株探米国株
英語
エドガーで原本を確認する
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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, 2023
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
AGR2023.jpg
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.  ☒
If securities are registered pursuant to Section 12(b) of the Act, indicate by check mark whether the financial statements of the registrant included in the filing reflect the correction of an error to previously issued financial statements.  ☐
Indicate by check mark whether any of those error corrections are restatements that required a recovery analysis of incentive-based compensation received by any of the registrant's executive officers during the relevant period pursuant to §240.10D-1(b).  ☐
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 and non-voting common equity 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, 2023) was $2,665 million based on a closing sales price of $37.68 per share.
Indicate the number of shares outstanding of each of the registrant’s classes of common stock, as of the latest practicable date: 386,779,949 shares of common stock, par value $0.01, were outstanding as of February 21, 2024.
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 2024 Annual Meeting of the Shareholders are incorporated by reference into Part III to the extent described therein.


TABLE OF CONTENTS
 
i

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.
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.
2023 Joint Proposal Joint proposal of NYSEG and RG&E and certain other signatory parties approved by the NYPSC on October 12, 2023, for a three-year rate plan for electric and gas service with effective date November 1, 2023.
Adjusted Daily Compounded SOFR The rate per annum equal to (a) the Daily Compounded SOFR for such U.S. Government Securities Business Day and (b) the SOFR adjustment; provided that if Adjusted Daily Compounded SOFR as so determined shall ever be less than the Floor, then Adjusted Daily Compounded SOFR shall be deemed the Floor.
Adjusted Term SOFR The rate per annum equal to (a) Term SOFR for such calculation plus (b) the SOFR adjustment; provided that if Adjusted Term SOFR as so determined shall ever be less than the Floor, then Adjusted Term SOFR shall be deemed to be the Floor.
AFUDC Allowance for funds used during construction
AMI Automated Metering Infrastructure
AOCI Accumulated other comprehensive income
ARAM Average Rate Assumption Method
ARHI Avangrid Renewables Holdings, Inc.
ARP Alternative Revenue Programs
ASC Accounting Standards Codification
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
CAPM Capital-asset pricing model
CAMT Corporate Alternative Minimum Tax
CfDs Contracts for Differences
CBP U.S. Customs and Border Protection
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
DEQ
Oregon Department of Environmental Quality
DER Distributed energy resources
DIMP Distribution Integrity Management Program
Dodd-Frank Act Dodd-Frank Wall Street Reform and Consumer Protection Act
DOC Department of Commerce
1

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
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
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.
HSR
Hart-Scott-Rodino Antitrust Improvements Act of 1976
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
IRA Inflation Reduction Act
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
2

MBEP Maine Board of Environmental Protection
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 June 19, 2023 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
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.
NYPA New York Power Authority
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
PBR
Performance-Based Regulation
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
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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
RSG Reverse South Georgia
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 and as amended and modified as of July 19, 2023 between Avangrid and Iberdrola concerning items
SOFR Secured Overnight Financing Rate
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
UFLPA Uyghur Forced Labor Prevention Act
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
AND SUMMARY OF RISK FACTORS
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 following, which is also a summary of the principal risks set forth under Part I, Item 1A, "Risk Factors" in this Annual Report on Form 10-K:
•actions or inactions of local, state or federal regulatory agencies;
•the ability of our regulated utility operations 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 mechanism;
•potentially material adverse effect on our business, and financial condition due to the purchase and sales of energy commodities and related transportation and services by our operating subsidiaries;
•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 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;
•efforts to maintain a responsive sustainability program;
•new tariffs imposed on imported goods;
•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;
•potential restrictions by interconnecting utility and/or RTO rules, policies, procedures and FERC tariffs and market conditions on renewable project operations and ability to generate revenue;
•our rights, and the rights of our subsidiaries to sites that projects are located may be subordinate to the rights of lienholders and leaseholders;
•strikes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms;
•technological developments;
•geopolitical instability could exacerbate existing risk factors;
•the future financial performance, anticipated liquidity and capital expenditures;
•weather conditions are unfavorable or below production forecasts;
•customary business and market related risks including warranty limitation and expiration as well as PPA expiration or early termination;
•impact of Iberdrola’s influence over stock as well as the future sale of issuance of common stock by Iberdrola;
•the “controlled company” exemption to the corporate governance rules for NYSE-listed companies could make shares of our 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;
•ability 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;
•the ability to maintain effective internal control over financial reporting;
•our investments and cash balances are subject to the risk of loss;
•the cost and availability of capital to finance our business is inherently uncertain;
•litigation or administrative proceedings;
•inability to insure against all potential risks;
•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;
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•adverse developments in general market, business, economic, labor, regulatory and political conditions including, without limitation, the impacts of inflation, deflation, supply-chain interruptions and changing prices and labor costs, including the Department of Commerce's anti-circumvention petition that could adversely impact renewable solar energy projects;
•the impacts of climate change, fluctuations in weather patterns and extreme weather events;
•the impact of extraordinary external events, such as any cyber breaches or other incidents, grid disturbances, acts of war or terrorism, civil or social unrest, natural disasters, pandemic health events or other similar occurrences, including the ongoing geopolitical conflict with Russia and Ukraine;
•the impact of a catastrophic or geopolitical event on business and economic conditions;
•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 $44 billion in assets and operations in 24 states concentrated in our two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving approximately 3.3 million customers in New York and New England. Avangrid Renewables owns and operates 9.3 gigawatts of electricity capacity, primarily through wind and solar power, with a presence in 22 states across the United States. Avangrid supports the achievement of the Sustainable Development Goals approved by the member states of the United Nations, was named among the World’s Most Ethical companies in 2023 for the fifth consecutive year by the Ethisphere Institute, included as a member of the 2023 Bloomberg Gender-Equality Index, and recognized by Just Capital as one of the 2024 Just 100, an annual ranking of the most just U.S. public companies for the fourth time. Avangrid employs approximately 8,000 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.
Avangrid Organization Structure 2023 10-K_v3.jpg
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, 2023. 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.
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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 9,338 megawatts, or MW, as of December 31, 2023, including Renewables’ share of joint projects, of which 8,045 MW was installed onshore wind capacity and 39 MW of offshore wind capacity. Renewables targets to contract or hedge above 80% of its capacity under long-term power purchase agreements, or PPAs, and hedges to limit market volatility. As of December 31, 2023, approximately 78% of the capacity was contracted with PPAs, for an average period of approximately 9 years, and an additional 11% 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, 2023 and strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. As of December 31, 2023, Renewables installed capacity includes 68 onshore wind farms and six solar facilities operational in 21 states across the United States.
Terminated 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 (as amended by the Amendment to Merger Agreement dated January 3, 2022, Amendment No. 2 to the Merger Agreement dated April 12, 2023 and Amendment No. 3 to the Merger Agreement dated June 19, 2023), or Merger Agreement, pursuant to which Merger Sub was expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of Avangrid, or the Merger for approximately $4.3 billion in aggregate consideration.
On December 31, 2023, Avangrid sent a notice to PNMR terminating the Merger Agreement. The Merger had been conditioned, among other things, upon the receipt of certain required regulatory approvals, including the approval of the New Mexico Public Regulation Commission or NMPRC, and provided that the Merger Agreement may be terminated by either Avangrid or PNMR if the closing of the Merger shall not have occurred by 5:00 PM New York City Time on December 31, 2023, or the End Date. Because the required approval of the NMPRC was not received by the End Date and the conditions to the closing of the Merger were not satisfied by the End Date, Avangrid exercised its right to terminate the Merger Agreement. No termination penalties were incurred by either party in connection with the termination of the Merger Agreement.
In light of the termination of the Merger Agreement, on January 8, 2024, Avangrid filed a motion to withdraw from the appeal it and PNMR’s subsidiary, Public Service Company of New Mexico (PNM), had filed with the New Mexico Supreme Court relating to the NMPRC order. 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 disaggregated by products and services, and a measure of profit or loss and total assets for each segment for each of the last three fiscal years is provided in Note 4 and 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 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 Iberdrola in the United States, bringing all of its 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.
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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 indirectly:
•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.
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, 2023:
Utility Rate Base(1)
(in billions)		 Electricity
Customers		 Electricity
Delivered
(in MWh)		 Natural Gas
Customers		 Natural Gas
Delivered
(in DTh)
NYSEG $ 4.5  919,650  15,328,774  271,976  52,445,058 
RG&E $ 3.0  391,634  6,875,800  324,793  54,434,921 
CMP $ 2.8  664,260  8,716,845  —  — 
MNG $ 0.1  —  —  6,136  2,096,184 
UI $ 2.0  344,976  4,748,336  —  — 
SCG $ 0.7  —  —  208,601  34,292,687 
CNG $ 0.6  —  —  187,790  32,677,005 
BGC $ 0.2  —  —  40,644  9,893,159 
Total $ 13.9  2,320,520  35,669,755  1,039,940  185,839,014 
(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, 2023.
During the last five years, Networks has invested $9.9 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 2023, the nine hydroelectric plants owned and operated by NYSEG and RG&E generated approximately 233,300 megawatt-hours, or MWh of clean hydropower, which is enough energy to power approximately 32,400 homes across New York State, 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.
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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, 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 and will 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, 2023, we have capitalized approximately $807 million on the NECEC project, which includes capitalized interest costs and other additional payments related to the project along with construction costs. The project has total estimated construction costs of approximately $1.5 billion. 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, 2023, 2022 and 2021. 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 2023 2022 2021
(in millions)
NYSEG Electric $ 3,715  $ 3,181  $ 2,776 
NYSEG Gas 789  726  715 
RG&E Electric 2,319  2,082  1,911 
RG&E Gas 682  597  553 
Subtotal New York 7,505  6,586  5,955 
CMP Dist 1,274  1,120  1,014 
CMP Trans 1,539  1,520  1,493 
MNG 83  82  87 
Subtotal Maine 2,896  2,722  2,594 
UI Dist 1,256  1,253  1,240 
UI Trans 776  730  699 
SCG 738  673  602 
CNG 592  559  515 
Subtotal Connecticut 3,362  3,215  3,056 
BGC 161  135  128 
Total $ 13,924  $ 12,658  $ 11,733 
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, 2023. For the year ended December 31, 2023, Renewables produced 19,020,041 MWh of energy through wind power generation. Renewables had a pipeline of 25,704 MW (19,625 MW - onshore and 6,079 MW - offshore) of future renewable energy projects in various stages of development as of December 31, 2023. In addition to its wind assets, Renewables had eight solar photovoltaic facilities with an installed capacity of 618 MW as of December 31, 2023, out of which six facilities were operational with an installed capacity of 529 MW. The solar photovoltaic facilities produced over 833,186 MWh of renewable energy for the year ended December 31, 2023.
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Solar accounted for 4.0% of the total renewable energy generation from Renewables in 2023.
