net Cash Used in Investing Activities	526	(545)	667
Cash Flow from Financing Activities
(Repayments) receipts of short-term notes payable from subsidiaries, net	(186)	(14)	107
Repayments of short-term notes payable	(309)	(253)	(27)
Proceeds from non-current debt	0	744	1,243
(Repayments) proceeds from non-current debt with affiliate	(3,000)	3,000	0
Repayments of non-current debt	0	(950)	0
Repurchase of common stock	(33)	(2)	0
Issuance of common stock	3,998	(1)	0
Dividends paid	(613)	(545)	(545)
Net Cash Provided by Financing Activities	(143)	1,979	778
Net Increase in Cash, Cash Equivalents and Restricted Cash	(14)	1,292	146
Cash, Cash Equivalents and Restricted Cash, Beginning of Year	1,438	146	0
Cash, Cash Equivalents and Restricted Cash, End of Year	1,424	1,438	146
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized	74	111	85
Cash paid for income taxes	$ (15)	$ 65	$ 43

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CONDENSED FINANCIAL INFORMATION OF PARENT - Basis Of Presentation (Details) $ / shares in Units, $ in Millions	May 18, 2021 USD ($) placement $ / shares shares	Apr. 15, 2021	Oct. 20, 2020 USD ($) $ / shares	Dec. 31, 2021 $ / shares	Dec. 31, 2020 $ / shares	Dec. 31, 2019 $ / shares
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	77,821,012
Sale of stock, number of placements | placement	2
Common stock, par value (in dollars per share) | $ / shares	$ 0.01			$ 0.01	$ 0.01	$ 0.01
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	$ 3,000
AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	77,821,012
Sale of stock, number of placements | placement	2
Common stock, par value (in dollars per share) | $ / shares	$ 0.01			$ 0.01	$ 0.01
Sale of stock, price (in dollars per share) | $ / shares	$ 51.40
Proceeds of private placements	$ 4,000
Proceeds of private placements used to repay debt	$ 3,000
Iberdrola S.A. | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	63,424,125
Avangrid | Iberdrola S.A.
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Percentage of equity owned by parent				81.60%
Avangrid | Iberdrola S.A. | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Percentage of equity owned by parent				81.50%
Hyde Member LLC and Subsidiary of Qatar Investment Authority
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
Hyde Member LLC and Subsidiary of Qatar Investment Authority | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Sale of stock, number of shares issued (in shares) | shares	14,396,887
NM Green Holdings, Inc.
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Merger agreement, share price (in dollars per share) | $ / shares			$ 50.30
Merger agreement term, ownership percentage benchmark			15.00%
Merger agreement, termination rights term, extension period			3 months
Merger agreement, termination rights term, termination fees			$ 130
Merger agreement, termination rights term, termination fees as remedy			184
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			10
NM Green Holdings, Inc. | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Merger agreement, termination rights term, termination fees as remedy			184
Merger agreement, termination rights term, termination fees, out-of-pocket fees and expenses reimbursable limit (up to)			$ 10
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%
NM Green Holdings, Inc. | Side Letter Agreement Associated With Merger | AVANGRID
Collaborative Arrangement and Arrangement Other than Collaborative [Line Items]
Debt basis spread on variable rate		0.75%
Facility fee percentage on undrawn portion of funding commitment		0.12%