A significant part of Renewables' strategic business is offshore wind. Renewables has rights to two federal offshore wind lease areas. One is located 20 miles off the coast of Massachusetts including 101,590 acres, which has the potential to generate up to 2,600 MW of renewable energy for one or more New England states and the other is located 27 miles off the coast of North Carolina including 122,405 acres, which has the potential to generate up to 3,500 MW of renewable energy for Virginia and North Carolina. In addition, Renewables holds a 50% indirect ownership interest in Vineyard Wind 1 LLC (Vineyard Wind 1), a joint venture with affiliates of Copenhagen Infrastructure Partners, or CIP, a fund management company based in Denmark, which has rights to a federal offshore wind lease area located 15 miles off the coast of Massachusetts including 65,296 acres.
Prior to a restructuring transaction that closed on January 10, 2022 (Restructuring Transaction), Vineyard Wind, LLC (Vineyard Wind) held acquired easements from the U.S. Bureau of Ocean Energy Management (BOEM) containing the rights to develop offshore wind generation. Vineyard Wind acquired two lease areas, Lease Area 501 which contained 166,886 acres and Lease Area 522 which contained 132,370 acres, both located southeast of Martha’s Vineyard. Lease Area 501 was subdivided in 2021, creating Lease Area 534. On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Among other items, the Vineyard Wind 1 project was transferred into a separate joint venture, Vineyard Wind 1. Following the Restructuring Transaction, Vineyard Wind 1 remained a 50-50 joint venture and kept the rights to develop Lease Area 501, and Vineyard Wind was effectively dissolved where Renewables received rights to the Lease Area 534 and CIP received rights to Lease Area 522 as liquidating distributions. In contemplation of the liquidating distributions, Renewables also made an incremental payment of approximately $168 million to CIP. Refer to Note 22 to our consolidated financial statements contained in this Annual Report on Form 10-K.
Vineyard Wind 1 is currently constructing the Vineyard Wind 1 project, an 806 MW utility-scale offshore wind project in Lease Area 501. The Vineyard Wind 1 project is expected to generate an amount of clean energy equivalent to that used by 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, or EDCs, 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. On January 2, 2024, Vineyard Wind 1 delivered first power to the electric grid in Massachusetts.
In December 2021, the Commonwealth Wind project, which was to be located on Lease Area 534 was selected as part of Massachusetts’ third offshore wind competitive procurement process. In April 2022, Commonwealth Wind signed 1200 MW of PPAs with the Massachusetts EDCs, which were filed with, and approved by the DPU. Following motions filed with the DPU with respect to the suspension of the proceeding to review the PPAs and termination of the PPAs and appeal to the Supreme Judicial Court of Massachusetts of the DPU's approval, on July 13, 2023, each of the EDCs filed with the DPU a first amendment, termination agreement and release agreed with Commonwealth Wind, providing for an orderly termination of the PPAs, withdrawal or dismissal of Commonwealth Wind’s appeal, and payment by Commonwealth Wind of a $48 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs. The DPU approved the termination agreements on August 2, 2023 and Commonwealth Wind filed for a dismissal of its appeal of the DPU’s approval order.
Renewables had been developing the Park City Wind project, an 804 MW project located on Lease Area 534, that was intended to deliver clean, reliable energy to the residents of Connecticut through contracts with the EDCs in Connecticut. The project had 20-year PPAs with the EDCs in Connecticut, including UI. On October 2, 2023, following discussions with the Connecticut EDCs, Park City Wind entered into a first amendment, termination agreement and release with each of the Connecticut EDCs, providing for an orderly termination of the Park City Wind PPAs and payment by Park City Wind of an approximately $16 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs. On October 13, 2023, PURA approved the termination agreements.
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 solar or wind project is then transmitted to customers through long-term agreements with purchasers. There are a limited number of wind turbine suppliers in the market. Renewables’ largest turbine suppliers, Siemens-Gamesa and GE Wind, in the aggregate supplied turbines that accounted for 69% of Renewables’ installed wind capacity as of December 31, 2023. Iberdrola had an 8.1% ownership interest in Siemens-Gamesa until it was sold in February 2020.
To monetize the tax benefits resulting from tax credits, or PTCs and ITCs, and accelerated tax depreciation available to qualifying wind and solar energy projects, Renewables has entered into “tax equity” financing structures with third party investors for a portion of its wind and solar farms.
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Renewables holds operating wind and solar 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 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 and solar 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 and solar farm businesses, subject to investor approval of certain major decisions. See “—Properties—Renewables” for more information regarding Renewables’ power generation properties.
Renewables owns two thermal generation facilities located in Klamath Falls, Oregon with 636MW of nameplate capacity as of December 31, 2023. The 536MW Combined Cycle Cogeneration Plant creates energy from both natural gas and steam (waste heat) produced from its gas turbines. The 100MW plant is a simple cycle, peaking plant that provides flexibility in terms of quick ramp time. Both facilities are utilized to support Renewable’s Balancing Authority in addition to providing customers with capacity in peak demand periods.
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 40 wind meteorological towers and 15 solar meteorological stations that are currently in operation. Additionally, a total of three 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.
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.
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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, MEPCO's and New York TransCo's regulated electric utilities transmission revenue requirements. Wholesale electric transmission revenues are recovered through stated or 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%, and provided 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. The FERC is authorized to assess a maximum civil penalty of $1.39 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.
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 $1.39 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.
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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 $1.9 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.
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 their 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.
In New York, Maine, Connecticut and Massachusetts, most of Networks’ distribution utilities’ customers have the opportunity to purchase their electricity or natural gas 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 subject to and the result of 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. 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.
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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 their 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 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.
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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 three 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.
Global Climate Change and Greenhouse Gas Emission Issues
Global climate change and greenhouse gas emission, or GHG, 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. In October 2023, California enacted landmark climate disclosure and financial reporting legislation, the Climate Corporate Data Accountability Act, which will require certain public and private companies doing business in California to disclose their scope 1, scope 2 and scope 3 greenhouse gas emissions on an annual basis beginning in 2026, with respect to Scope 3, in 2027.
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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. See “Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations” in this Annual Report for additional information about CLCPA.
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 generally 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. UI continues its activities to investigate and remediate the environmental conditions at the site. In 2023 and 2024, DEEP sent UI a series of letters requesting details on remediation plans and security, which UI has responded to. On January 25, 2024, DEEP issued a notice of declaratory ruling to determine the “high occupancy standard” necessary “to abate on-site pollution and impacts for industrial/commercial use of the Site…inside the buildings” as referenced in section (B)(1)(e)(4) of the Partial Consent Order. On January 29, 2024, DEEP served UI with a Summons and Complaint seeking injunctive relief and enforcement of the consent order from the Connecticut Superior Court. We cannot predict the outcome of this matter. For additional information, see Note 14 to our consolidated financial statements contained in this Annual Report on Form 10-K.
Environmental Management and Goals
In connection with our environmental, social, governance and financial stewardship strategy, we have established several environmental goals including a target to be carbon neutral for Scopes 1 and 2, as defined by the U.S. Environmental Protection Agency, by 2030. The Avangrid Board has adopted a governance and sustainability system reflecting our environmental, social, governance and financial stewardship strategy including, without limitation, a Climate Action Policy that explicitly sets forth our Scope 1 and Scope 2 targets. Further, we have defined a set of goals to reduce the environmental impact of our facilities including that 100% of our corporate facilities will have renewable electricity by 2030, 100% of our light duty fleet will be clean energy vehicles by 2030 and an increase in our emission free generation capacity by 190% by 2030.
Customers
Networks delivers natural gas and electricity to residential, commercial and institutional customers through its regulated utilities in New York, Maine, Connecticut and Massachusetts.
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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 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, 2023, approximately 78% of the capacity was contracted with PPAs, for an average period of approximately 9 years, and an additional 11% 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 or offshore lease 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, 2023. 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, 2023:
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  4,548  39,725  3,589  43,314 
RG&E New York 156  1,117  8,797  3,324  12,120 
CMP Maine 205  2,912  29,507  3,526  33,033 
UI Connecticut 28  138  8,323  1,314  9,637 
Total 819  8,715  86,352  11,753  98,105 
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, 2023:
Utility State Transmission Pipeline (in miles) Distribution Pipeline (in miles)
NYSEG New York 20  8,527 
RG&E New York 99  8,449 
MNG Maine 2  324 
SCG Connecticut —  4,242 
CNG Connecticut —  3,871 
BGC Massachusetts —  1,139 
Total 121  26,552 
CNG owns and operates a LNG plant which can store up to 1.2 Bcf of natural gas and can vaporize up to 90,000 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, 2023. 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 2018 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 36 (Gamesa G114, 2.10 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
Midland Wind 21 (Vestas, 4.3 MW);
4 (Vestas, 3.8 MW)		 104 2023 MRO
Iowa Barton 79 (Gamesa, 2.0 MW) 158 2009 MRO
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Location Wind Project Turbines Total Installed Capacity (MW) Commercial Operation Date North American Electric Reliability Corporation (NERC) Region
Flying Cloud 29 (GE, 1.5 MW) 44 2003 MRO
New Harvest 50 (Gamesa G87, 2.0W) 100 2012 MRO
Top of Iowa II 40 (Gamesa G87, 2.0 MW) 80 2007 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) 27.5 (Vestas V82, 1.65 MW) 45 2006 NPCC
Roaring Brook 5 (Gamesa G114, 2.625);
15 (Gamesa G145, 4.5)		 80 2021 NPCC
North Carolina Desert Wind 104 (Gamesa G114, 2.0 MW) 208 2017 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 51 (Vestas, 4.3 MW) 219 2021 WECC
Pennsylvania Casselman 23 (GE, 1.5 MW) 35 2007 RFC
Locust Ridge I 13 (Gamesa G87, 2.0) 26 2007 RFC
Locust Ridge II 50 (Gamesa G83, 2.0 MW) 100 2009 RFC
South Chestnut 23 (Gamesa G90, 2.0 MW) 46 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)		 19 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 2016 TRE
Barton Chapel 60 (Gamesa, 2.0 MW) 120 2009 TRE
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Location Wind Project Turbines Total Installed Capacity (MW) Commercial Operation Date North American Electric Reliability Corporation (NERC) Region
Karankawa 93 (GE, 2.52 MW);
22 (GE, 2.3 MW);
9 (GE, 2.5 MW)		 307 2019 TRE
Patriot 58 (Vestas, 3.6 MW);
 5 (Vestas, 3.45 MW)		 226 2019 TRE
Peñascal I 79 (Mitsubishi, 2.4 MW) 190 2009 TRE
Peñascal II 81 (Mitsubishi, 2.4 MW) 194 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 with installed capacity in Renewables as of December 31, 2023. Unless otherwise noted, Renewables owns each facility.
Facility Location Type of Facility Installed Capacity (MW) 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 
Lund Hill Solar Klickitat County, Washington Solar 194 2022 
Montague Solar Gilliam County, Oregon Solar 205 2023 
Bakeoven Solar (3) Wasco County, Oregon Solar 53 Note 3
True North (3) Falls County, Texas Solar 36 Note 3
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)Commercial Operation Date is expected in 2024.
Climate Change
We play a critical role in the fight against climate change as we work to create a more sustainable and equitable clean energy future. We are taking both mitigative and adaptive measures to address the threat of climate change. This means implementing strategies and systems to monitor and address the chronic and extreme risks that climate change can cause. These efforts include assessing climate risks as part of our investment analysis, building in resiliencies in the design of our projects and implementing solutions such as smarter grids and a more resilient infrastructure. Our efforts to assess and mitigate against climate risk help us support our customers and protect our communities from increasingly severe weather events while providing reliable and safe energy. To combat the risks associated with climate change and to raise awareness of the benefits of contributing to a carbon neutral and sustainable future, our climate strategy is aligned with the framework established by the Task Force on Climate Related Financial Disclosures, or TCFD. We believe that alignment with the TCFD supports the establishment of the appropriate governance and assessment and management of, our climate risks and opportunities with the appropriate oversight and transparency.
To further our commitments to address climate change, decisions to move forward with new investments must incorporate an analysis of risks related to climate change along with plans (and a budget) to mitigate these risks. To help inform how and where we invest to address climate change, we monitor for emerging risks, including those that may impact our supply chain and our network and renewables operations.
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Our comprehensive risk management strategy recognizes the acute and chronic impacts that may result from climate change. These can present physical risks to our communities and energy systems and financial risk across our operations. Because of this, we prioritize our efforts to plan for – and protect against – the increasingly severe impacts of climate change. Our risk management function coordinates with the business areas to identify, assess and report the risks, including those due to climate change such as extreme weather events, flooding and other natural disasters. The board, through its governance and sustainability committee, receives regular reports on our climate action strategy and the risk to the company due to climate change. For each of these threats, we identify the principal physical impacts they can cause, such as infrastructure damage, reduced power or limited availability of water. We also work to identify the approach we will take to manage the impacts of these threats, such as the use of new materials that can better withstand extreme conditions, burying of power lines and the installation of detection and warning systems.
In addition, we seek out opportunities to adapt to and mitigate climate change risks, including investments in energy storage technologies to maximize the availability of our renewable resources, and upgrades across our networks to improve the security and reliability of our energy supply. We are also working to accelerate decarbonization across our own operations and our industry. In connection with our environmental, social, governance and financial stewardship strategy, we have established several environmental goals including a target to be carbon neutral for Scopes 1 and 2, as defined by the U.S. Environmental Protection Agency, by 2030 and goals for 100% of our corporate facilities will have renewable electricity by 2030, 100% of our light duty fleet to be clean energy vehicles by 2030, and an increase in our emission free generation capacity by 190% by 2030. By addressing our company’s carbon emissions and the carbon footprint of our industry, we can help to reduce the chronic and extreme threats and impacts associated with climate change.
Our actions, investments and goals to address climate change demonstrate our commitment, and we continue to see the positive impacts of these actions across our operations. In 2023, these impacts included decreasing our CO2 emissions intensity by 28% compared to a 2015 base year, maintaining our place as the third-largest renewable energy operator in the U.S. with 8.7 GW of emissions-free installed capacity, reaching the commercial operation date (COD) for nearly 395 MW of new wind and solar projects, and achieving a 91% emissions-free generating capacity.
We also continue to link a portion of our executive and employee compensation to our corporate sustainability metrics. In 2023, our short-term incentive plan and our long-term incentive plan included sustainability-related performance metrics such as metrics related to the reduction of CO2 emissions intensity, increasing purchases from sustainable suppliers, implementing gender parity plans to increase gender diversity, and reducing employee and contractor injuries.
We are committed to transparency around our carbon footprint and climate risk and use the framework developed by the TCFD to inform our disclosure on climate governance, strategy, risk management, and metrics and targets. For governance and strategy, we follow an integrated approach to address climate change, with multiple teams responsible for managing climate-related activities, initiatives, and policies. Strategies and progress toward goals are reviewed with senior executives and the board’s governance and sustainability committee.
Human Capital Resources
At Avangrid, we’re focused on creating a workplace where talented and committed employees build meaningful, long-term careers. We accomplish this by fostering a workplace culture that seeks out diverse perspectives, values continuous improvement, and recognizes and rewards behaviors and ideas that prepare our employees to meet the challenges of the future.
We also prioritize the health, safety, and well-being of our employees – from their physical safety and financial security to our diversity, equity, and inclusion commitments, to mental health and wellness, all within a respectful work environment. We bring these commitments to life by investing in programs and tools that empower our employees’ personal and professional growth while helping them connect with and support each other, and while addressing their individual needs and the needs of their families.
In 2023, we made progress towards several aspirational goals we set the year before. These include commitments to increase diversity across our workforce, to expand opportunities for our employees while prioritizing their safety and well-being, to address gender equity, and to create a more diverse, equitable and inclusive workplace.
In light of our commitment to our employees, we continued our efforts to increase the gender diversity of our executive leadership team (vice president and above), with a goal to have women represent 35% of our executive positions by 2030, and 50% of our senior leadership positions by 2030.
As of December 31, 2023, we employed 7,999 employees, all of whom are full-time. 91.3% of employees were based in five states – Connecticut, Massachusetts, Maine, New York, and Oregon. During fiscal year 2023, we hired and onboarded 1,083 employees.
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Approximately 45.8% 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 24.1% of our employees. There is mutual respect and collaboration when discussing the variety of issues we face on an ongoing basis, and the respective parties share the goal of supporting the business while helping to ensure a positive customer experience.
For the year ended December 31, 2023, the information on turnover rates is as follows:
Employee Turnover % of Total
Voluntary Turnover as a percent of workforce 6.0  %
Involuntary Turnover as a percent of workforce 1.0  %
Retirement as a percent of workforce 1.6  %
Total Turnover as a percent of workforce 8.5  %
Diversity, Equity and Inclusion
We are committed to creating inclusive workplaces where every employee across every team is valued and has access to equitable opportunities for professional growth and development. We recognize that diversity, equity, and inclusion (DEI) are critical to our future success, and to build, sustain and empower a diverse workforce with a rich mix of differences we have prioritized DE&I initiatives in three areas:
•Increasing diverse representation, especially in leadership positions
•Promoting equitable opportunities to grow and develop
•Establishing pathways for community and connection with others.
In 2023, we made significant progress to our DEI commitments, beginning with the formation of a new DEI Executive Council, which we launched in March. The mission of this council is to inspire a more diverse and inclusive organizational culture, advocate for DEI across the entire company, and promote more connections between employees and their senior leaders. The council, which is comprised of members from across Avangrid’s senior leadership and our Business Resource Groups, work together to embed our DEI goals across different parts of the company.
We also launched our new Inclusion at Work training, which was designed to empower all Avangrid employees with the knowledge and skills needed to foster an inclusive workplace. Through this training, which is provided to our entire staff, employees learn to recognize and reduce unconscious biases while gaining an understanding of cultural differences, all with a focus on enhancing empathy and respect among one another.
Our growing network of BRGs provide communities where our employees can discuss relevant issues and celebrate different cultures, ethnicities, identities, and backgrounds. Over 15% of our employees participate in one of our seven BRGs. The Avangrid African-American Council for Excellence (AAACE), the Avangrid Coalition for Asian Pacific Americans (ACAPA), AVAN-Veterans, The Avangrid Community for All Abilities and Resource for Excellence (CARE), The Hispanic Organization for Leadership and Awareness (HOLA), Pride@AVANGRID and WomENergy. Our BRGs hosted over 97 events in 2023, promoting inclusive conversations and diverse thinking throughout the organization.
As of December 31, 2023, 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 24.4  % 3.9  % 16.4  % 42.0  % 4.7  %
American Indian or Alaska Native 0.5  % 0.2  % —  % 0.5  % 0.5  % 1.1  %
Asian 3.4  % 5.4  % 3.9  % 1.5  % 2.2  % 9.1  %
Black or African American 5.8  % 13.1  % 2.3  % 1.0  % 4.8  % 3.2  %
Hispanic or Latino 8.5  % 16.3  % 7.4  % 1.8  % 5.4  % 8.8  %
Hawaiian Native or other Pacific Islander 0.1  % 0.1  % 0.0  % 0.0  % 0.1  % 0.8  %
Two or more races 2.0  % 1.8  % 2.3  % 1.8  % 2.0  % 2.7  %
White 78.1  % 61.4  % 81.0  % 91.6  % 83.9  % 72.4  %
Did not provide 1.6  % 1.7  % 3.2  % 1.8  % 1.1  % 1.9  %
Senior Leadership All CT MA ME NY OR
% of Employees in State 31.3  % 7.7  % 16.2  % 17.3  % 14.5  %
American Indian or Alaska Native —  % —  % —  % —  % —  % —  %
Asian 3.1  % 3.6  % —  % 1.8  % —  % 3.9  %
Black or African American 2.3  % 3.6  % —  % —  % 4.9  % 2.0  %
Hispanic or Latino 11.6  % 20.9  % 11.1  % 7.0  % 9.8  % 5.9  %
Hawaiian Native or other Pacific Islander 0.6  % 0.9  % —  % —  % —  % 2.0  %
Two or more races 2.6  % 0.9  % 3.7  % 5.3  % 1.6  % 2.0  %
White 77.0  % 68.2  % 77.8  % 82.5  % 78.7  % 82.4  %
Did not provide 2.8  % 1.8  % 7.4  % 3.5  % 4.9  % 2.0  %
All Employees All CT MA ME NY OR
Female 27.8  % 30.1  % 30.5  % 29.3  % 27.8  % 28.7  %
Male 72.1  % 69.8  % 69.1  % 70.6  % 72.1  % 71.0  %
Undeclared 0.1  % 0.1  % 0.3  % 0.1  % 0.1  % 0.3  %
Senior Leadership All CT MA ME NY OR
Female 27.3  % 30.0  % 7.4  % 35.1  % 24.6  % 33.3  %
Male 72.4  % 70.0  % 88.9  % 64.9  % 75.4  % 66.7  %
Undeclared 0.3  % —  % 3.7  % —  % —  % —  %
Growing our Talent
Varied learning opportunities enable the personal and professional development of our employees – such as on-demand skill building platforms, leadership programs, mentoring programs, technical and on-the-job training, community outreach options, and tuition assistance.
In 2023, Avangrid took action to enhance its leadership development programs, with the launch of several leadership development journeys based on role in company. These learning journeys were curated leveraging a partnership with an external vendor to create meaningful, thoughtful programs with high interactivity for knowledge and skill retention. Learning journeys were created for the Vice President level (Leading Organizations), Senior Director and Director level (Leading Leaders), Manager/Supervisor (Leading People) and Individual Contributor (Leading Self), each with distinct learning objectives and curriculum around building an inclusive work environment. The following programs were also continued in 2023, with enhancements made based on business needs: the mentoring program to all non-union employees; continuation of the Leadership Essentials program for new people leaders; continuation of How to Have Difficult Conversations as related to known bias and expansion of resources to help people leaders manage teams effectively in a remote/hybrid environment.