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CONDENSED FINANCIAL INFORMATION OF PARENT - Common Stock (Details) - USD ($) $ / shares in Units, $ in Millions		1 Months Ended	12 Months Ended
	Feb. 16, 2022	Mar. 31, 2021	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	May 18, 2021
Business Acquisition [Line Items]
Common stock, authorized (in shares)			500,000,000	500,000,000
Common stock issued (in shares)			387,678,630	309,794,917
Common stock, outstanding (in shares)			386,568,104	309,077,300
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01	$ 0.01	$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 17,679	$ 13,665
Release of common stock held in trust (in shares)			301,239	72,028
Number of shares repurchased during period (in shares)			694,148
Treasury shares (in shares)			997,983
Treasury stock			$ 47	$ 14
Dividends declared (in dollars per share)			$ 1.76	$ 1.76	$ 1.76
Subsequent Event
Business Acquisition [Line Items]
Dividends declared (in dollars per share)	$ 0.44
Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)			0	0
Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)			77,883,713	42,777
AVANGRID
Business Acquisition [Line Items]
Common stock, authorized (in shares)			500,000,000	500,000,000
Common stock issued (in shares)			387,678,630	309,794,917
Common stock, outstanding (in shares)			386,568,104	309,077,300
Common stock, par value (in dollars per share)			$ 0.01	$ 0.01		$ 0.01
Common stock			$ 3	$ 3
Additional paid-in capital			$ 17,679	$ 13,665
Common stock held in trust (in shares)			112,543	413,782
Release of common stock held in trust (in shares)			301,239	72,028
Number of shares repurchased during period (in shares)		694,148
Treasury shares (in shares)			997,983
Treasury stock			$ 47	$ 14
AVANGRID | Subsequent Event
Business Acquisition [Line Items]
Dividends declared (in dollars per share)	$ 0.44
AVANGRID | Convertible Preferred Stock
Business Acquisition [Line Items]
Preferred stock, shares outstanding (in shares)			0	0
AVANGRID | Common Stock
Business Acquisition [Line Items]
Issuance of common stock (in shares)			77,883,713	42,777
Iberdrola Renewables Holding, Inc
Business Acquisition [Line Items]
Percentage of equity owned by parent			81.50%
Iberdrola Renewables Holding, Inc | AVANGRID
Business Acquisition [Line Items]
Percentage of equity owned by parent			81.60%	81.50%
Target ownership percentage by Parent			81.50%

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CONDENSED FINANCIAL INFORMATION OF PARENT - Long-Term Debt (Details) - USD ($)			12 Months Ended
	Apr. 09, 2020	May 16, 2019	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019	Dec. 14, 2020	Nov. 21, 2017
Debt Instrument [Line Items]
Proceeds from non-current debt			$ 833,000,000	$ 1,367,000,000	$ 2,137,000,000
Iberdrola Loan | Subordinated Debt
Debt Instrument [Line Items]
Debt instrument principal amount						$ 3,000,000,000
AVANGRID
Debt Instrument [Line Items]
Proceeds from non-current debt			$ 0	$ 744,000,000	$ 1,243,000,000
AVANGRID | 3.150% Notes due 2024
Debt Instrument [Line Items]
Debt instrument principal amount							$ 600,000,000
Debt instrument, interest rate							3.15%
AVANGRID | 3.800% Notes due 2029
Debt Instrument [Line Items]
Debt instrument principal amount		$ 750,000,000
Debt instrument, interest rate		3.80%
Proceeds from non-current debt		$ 743,000,000
AVANGRID | Unsecured Notes Maturing in 2025
Debt Instrument [Line Items]
Debt instrument principal amount	$ 750,000,000
Debt instrument, interest rate	3.20%
Proceeds from non-current debt	$ 744,000,000
AVANGRID | Iberdrola Loan | Subordinated Debt
Debt Instrument [Line Items]
Debt instrument principal amount						$ 3,000,000,000

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CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Summary (Details) - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
AVANGRID Networks
Cash Dividend [Line Items]
Cash dividends paid	$ 970	$ 419	$ 433
AVANGRID Renewables
Cash Dividend [Line Items]
Cash dividends paid	$ 152	$ 0	$ 0

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CONDENSED FINANCIAL INFORMATION OF PARENT - Cash Dividends Paid by Subsidiaries - Additional Information (Details) - AVANGRID - USD ($) $ in Millions	12 Months Ended
	Dec. 31, 2021	Dec. 31, 2020	Dec. 31, 2019
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 1,026	$ 591	$ 399
Non cash contribution/dividend recorded by parent company	674	423
United Illuminating Company (UI)
Cash Dividend [Line Items]
Capital contribution to subsidiary by parent	$ 1,011	$ 590	$ 158