We also enhanced our succession and talent management processes to target the identification and development of key talent within all business areas to enhance the sustainability of the business from a people perspective, with a focus on diverse representation and launch of a new People Review Process. We expanded our early career pipeline to include the graduate program composed of local and global graduates as well as our ongoing Internship Program to continue building in-demand and emerging skills.
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Total Rewards & Benefits
Our compensation, health, and retirement programs are designed to attract, retain, and empower employees to meet business and customer needs across a variety of markets and locations, and within the increasingly competitive market 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. 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. Annually, we evaluate the effectiveness and competitiveness of our executive compensation and benchmark ourselves against comparable peers within our industry.
We take a “Total Health” approach to benefits and wellbeing with inclusive programs designed to support employees’ physical, financial, emotional, and social health, as well as their families’, throughout various stages of life. Many of our programs are available to all union and non-union employees both full- and part-time.
Some 2023 examples of Company programs include:
•Comprehensive, high-quality health, dental, vision, life, and disability plans
•401(k) match and Paid Time Off programs
•Paid Parental Leave for those welcoming a new child through birth, surrogacy, adoption, or foster care placement
•Fertility and family-forming care and coverage
•Diabetes, Pre-Diabetes. Hypertension, and Musculoskeletal focused programs
•Education and tuition reimbursement assistance programs, including student loan debt repayment program for non-union employees
•Emergency Savings program
•Subsidized back-up care for children, elder family members, and those with special needs including tutoring, test prep and camp options. Programs that support local non-profits by offering a cash match for employee donations, as well as direct donations recognizing employee volunteer hours.
•A variety of value-added options that allow employees to make choices that meet their individual needs, including telemedicine, claims navigation, mental health resources, financial wellness and education programs, legal assistance, identity theft protection, and auto/home/pet insurance.
In 2023 we continued with our Emotional Health programs, providing resources that look to eliminate the Stigma that is associated with Mental Health disease. We provided webinars as well as digital, telephonic and face to face programs that touched on all mental health issues including depression and anxiety. We continue to train our Managers with a Mental Health Matters training to give managers tools and resources help them have productive conversations with an employee who may be having an issue. Our Mental Health Advocate program now has over 100 employees participating. Mental health advocates are employees who undergo certain training and volunteer their time to listen and provide guidance to others regarding available mental health resources. In 2023 they provided guidance to over 370 employees and over 250 non-Avangrid employees in the community. The number of employees taking our Health Assessment, participating in our activity challenges and sleep/fatigue management programs continues to grow. In 2023 Avangrid saw a need for a musculoskeletal program and launched Hinge Health program in September for employees and their families for non-work-related injuries. In addition, we continued with onsite services including “Benefits & Wellbeing Fairs” and onsite influenza vaccination clinics. We will continue to evaluate the programs we have and look for additional programs that will add value to our employee’s wellbeing.
Safety
Safety is a core value at Avangrid. We are committed to providing a safe and healthy workplace for 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.
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A safe workplace encourages an environment where innovation can flourish. All Avangrid 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 present Environmental, Health & Safety Excellence awards and Good Catch awards to spotlight exemplary and proactive safety behavior. A Good Catch is the result of an employee recognizing a condition that had the potential to cause an incident but did not cause one, due to timely identification and mitigation by the employee. As musculoskeletal/soft tissue problems account for Avangrid’s most frequent injuries, we escalated our ergonomics program in 2023 to reduce injuries and educate employees on ergonomic best practices. From re-launching the Ergo-Power training program to further expanding our Early Intervention Program, which promotes on-site occupational health and injury prevention, we have already impacted our ergonomic injury rates in a positive and significant way.
This past year, we streamlined a Leadership Field Safety Observation Program, designed to improve employee engagement, and increase field condition awareness throughout the organization. In 2023, employees and leaders completed more than 35,000 safety observations. These programs, in addition to monthly safety meetings, are dedicated to sharing critical safety updates, promoting a learning/improving safety culture, while also building critical skills for managers and supervisors to boost engagement for all employees. Avangrid also continued "The Daily 5," which includes safety best practices videos and content posted on the company’s internal social media channel. These posts are shared with field supervisors and managers, who cascade the messages to all field employees. For our Networks employees, we continued an intensive “Alertdriving” training program with nearly 3,000 employees to promote safety and reduce company-related motor vehicle incidents.
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 X, 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 X 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
You should carefully consider the following risks and all of the other information set forth in this report, including without limitation our consolidated financial statements and the notes thereto and "Item 7—Management's Discussion and Analysis of Financial Condition and Results of Operations—Critical Accounting Estimates." The following risk factors have been organized by category for ease of use; however, many of the risks may have impacts in more than one category.
Strategic Risk Factors
The success of Avangrid depends on achieving our strategic objectives, which may be through mergers, 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, mergers, acquisitions, joint ventures, dispositions and restructuring. With respect to potential mergers, 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. Additionally, we may face potential financial and reputational impacts due to termination of mergers, acquisitions, joint ventures, dispositions and restructuring activities. 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.
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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, interconnections to generating resources and other innovative technologies pertaining to our sector. 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 or other required approvals, new legislation, citizen referendums or ballot initiatives, economic events, foreign currency risk, negative publicity, design and siting issues, difficulties in obtaining required leases, easements or other rights of way, difficulties in securing equipment orders, difficulty securing key vendor alternatives, construction delays and cost overruns, including delays in third party performance, delays in equipment deliveries, increase in the price of raw materials or availability of responsibly sourced materials, severe weather and mitigation or adaptation activities, increase in financing cost, competition from incumbent facilities and other entities, and actions of strategic partners. Projects have also endured, and may continue to endure, environmental and community concerns including but not limited to environmental justice, disposal of waste, emissions impacts, sustainable water and soil usage, protection of ecosystems and energy efficiency. There may be delays or unexpected developments in completing current and future construction projects. For example, the outcome of ongoing legal proceedings, cost overruns and construction delays could have an adverse effect on the success of development projects and our financial condition and prospects. Additionally, changes in economic conditions including the impacts of inflation, increased interest rates and supply chain disruptions on the projects could result in the termination of certain development projects resulting in financial impacts such as the payment of termination payments or reputational impacts. 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. Project delays may also lead to an inability to utilize and monetize safe harbor equipment, negatively impacting project returns. Additionally, for Renewables’ projects that are subject to PPAs, contractual non-performance prior to construction could lead to payment of damages and potential project cancellation. During construction, 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 project failing to qualify for PTCs or ITCs could result in losses that would be substantially greater than the amount of liquidated damages paid to Renewables. Finally, there is a risk that a project fails to qualify at the expected level for PTC or ITC impacting returns.
Avangrid may be materially adversely affected by negative publicity related to or in connection with development projects, government-controlled power initiatives and in connection with other matters.
From time to time, political and public sentiment in connection with Avangrid projects, government-controlled power initiatives and in connection with other matters have resulted and may result in the future 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 adverse effect on Avangrid’s business, financial condition, results of operations and cash flows and the market value of Avangrid common stock and debt securities.
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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.
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 operations are subject to, and influenced by, complex and comprehensive federal, state and local regulation and legislation. This is impactful for all areas of the business but particularly in the emerging development of offshore and solar generation. It is anticipated that members of Congress will continue working to pass legislation that would prohibit offshore wind construction by foreign flagged vessels in which the crew nationality does not match the nation in which the vessel is flagged. If passed, this legislation could affect expected timelines and returns on approved projects. Additionally, implementation of the Uyghur Forced Labor Prevention Act has led U.S. Customs and Border Control and Protection to detain and reject the import of products made with forced labor in certain areas of China, to date this has included solar panels, which is causing significant delay in panel delivery. Under this authority, aluminum products have been detained and there is the potential that additional products could face detentions as well. This legislation could have an impact on project development, construction activities and project returns.
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.
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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 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.
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 and cost allocation, 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.
For example, 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.
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. U.S. and European laws and regulations may require us to post 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 purchase and sale of energy commodities and other attributes, as well as related transportation, transmission 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.
Additionally, Avangrid faces fluctuations in the fair value of its derivative contracts over time due to the impact of mark-to-market accounting.
The increased cost of purchasing natural gas and electricity during periods in which prices have increased significantly could adversely impact our earnings and cash flow.
Our regulated utilities are permitted to recover the costs of natural gas and electricity purchased for customers. Under the regulatory body-approved cost recovery pricing mechanisms, the commodity charge portion of rates charged to customers may be adjusted upward on a periodic basis. If the cost of purchasing natural gas or electricity increases and Networks’ regulated 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 or electricity may result in higher customer bad debt expense for uncollectible accounts and reduced sales volume and related margins due to lower customer consumption.
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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. Climate vulnerability assessment regulation have also been issued in New York, Maine, and Connecticut. 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 within our territories. We are unable to predict the impact these laws 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 changes to 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 invested capital 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 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 have exposed and in the future may 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.
For example, climate-related and greenhouse gas emission disclosure legislation or rules that have been issued or are pending federally, within California or other states (e.g. New York) that, among other things, may require our management and other personnel to devote a substantial amount of time and company resources to these compliance activities. If we are not able to comply with these requirements in a timely manner we may be subject to regulatory investigations, fines, penalties or other sanctions. Additional financial and management resources could be required.
Security breaches, acts of war or terrorism, grid disturbances or unauthorized access could negatively impact our business, financial condition and reputation.
Our business depends on critical assets, with Networks serving as a super-regional energy services and delivery company, and Renewables operating generation plants that produce electricity using renewable resources. In the ordinary course of our business, we also maintain sensitive customer, vendor and employee data, critical infrastructure information, financial and system operating information, and other confidential data.
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Threat sources, including sophisticated nation-state actors, continue to seek to exploit potential vulnerabilities of critical assets in the utility industry, grid infrastructure, and other energy infrastructures, and these attacks and disruptions, both physical and cyber, are becoming increasingly sophisticated and dynamic. Continued implementation of advanced digital technologies increases the potentially unfavorable impacts of such attacks.
Cyber breaches, acts of war or terrorism or grid disturbances resulting from internal or external sources could therefore target our critical assets, including our facilities or information technology systems, or those of our vendors, business partners and interconnected entities. Cyber and physical security attacks on our infrastructure could lead to disabling damage to our facilities and equipment or to theft, vandalism and the release of critical operating information or confidential customer, vendor and employee information, which could adversely affect our operations, including causing an operations shutdown or affecting our ability to control our transmission and distribution assets, and could result in monetary and reputational damages and 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. A cyber or physical security incident could also result in competitive disadvantages and significant increases in compliance costs and costs to improve the security and resiliency of our systems, and the compromise of personal, confidential or proprietary information could subject us to significant legal liability or regulatory action under evolving cyber-security, data protection and privacy laws and regulations. As a result, our ability to conduct our business and our results of operations could be materially and adversely affected.
Like other companies, our computer systems are also regularly subject to and will continue to be the target of computer viruses, malware or other malicious codes (including ransomware), unauthorized access, cybersecurity incidents or other computer-related penetrations. The risk of these incidents could be caused or exacerbated by geopolitical tensions, including hostile actions taken by nation-states or terrorist organizations. In the event of a computer virus or natural or other disaster, our computer systems could be inaccessible for an extended period of time, and because our systems increasingly interface with and depend on third-party systems, including cloud-based systems, we could experience service denials or failures of controls if a third-party system fails or experiences an interruption.
We have also outsourced certain technology and business process functions to third parties and may increasingly do so in the future. If we do not effectively develop, implement and monitor our vendor relationships, if third party providers do not perform as anticipated or adhere to our data security measures, if we experience technological or other problems with a transition, or if vendor relationships relevant to our business process functions are terminated, our business may become more vulnerable and could experience a significant cybersecurity or physical attack.
While we have experienced security breaches in the past, to date, we are not aware that we have experienced a material cybersecurity or physical breach. 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 against potential harms. While we have implemented, and continuously refine our cyber and physical security measures to protect our business, these measures may not be effective or sufficient in preventing a significant breach, and our controls, measures and incident response plan may not be effective or sufficient in assessing, identifying and managing material risks from cybersecurity threats or mitigating and remediating against cybersecurity incidents.
Catastrophic or geopolitical events may disrupt operations and negatively impact the financial condition of the business, cash flows, and the trading value of its securities.
The impact of a catastrophic or geopolitical event, on the economy, labor, financial markets and the environment could adversely affect our business. The extent to which events may impact our business going forward will depend on factors such as public response, governmental actions, the duration, and its impact to economic activity and financial stability. Increased frequency or duration of events such as these may alter the fundamental 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 due to affordability; 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.
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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 inability to 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 an 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. 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 our 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.
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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.
A part of Avangrid employees are subject to collective bargaining agreements with various unions. Unionization activities, including votes for union certification, could occur among non-union employees across Avangrid’s subsidiaries. While we generally enjoy strong working relationships with all our labor unions, 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, outages and operation disruptions if replacement labor is not procured. This risk may also lead to an increase in personnel costs.
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 have increased the development of new technologies for renewable energy, energy efficiency and investment in an attempt to make those technologies more efficient and cost effective. However, there is a risk that new and/or unproven technologies, including battery storage and hydrogen technology, may fall short of their expected benefits and may not be 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.
Avangrid’s efforts to maintain a responsive sustainability program may impact business operations and investor sentiment.
Avangrid's operations and reputation concerning sustainability are reliant on the company's actions around employee engagement, community relations including with overburdened or indigenous communities, human rights, value chain management including upstream and downstream effects, waste management and recycling, and areas that may impact perceptions on the company's sustainability effectiveness and could subject Avangrid to increased legal or political scrutiny of Avangrid’s activities. Avangrid’s efforts to comply with increasing sustainability reporting requirements to regulators, customers and third parties, and to track and provide accurate data may impact internal resources. Additionally, Avangrid has several goals that include, but are not limited to, emissions reduction, sustainable use of nature resources such as land and water, biodiversity, increased use of renewable generation, responsibly sourced materials, operational health and safety, and social impacts. The efforts involved in meeting these goals may be costly and may require our management and other personnel to devote a substantial amount of time and company resources to these activities. Furthermore, Avangrid’s actual or perceived progress towards achieving these goals may adversely impact our financial condition and reputation.
Geopolitical instability could exacerbate existing risk factors.
The recent geopolitical developments caused by the conflict in Ukraine, increased instability in the Middle East and the strained relationship between China and the United States may further intensify risk factors highlighted in this Form 10-K for the fiscal year ended December 31, 2023 including, but not limited to, risks around inflation, interest rates, energy supply and price, supply chain delays and heightened cybersecurity and physical security threats.
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. These include but are not limited to acute risks such as floods, hail, tornados, hurricanes, wildfire and wind gusts as well as chronic risks such as drought, heat stress and seal level rise.
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.
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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 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 have caused and in the future 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 have in the past and could in the future 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 and other energy-related commodities 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 has the ability 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 dated December 15, 2016, between Avangrid and Iberdrola, 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.
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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 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 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 that 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 requires 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.
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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 geopolitical and other macroeconomics factors and events 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 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.
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 plans 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 both important to our financial performance and our operations. It is increasingly important for Avangrid to effectively promote best labor practices in terms of equity, opportunity, diversity and inclusion, as well as to provide skills related to operations and technology for energy transition. 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 and an increasing percentage of our employees are retirement eligible. If employee turnover increases or our workforce continues 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 1C. Infrastructure Protection and Cyber Security Measures
Avangrid possesses a multi-layered security management approach, consisting of controls, measures, and designs aimed at reducing the risks of unauthorized access or unsanctioned use of our facilities, assets and cyber-infrastructure, such as our transmission and distribution system. These measures are key to assessing, identifying, and managing material cybersecurity related risks and have been integrated across our respective business units, and throughout the Company’s overall risk management framework.
Avangrid possesses a multi-layered security management approach, consisting of controls, measures, and designs aimed at reducing the risks of unauthorized access or unsanctioned use of our facilities, critical assets and infrastructure, such as our transmission and distribution system. These measures have been put in place to help assess, identify, and manage material cybersecurity related risks and have been integrated across our respective business units and throughout the Company’s overall risk management framework.
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To manage our cybersecurity and operational risks, pursuant to the cybersecurity risk policy and corporate security policy approved by the board, we have implemented, and continuously refine, cyber and physical security measures that aim to strengthen our technical capabilities to protect our critical assets. In addition, the Company possesses a security governance structure focused on sharing critical and relevant information and optimizing business-wide practices that work to identify, assess and manage wide-ranging risks to the Company including those that are cyber-related.
The board’s audit committee oversees 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. The chief security officer regularly reports to the audit committee on such matters. As part of the Company’s efforts to implement measures to protect against such risks, the Company continuously monitors and, where applicable, adjusts internal policies, rules, and procedures. The Company evaluates its security framework by assessing its controls, with internal as well as external assessors, and works to continuously improve its cybersecurity systems, tools, and measures. This includes contracting with independent assessors that conduct penetration testing.
Fostering Company-wide cyber-related resiliency is also core to the Company’s security management. Avangrid annually tests its incident response plan and implements a training and awareness program that educates employees. In respect to third party services, we have processes embedded into our procurement process that evaluate contracts for risks and require vendors to adhere to our data security rider and other security measures. Our corporate security department also maintains relationships with federal and state agencies to exchange threat information as appropriate.
Upon the recommendation of the board’s audit committee, the board has appointed a senior officer responsible for security, the chief security officer, or CSO, who is a corporate and U.S. national security veteran. The CSO oversees a dedicated corporate security department responsible for managing security risks across the company. Our CSO has over 25 years of experience working in cybersecurity and gained subject matter expertise in cybersecurity, intelligence, privacy, and risk reduction while working at, among other employers, the U.S. Department of Homeland Security, the Cybersecurity and Infrastructure Security Agency, or CISA, and the North American Electric Reliability Corporation. The Company’s corporate security department is responsible for the physical and cyber security program, which is supported by a governance program that manages and assists the Company in seeking to protect our cyber, physical and information assets. Together, these members of management are informed about and monitor the threats through their implementation of the controls, measures, and designs described above.
As further described in in our 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 of this Annual Report on Form 10-K, a physical or cyber breach could result in, among other things, in theft, damage, interruption of service and the release of critical operating information or confidential customer information. While we have experienced insignificant security breaches in the past, to date, we are not aware that we have experienced a material cybersecurity or physical breach, the Company aims to takes proactive steps to manage evolving threats including, without limitation, the threat of a material cybersecurity incident. We continue to invest in technology, processes, security measures and services in our ongoing efforts to predict, detect, mitigate and protect our assets, both physical and cyber. These investments include assessments and implementation of appropriate upgrades to our cyber-infrastructure assets, network architecture and physical security measures.
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, 2023:
Location Type of Facility Leased/Owned Size (square feet)
Orange, Connecticut Office Owned 123,159 
Augusta, Maine Office Owned 215,832 
Portland, Maine Office Leased 90,325 
Rochester, New York Office Owned 149,249 
Rochester, New York Office Leased 126,716 
Portland, Oregon Office Leased 43,633 
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
Set forth below is the names of our executive officers as of February 21, 2024 and a brief account of the business experience during the past five years of each such executive officer:
Name Age (1) Title
Pedro Azagra Blázquez 55 Chief Executive Officer
Justin B. Lagasse 36 Senior Vice President – Chief Financial Officer and Controller
Jose Antonio Miranda Soto 52 President and Chief Executive Officer of Renewables
R. Scott Mahoney 58 Senior Vice President – General Counsel and Corporate Secretary
Catherine Stempien 54 President and Chief Executive Officer of Networks
(1)Age as of December 31, 2023.
Pedro Azagra Blázquez. Mr. Azagra Blázquez has served as Chief Executive Officer of Avangrid since May 29, 2022, and previously served as the Chief Development Officer of Iberdrola from 2008 until his appointment as Avangrid Chief Executive Officer. Prior to his appointment as Chief Development Officer, Mr. Azagra Blázquez served as Iberdrola’s Director of Strategy. He has also served as Professor of Corporate Finance and Mergers and Acquisitions at Universidad Pontificia de Comillas, in Madrid, Spain, since 1998. Mr. Azagra Blázquez formerly served on the board of directors of Siemens Gamesa Renewable Energy, S.A. He earned a business degree and a law degree from Universidad Pontificia de Comillas and an M.B.A. from the University of Chicago. Mr. Azagra Blázquez served as a member of Avangrid's Board since 2019 and previously served as a member of the Board from 2014 until 2018. In addition, Mr. Azagra Blázquez serves as a member of the board of directors of Neoenergia, S.A., a member of the Iberdrola group of companies listed on the São Paulo Stock Exchange.
Justin B. Lagasse. Mr. Lagasse was appointed Senior Vice President – Controller in July 2023, and was appointed Interim Chief Financial Officer in November 2023. Mr. Lagasse was appointed Senior Vice President – Chief Financial Officer and Controller on February 15, 2024. Mr. Lagasse had previously served as Senior Vice President – Controller from July 2023 and Interim Chief Financial Officer from November 2023. He is responsible for all aspects of accounting, financial reporting, business performance, long-term planning, and administration for Avangrid and its two lines of business, Networks and Renewables. Prior to this role, Mr. Lagasse most recently served as Vice President, Chief Accounting Officer and was responsible for corporate accounting, consolidations and reporting, technical accounting, and internal controls. Before joining Avangrid, Mr. Lagasse served as Assurance Director at BDO, LLP in Southern California and Assurance Senior at a regional accounting firm in Maine. Mr. Lagasse holds a bachelor’s degree in accounting and master’s degree of business administration from Thomas College and holds an active Certified Public Accountant license in Maine.
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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. On October 12, 2022, Mr. Miranda Soto became the sole President and Chief Executive Officer of Renewables. 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 Master's degree in Industrial Engineering from the Superior Technical Institute of Industrial Engineers of Gijón (Oviedo University, Spain).
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. From January 2007 to June 2012, Mr. Mahoney served as Deputy General Counsel and Chief FERC Compliance Officer for Avangrid, 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 Officer 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 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 21, 2024, there were 2,828 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, 2018 through December 31, 2023.
5 year Performance Graph 2023.jpg
December 31, 2018 December 31, 2019 December 31, 2020 December 31, 2021 December 31, 2022 December 31, 2023
Avangrid $ 100.00  $ 164.50  $ 142.64  $ 156.48  $ 102.66  $ 78.62 
S&P 500 $ 100.00  $ 171.70  $ 202.96  $ 231.31  $ 155.48  $ 207.04 
S&P Electric Utilities Index $ 100.00  $ 170.89  $ 174.91  $ 182.51  $ 167.88  $ 148.68 
S&P Utilities Index $ 100.00  $ 172.56  $ 172.38  $ 174.96  $ 159.42  $ 141.05 
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, 2018, including dividend reinvestment during this time period. The changes displayed are not necessarily indicative of future returns.
Recent Sales of Unregistered Securities
None.
Issuer Repurchases of Equity Securities
There were no repurchases of common stock of Avangrid during the fourth quarter of the year ended December 31, 2023.
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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 $44 billion in assets and operations in 24 states concentrated in our two primary lines of business - Avangrid Networks and Avangrid Renewables. Avangrid Networks owns eight electric and natural gas utilities, serving approximately 3.3 million customers in New York and New England. Avangrid Renewables owns and operates 9.3 gigawatts of electricity capacity, primarily through wind and solar power, with a presence in 22 states across the United States. Avangrid supports the achievement of the Sustainable Development Goals approved by the member states of the United Nations, was named among the World’s Most Ethical companies in 2023 for the fifth consecutive year by the Ethisphere Institute, included as a member of the 2023 Bloomberg Gender-Equality Index, and recognized by Just Capital as one of the 2024 Just 100, an annual ranking of the most just U.S. public companies for the fourth time. Avangrid employs approximately 8,000 people. Iberdrola S.A., or Iberdrola, a corporation (sociedad anónima) organized under the laws of the Kingdom of Spain, a worldwide leader in the energy industry, directly owns 81.6% of the outstanding shares of Avangrid common stock. The remaining outstanding shares are owned by various shareholders with approximately 14.7% of Avangrid's outstanding shares publicly-traded on the New York Stock Exchange (NYSE). Avangrid's primary businesses are described below.
Our direct, wholly-owned subsidiaries include Avangrid Networks, Inc., or Networks, and Avangrid Renewables Holdings, Inc., or ARHI. ARHI in turn holds subsidiaries including Avangrid Renewables, LLC, or Renewables. Networks owns and operates our regulated utility businesses through its subsidiaries, including electric transmission and distribution and natural gas distribution, transportation and sales. Renewables operates a portfolio of renewable energy generation facilities primarily using onshore wind power and also solar, biomass and thermal power.
Through Networks, we own electric distribution, transmission and generation companies and natural gas distribution, transportation and sales companies in New York, Maine, Connecticut and Massachusetts, delivering electricity to approximately 2.3 million electric utility customers and delivering natural gas to approximately 1.0 million natural gas utility customers as of December 31, 2023.
Networks, a Maine corporation, holds regulated utility businesses, including electric transmission and distribution and natural gas distribution, transportation and sales. Networks serves as a super-regional energy services and delivery company through the eight regulated utilities it owns directly:
•New York State Electric & Gas Corporation, or NYSEG, which serves electric and natural gas customers across more than 40% of the upstate New York geographic area;
•Rochester Gas and Electric Corporation, or RG&E, which serves electric and natural gas customers within a nine-county region in western New York, centered around Rochester;
•The United Illuminating Company, or UI, which serves electric customers in southwestern Connecticut;
•Central Maine Power Company, or CMP, which serves electric customers in central and southern Maine;
•The Southern Connecticut Gas Company, or SCG, which serves natural gas customers in Connecticut;
•Connecticut Natural Gas Corporation, or CNG, which serves natural gas customers in Connecticut;
•The Berkshire Gas Company, or BGC, which serves natural gas customers in western Massachusetts; and
•Maine Natural Gas Corporation, or MNG, which serves natural gas customers in several communities in central and southern Maine.
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Renewables has a combined wind, solar and thermal installed capacity of 9,338 megawatts, or MW, as of December 31, 2023, including Renewables’ share of joint projects, of which 8,045 MW was installed onshore wind capacity and 39 MW of offshore wind capacity. Renewables targets to contract or hedge above 80% of its capacity under long-term PPAs and hedges to limit market volatility. As of December 31, 2023, approximately 78% of the capacity was contracted with PPAs for an average period of approximately 9 years and an additional 11% 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, 2023, and strives to lead the transformation of the U.S. energy industry to a sustainable, competitive, clean energy future. As of December 31, 2023, Renewables installed capacity includes 68 onshore wind farms and six solar facilities operational in 21 states across the United States.
Terminated 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 (as amended by the Amendment to Merger Agreement dated January 3, 2022, Amendment No. 2 to the Merger Agreement dated April 12, 2023 and Amendment No. 3 to the Merger Agreement dated June 19, 2023), or Merger Agreement, pursuant to which Merger Sub was expected to merge with and into PNMR, with PNMR surviving the Merger as a direct wholly-owned subsidiary of Avangrid, or the Merger for approximately $4.3 billion in aggregate consideration.
On December 31, 2023, Avangrid sent a notice to PNMR terminating the Merger Agreement. The Merger was conditioned, among other things, upon the receipt of certain required regulatory approvals, including the approval of the NMPRC, and provided that the Merger Agreement may be terminated by either Avangrid or PNMR if the closing of the Merger shall not have occurred by 5:00 PM New York City Time on December 31, 2023, or the End Date. Because the required approval of the NMPRC was not received by the End Date and the conditions to the closing of the Merger were not satisfied by the End Date, Avangrid exercised its right to terminate the Merger Agreement. No termination penalties were incurred by either party in connection with the termination of the Merger Agreement. The Funding Commitment Letter and related side letter agreement with Iberdrola terminated automatically upon termination of the Merger Agreement.
In light of the termination of the Merger Agreement, on January 8, 2024, Avangrid filed a motion to withdraw from the appeal it and PNMR’s subsidiary, Public Service Company of New Mexico (PNM), had filed with the New Mexico Supreme Court with respect to the NMPRC’s December 8, 2021, order which had rejected the amended stipulated agreement entered into by PNM, Avangrid and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application.
For additional information on the Merger, see Note 1 - Background and Nature of Operations.
Business Environment
The impact of extraordinary external events such as global pandemics and geopolitical instability continue to cause global economic and supply chain disruption and volatility in financial markets and the United States economy. We continue to experience changes in inflation levels resulting from various supply chain disruptions, increased business and labor costs, increased financing costs from changes in the Federal Reserve's monetary policy and other disruptions caused by global economic conditions. We continue to monitor the further developments, which may include further sanctions imposed by the United States, Canada, and the European Union on Russia, supply chain instability, and potential retaliatory action by the Russian government and/or other countries. We are taking steps intended to mitigate the potential risks from continued conflict, including without limitation, communication with suppliers to ensure that the supply chains are free from sanctioned materials and efforts to diversify sourcing and capacity planning to help avoid supply chain disruptions. To date, there has been no material impact on our operations or financial performance as a result of ongoing extraordinary events including, without limitation, the conflicts in Eastern Europe and the Middle East; however, we cannot predict the extent of these effects, given the evolving nature of the geopolitical situation, on our business, results of operations or financial condition.
We are monitoring the Department of Commerce's, or DOC, anti-circumvention petition alleging that solar panels and cells shipped from Vietnam, Thailand, Malaysia and Cambodia have circumvented tariffs imposed on Chinese solar panels and cells. The petition calls for anti-dumping and countervailing duties to be applied to solar panels. In June 2022, President Biden's Administration announced a 24-month tariff exemption on any potential tariff resulting from the anti-circumvention investigation. On August 18, 2023, DOC issued final rulings, concluding some manufacturers operating in the named countries circumvented the AD/CVD duties on a country-wide basis. Renewables is taking steps intended to mitigate potential risks to their solar project development portfolio. To date, there has been no material impact on Renewables' operations or financial performance as a result of this investigation. Despite the 24-month tariff exemption, there is uncertainty around related long-term effects to the solar panel supply chain and we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.
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In April 2023, the House Transportation and Infrastructure Committee included maritime crewing provisions within the Coast Guard Authorization bill which passed the committee. The bill was not included in the House National Defense Authorization Act - there is no clear path for passage at this point. If enacted, the Coast Guard authorization may only allow foreign vessels to operate on the Outer Continental Shelf if they have a U.S. crew or the crew of the nation of which the vessel is from. If passed, the legislation could affect expected timelines and returns on approved projects. To date, there has been no material impact on Renewables' operations or financial performance as a result of these bills; however, given the uncertainty of resolution of the final legislation and the related effects to our offshore projects, we currently cannot predict if there will be materially adverse impacts to our business, results of operations or financial condition.
There are a limited number of wind turbine suppliers in the market. Renewables’ largest turbine suppliers, Siemens-Gamesa and GE Wind, were engaged in an intellectual property dispute with respect to certain offshore wind turbines including the wind turbines to be used in the Vineyard Wind 1 project. In July 2022, the federal district court granted Siemens-Gamesa’s request for a permanent injunction barring GE Wind from importing and selling the infringing wind turbines, which carved out the wind turbines for the Vineyard Wind 1 project from such injunction. On April 1, 2023, Siemens-Gamesa and GE Wind announced a global settlement resolving the dispute. Following the settlement, the judge in the patent case vacated the permanent injunction by an order dated April 3, 2023. While there was no material impact on Renewables' operations or turbine procurement arising out of this dispute, we continue to monitor developments with the limited number of turbine suppliers that may have an impact on Renewables' operations or turbine procurement.
In April 2023, Avangrid Renewables received a letter from the U.S. Fish and Wildlife Service regarding certain bald and gold eagle fatalities that allegedly occurred at certain Avangrid Renewables facilities that are not covered by an eagle take permit. Avangrid Renewables has responded to the U.S. Fish and Wildlife Service providing information about the relevant eagle taking permit applications and relevant mitigation activity at each facility. We cannot predict the outcome of this preliminary inquiry.
On June 30, 2023 Avangrid received an exclusion notice from the U.S. Customs and Border Protection, or CBP, in the Port of Fresno, California, denying entry to approximately 220 MWs of solar modules for use in the company’s Bakeoven and Daybreak solar projects. The notice stated that the modules were rejected due to insufficient documentation demonstrating the merchandise was not produced in whole or in part in the Xinjiang Uyghur Autonomous Region or by an entity on the Uyghur Forced Labor Prevention Act, or UFLPA, Entity List within 30 days from which the cargo was detained. In September 2023 Avangrid entered into a bill of sale and assumption and assignment agreement with Iberdrola Renovables Energia SAU, or IRE, a subsidiary of Iberdrola, and the solar panel supplier to assign all of its rights, title and interest in the 220 MWs of solar modules to IRE. Pursuant to such agreement, Avangrid will receive reimbursement of the amounts previously paid to the solar supplier for such modules, when the title to such modules are transferred to IRE upon delivery to IRE's delivery location, expected in Q1 2024.
For more information, see the risk factor in Item 1A. Risk Factors in this Form 10-K.
Summary of Results of Operations
Our operating revenues increased by $386 million from $7,923 million for the year ended December 31, 2022, to $8,309 million for the year ended December 31, 2023.
Networks business revenues increased mainly due to rate increases in New York effective October 12, 2023. Renewables revenues increased mainly due to favorable thermal and power trading due to higher average prices in the period primarily driven by weather.
Net income attributable to Avangrid decreased by $95 million from $881 million for the year ended December 31, 2022, to $786 million for the year ended December 31, 2023. The decrease is primarily driven by a gain recognized in 2022 from the offshore joint venture restructuring transaction in Renewables.
Adjusted net income (a non-GAAP financial measure) decreased by $93 million, from $901 million for the year ended December 31, 2022 to $808 million for the year ended December 31, 2023. The decrease is primarily due to a $240 million decrease in Renewables driven by a gain recognized in 2022 from the offshore joint venture restructuring transaction, offset by a $99 million increase in Networks driven primarily by rate increases in New York effective October 12, 2023 and a $48 million increase in Corporate mainly driven by a tax benefit from unitary state tax changes 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.
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Our financial condition and financing capability will be dependent on many factors, including the level of income and cash flow of our 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 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 2024 and 50% of the second half of 2024. 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 2024.
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.
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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 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
On September 9, 2022, UI filed a distribution revenue requirement case proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (UI Rate Year 1), September 1, 2024 (UI Rate Year 2), and September 1, 2025 (UI Rate Year 3). UI requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $91 million in UI Rate Year 1, an incremental increase of approximately $20 million in UI Rate Year 2, and an incremental increase of approximately $19 million in UI Rate Year 3, compared to total revenues that would otherwise be recovered under UI’s current rate schedules. UI’s Rate Plan also included several measures to moderate the impact of the proposed rate update for all customers, including, without limitation, a rate levelization proposal to spread the proposed total rate increase over the three rate years, which would result in a change in revenue in UI Rate Year 1 of approximately $54 million. On August 25, 2023, PURA issued its Final Decision on UI's one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels.
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On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because of factual and legal errors related to the treatment of deferred assets, plant in service, and operating expenses. We cannot predict the outcome of this matter.
On April 24, 2023, the Connecticut Attorney General, Office of Consumer Counsel, Connecticut Public Utilities Regulatory Authority Office of Education, Outreach, and Enforcement and the Connecticut Industrial Energy Consumer filed a Petition requesting that PURA conduct a general rate hearing for CNG. On May 5, 2023, CNG and SCG responded indicating a willingness to file general rate cases for each company. PURA assented to the companies’ proposal on May 21, 2023. On September 29, 2023, SCG and CNG filed a notice of intent to file general rate cases on or about November 3, 2023.
On November 3, 2023, CNG and SCG filed a distribution revenue requirement case proposing a one-year rate plan commencing November 1, 2024 through October 31, 2025, for each company respectively. The filing was based on a test year ending December 31, 2022. CNG requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $19.8 million, and SCG requested approval of new distribution rates to recover an increase in revenue requirements of approximately $40.6 million. CNG’s and SCG’s Rate Plan also included several measures to moderate the impact of the proposed rate update for all customers, including the adoption of a low-income discount rate and seeking to maintain their current revenue decoupling and earning sharing mechanisms.
On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval. The Settlement Agreement followed BGC’s December 14, 2021 filing of a Notice of Intent to File Rate Schedules. Following that filing, BGC and the AGO negotiated the Settlement Agreement in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allows for agreed-upon adjustments to BGC’s revenue requirement as well as various step increases BGC shall be entitled to on January 1, 2023 and January 1, 2024. It provides for the opportunity to increase BGC’s revenue requirement by as much as $5.6 million over current rates (reflective of a 9.70% ROE and a 54.00% equity ratio as well as other stepped adjustments) through January 1, 2024. The Settlement Agreement was approved in its entirety by the DPU on October 27, 2022, and new rates went into effect January 1, 2023.
On May 26, 2022, NYSEG and RG&E filed for a new rate plan with the NYPSC. The rate filings were based on test year 2021 financial results adjusted to the rate year May 1, 2023 – April 30, 2024. NYSEG and RG&E filed for a one-year rate plan but expressed interest in exploring a multi-year plan during the pendency of the case (as is the custom in New York).
On September 16, 2022, the NYPSC suspended new tariffs and rates through April 21, 2023, and NYSEG and RG&E voluntarily agreed to subsequent suspensions through October 18, 2023, subject to a make-whole provision.
Following discovery and settlement negotiations, on June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. Hearings on the settlement followed in July 2023. The 2023 JP provides for a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2023 and continuing through April 30, 2026. For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the JP 2023, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs was November 1, 2023 with a make-whole provision back to May 1, 2023.
The 2023 JP, as approved, includes levelization across the three years of the rate plan for delivery rates for NYSEG's and RG&E’s Electric and Gas businesses. Actual bill impacts vary by customer class based on the agreed‑upon revenue allocation and rate design. The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas is 9.20%. The common equity ratio for each business is 48.00%.
The 2023 JP also includes an Earnings Sharing Mechanism (ESM) applicable to each business which varies based on the earned ROE with 100% of the customers’ portion of earnings above the sharing threshold that would otherwise be deferred for the benefit of customers to be used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition, 50% of NYSEG's and RG&E’s portion will be used to reduce their respective outstanding storm-related regulatory asset deferral balances to the extent such balances exist.
The 2023 JP further enhances distribution vegetation management, maintains gas safety performance measures, establishes threshold performance levels for designated aspects of customer service quality, and includes three Electric Reliability Performance Measures (SAIFI, CAIDI, and Distribution Line Inspection Program Metric for Level II Deficiencies) with a negative revenue adjustment (NRA) beginning with calendar year 2023, if NYSEG fails to meet its annual SAIFI performance metric.
NYSEG and RG&E will continue a RAM to return or collect the remaining Customer Bill Credits established in the prior rate plan and will continue an Electric Revenue Decoupling Mechanism on a total revenue per class basis.
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The 2023 JP reflects the recovery of deferred NYSEG Electric and RG&E Electric Major Storm costs of approximately $371 million and $54.6 million, respectively. NYSEG’s remaining super storm regulatory asset of $52.3 million and the non-super storm regulatory asset of $96.6 million from the 2020 Joint Proposal are being amortized over seven years. RG&E’s remaining non-super storm regulatory asset of $19.6 million established prior to the 2020 Joint Proposal is being amortized over two years. All other deferred storm costs at both NYSEG and RG&E are being amortized over 10 years. The 2023 JP gradually increases NYSEG’s and RG&E’s Major Storm rate allowances over the term of the 2023 JP to better align NYSEG’s and RG&E’s actual Major Storm costs with such rate allowances and to support NYSEG’s and RG&E’s credit metrics.
The 2023 JP contains provisions consistent with, supportive of, and in furtherance of the objectives of the CLCPA including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan.
In an order issued on February 19, 2020, the MPUC authorized an increase in CMP's distribution revenue requirement of $17 million, or approximately 7.00%, based on an allowed ROE of 9.25% and a 50.00% equity ratio. The rate increase was effective March 1, 2020. Commencing on March 1, 2020, the MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order.
On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. On May 31, 2023, CMP filed a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 0.01 basis points of CMP’s allowed ROE. The Stipulation also provided for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. The next three increases will occur on January 1, 2024, July 1, 2024, and January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecast by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets. The Stipulation was approved by the MPUC on June 6, 2023.
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.
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 of 9.2%. CMP and UI are NETOs with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.
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On December 26, 2012, a second related complaint for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On July 31, 2014, a third related complaint was filed for a subsequent rate period requesting the ROE be reduced to 8.84%. On April 29, 2016, a fourth complaint was filed for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%.
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 FERC. We cannot predict the final outcome of the proceedings.
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 estimated construction costs of approximately $1.5 billion in total, would add 1,200 MW of transmission capacity to supply Maine and the rest of New England with power from reliable hydroelectric generation.
On June 13, 2018, CMP entered into transmission service agreements, or TSAs, with the Massachusetts EDCs, and H.Q. Energy Services (U.S.) Inc., or HQUS, an affiliate of Hydro-Québec, which govern the terms of service and revenue recovery for the NECEC transmission project. Simultaneous with the execution of the TSAs with CMP, the EDCs executed certain PPAs with HQUS for sales of electricity and environmental attributes to the EDCs. On October 19, 2018, FERC issued an order accepting the TSAs for filing as CMP rate schedules effective as of October 20, 2018. On June 25, 2019, the Massachusetts DPU issued an Order approving the NECEC project long term PPAs and the cost recovery by the EDCs of the TSA charges. This Order was subsequently appealed by NextEra Energy Resources. On September 3, 2020, the Massachusetts Supreme Judicial Court denied NextEra Energy Resources’ appeal of the DPU Order.
The NECEC project requires a Certificate of Public Convenience and Necessity, or CPCN, from the MPUC. On May 3, 2019, the MPUC issued an Order granting the CPCN for the NECEC project. This Order was subsequently appealed by NextEra Energy Resources. On March 17, 2020, the Maine Law Court denied NextEra Energy Resources’ appeal of the CPCN.
On January 4, 2021, CMP transferred the NECEC project to NECEC Transmission LLC, a wholly-owned subsidiary of Networks, pursuant to the terms of a transfer agreement dated November 3, 2020.
The NECEC project requires certain permits, including environmental, from multiple state and federal agencies and a presidential permit from the U.S. Department of Energy, or DOE, authorizing the construction, operation, maintenance and connection of facilities for the transmission of electric energy at the international border between the United States and Canada. On January 8, 2020, the Maine Land Use Planning Commission, or LUPC, granted the LUPC Certification for the NECEC. The Maine Department of Environmental Protection, or MDEP, granted Site Location of Development Act, Natural Resources Protection Act, and Water Quality Certification permits for the NECEC by an Order dated May 11, 2020. The MDEP Order was appealed by certain intervenors. Through an Order dated July 21, 2022, the Maine Board of Environmental Protection, or MBEP, denied the appeals of the MDEP Order, as well as the appeal of MDEP’s December 4, 2020 Order approving the partial transfer of the permits for the project to NECEC Transmission LLC. In August 2022, the intervenors that had appealed the MDEP Order appealed the MBEP Order. Certain of those intervenors dismissed their challenge in June 2023, though one group has continued to maintain their challenge. That appeal is pending before the Maine Superior Court. In addition, certain intervenors appealed MDEP's May 7, 2021 Order approving certain minor revisions. On February 16, 2023 the MBEP denied the appeal and affirmed the referred MDEP Order. In March 2023, the intervenors appealed the MBEP order to the Maine Superior Court, though subsequently dismissed that challenge in June 2023.
On November 6, 2020, the project received the required approvals from the U.S. Army Corps of Engineers, or Army Corps, pursuant to Section 10 of the Rivers and Harbor Act of 1899 and Section 404 of the Clean Water Act. A complaint for declaratory and injunctive relief asking the court to, among other things, vacate or remand the Section 404 Clean Water Act permit for the NECEC project filed by three environmental groups is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.
ISO-NE issued the final System Impact Study (SIS) for NECEC on May 13, 2020, determining the upgrades required to permit the interconnection of NECEC to the ISO-NE system. On July 9, 2020, the project received the formal I.3.9 approval associated with this interconnection request. CMP, NECEC Transmission LLC and ISO-NE executed an interconnection agreement. With respect to the upgrade required at the Seabrook Nuclear Generation Station, or Seabrook Station, on February 1, 2023, FERC issued an order granting in part Avangrid and NECEC Transmission LLC’s complaint against NextEra Energy Resources, LLC and NextEra Energy Seabrook, LLC, or Seabrook, denying in part Avangrid and NECEC Transmission LLC’s complaint, and dismissing Seabrook’s petition for declaratory order.
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Among other things, FERC directed Seabrook to replace the breaker at Seabrook Station pursuant to its obligations under Seabrook Station’s large generator interconnection agreement and good utility practice. Furthermore, FERC determined that Seabrook should not recover opportunity or legal costs in connection with the breaker replacement. NextEra sought reconsideration of FERC’s decision, which was denied in April 2023 and by further FERC order in June 2023. NextEra has appealed that decision to the U.S. Court of Appeals for the D.C. Circuit, where it remains pending. We cannot predict the outcome of this proceeding.
On January 14, 2021, the DOE issued a Presidential Permit granting permission to NECEC Transmission LLC to construct, operate, maintain and connect electric transmission facilities at the international border of the United States and Canada. On March 26, 2021, the plaintiffs challenging the Army Corps permit filed a motion for leave before the District Court in Maine to supplement their complaint to add claims against DOE in connection with the Presidential Permit. On April 20, 2021, the District Court granted the plaintiffs motion to amend the complaint. On April 22, 2021, the plaintiffs filed their amended complaint asking the Court, among other things, to vacate, set aside, remand or stay the Presidential Permit. This challenge to the Presidential Permit is currently pending before the District Court in Maine. We cannot predict the outcome of this proceeding.
On November 2, 2021, Maine voters approved, by virtue of a referendum, L.D. 1295 (I.B. 1) (130th Legis. 2021), “An Act To Require Legislative Approval of Certain Transmission Lines, Require Legislative Approval of Certain Transmission Lines and Facilities and Other Projects on Public Reserved Lands and Prohibit the Construction of Certain Transmission Lines in the Upper Kennebec Region” (the “Initiative”), which per its terms would retroactively apply to the NECEC project. In particular, the Initiative (i) required, 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) prohibited, retroactive to 2020, construction of a high-impact electric transmission line in the Upper Kennebec Region, and (iii) required, retroactive to 2014, the vote of 2/3 of all members elected to each House of the Maine Legislature for a lease by the Bureau of Parks and Lands (“BPL”) of public reserved lands for transmission lines and similar linear projects.
On November 3, 2021, Networks and NECEC Transmission LLC filed a lawsuit challenging the constitutionality of the Initiative and requesting injunctive relief preventing retroactive enforcement of the Initiative to the NECEC transmission project. Networks and NECEC Transmission LLC also requested a preliminary injunction preventing such retroactive enforcement during the pendency of the lawsuit, which was ultimately denied. The Initiative took effect on December 19, 2021.
On December 22, 2021, Networks and NECEC Transmission LLC moved that the Business & Consumer Court report its decision to the Maine Law Court for an interlocutory appeal under the applicable rule of appellate procedure. The Business & Consumer Court granted this motion, thereby sending its decision to the Law Court for review. On August 30, 2022, the Law Court ruled that certain Initiative provisions would infringe on NECEC’s constitutionally protected vested rights if NECEC Transmission LLC can demonstrate that it engaged in substantial construction of the NECEC project in good-faith reliance of the authority under the CPCN granted by the MPUC before Maine voters approved the Initiative. The Maine Law Court remanded the matter to the Business & Consumer Court for a trial to determine that question. The trial began on April 10, 2023 and concluded on April 20, 2023, when the jury reached a unanimous decision finding that NECEC had constructed substantial construction in good faith. The Court subsequently entered an Order that NECEC had obtained vested rights to continue work on the project, and that retroactively applying the Initiative to the NECEC project would violate the Maine Constitution. No party appealed that decision.
On November 23, 2021, the MDEP issued an Order finding that the Initiative constituted a changed circumstance justifying the suspension of the MDEP permits for the NECEC project. In its order, the MDEP ruled that, so long as such MDEP permits are suspended, all construction must stop, subject to the performance and completion of certain activities required by the Order. The MDEP lifted the Order in May 2023.
On August 3, 2023, NECEC resumed limited construction and is continuing to evaluate the construction schedule for the NECEC project, related commercial operation date, and total project cost, including potential impacts from increased construction costs, disputes with third party vendors regarding contracts and certain change orders, and a decrease in expected returns. As of December 31, 2023, we have capitalized approximately $807 million for the NECEC project, which includes capitalized interest costs and other additional payments related to the project along with construction costs.
In connection with the lease granted by BPL over a small area of Maine public lands to house a 0.9-mile section of the NECEC, on November 29, 2022, the Law Court vacated the trial court’s prior decision to reverse BPL’s decision to grant the lease. The Law Court confirmed that BPL acted within its constitutional and statutory authority when granting the lease.
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Furthermore, the Law Court held that the section of the Initiative that requires the vote of 2/3 of all members elected to each House of the Maine Legislature for a lease by BPL of public reserved lands for transmission lines and similar linear projects, as retroactively applied to the lease for the NECEC, violates the Contracts Clauses of the U.S. and Maine Constitutions and, accordingly, that the lease was not voided by the Initiative.
At the municipal level, the project has obtained multiple municipal approvals and will pursue any remaining municipal approvals in accordance with the project schedule.
Maine Government-Run Power Referendum
In November 2023, Maine voters rejected a government-run power referendum and approved a “No Blank Checks” referendum that requires citizens to approve the debt issued by the State of Maine greater than $1 billion, including debt necessary for a government-controlled entity to seize the assets of an investor-owned utility.
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. While no proceedings have been brought before the MPUC, we cannot predict the outcome of this matter or any potential proceedings before the MPUC.
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 were recoverable through electric rates. On October 13, 2023, PURA approved the termination of this agreement between UI and its affiliate for the development of Park City Wind Project.
Reforming the Energy Vision
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 was 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, or DER, such as micro grids, on-site power supplies and storage.
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The NYPSC issued a 2015 order in Track 1, which acknowledged the utilities’ role as a Distribution System Platform provider, and required the utilities to file an initial Distribution System Implementation Plan, or DSIP, followed by bi-annual updates. The next scheduled DSIP update is June 30, 2025.
A Track 2 order was issued in May 2016, and included guidance related to the potential for Earnings Adjustment Mechanisms, or EAMs, Platform Service Revenues, innovative rate designs and data utilization and security. EAMs were approved by the NYPSC on November 19, 2020 in its Order approving the companies' 2020 Rate Plan. Modifications to EAMs were approved by the NYPSC on October 12, 2023 in its Order approving the companies' 2023 Rate Plan.
In 2017, the NYPSC approved a transition from traditional Net Energy Metering, or NEM, towards a more values-based approach (Value Stack) for compensating DER. Since that time, the NYPSC has issued a number of orders on additional Value of Distributed Energy Resources matters. Most recently, NYPSC Staff issued a proposal on Community Distributed Generation Billing, or CDG billing, and Crediting Performance Metrics and Negative Revenue Adjustments, or NRAs. The NYPSC Staff recommends six CDG performance metrics with associated NRAs that would incent improvements to the CDG billing processes. At this time, the outcome of this proceeding is unknown.
Other REV-related orders pertaining to electric vehicles, or EV, an Integrated Energy Data Resource, or IEDR, platform and energy storage are summarized below.
•The NYPSC issued an Order on April 20, 2023 instituting a proceeding to advance infrastructure for medium and heavy-duty vehicles. The Joint Utilities filed an implementation plan with the NYPSC for the medium and heavy-duty pilot program. The Joint Utilities are awaiting NYPSC approval of the implementation plan.
•On February 11, 2021, the NYPSC issued an Order to implement an Integrated Energy Data Resource platform, where NYSERDA was designated as the Program Sponsor of the platform. 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 January 19, 2024, the NYPSC issued an Order approving the Phase 2 budget, with costs up to the combined cost cap deferred for future recovery in the same manner as Phase 1.
•An order 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 EV charging stations.
•On December 13, 2018, the NYPSC issued an Order for utilities to file implementation plans detailing a competitive procurement process and cost recovery for deploying qualified storage systems. NYSEG and RG&E have tariffs in effect to collect costs for the procurement of qualified energy storage assets.
Tax Act Proceedings
The Tax Cuts and Jobs 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, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery of regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions. 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.
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 $130 million and $137 million, respectively, at December 31, 2023 and December 31, 2022.
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CMP began recovering its regulatory asset in 2020. In 2017, the NYPSC commenced an audit of the power tax regulatory assets. On January 11, 2018, the NYPSC issued an order opening an operations audit of NYSEG and RG&E and certain other New York utilities regarding tax accounting. In September 2023, NYSEG and RG&E received the NYPSC final audit report and in October 2023 we responded with comments and a request for certain clarifications. The report includes recommendations that are primarily intended to enhance existing practices. The NYPSC audit process was completed and the final audit report issued by the Commission on November 21, 2023 with no impacts to the recorded regulatory assets.
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 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, 2023. 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 the final tranche confirmation executed in 2022. UI’s contractual obligation is to procure 20% of RECs produced by about 255 MW of residential solar installations. Connecticut statutes provide 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.
In 2020, pursuant to the 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 were recoverable through electric rates. On October 2, 2023, Park City Wind entered into a first amendment, termination agreement and release with each of the Connecticut EDCs, providing for an orderly termination of the Park City Wind PPAs. On October 13, 2023, PURA approved the termination agreements.
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 August 17, 2013, CMP entered into a 20-year fixed rate agreement with Maine Wood Pellets, a 7.1 MW wood-fired biomass cogeneration facility. Pursuant to a MPUC Order dated September 22, 2016, CMP entered into a 20-year fixed rate agreement with Georges River Energy, a 7.5 MW wood-fired biomass cogeneration facility. Pursuant to a MPUC Order dated August 3, 2017, CMP entered into a 20-year fixed rate agreement with Pittsfield Solar 9.9 MW photovoltaic facility. 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.
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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 of which six have since terminated. In October 2021 CMP executed contracts with six additional facilities (Tranche 2) of which one has since terminated. Each of the Tranche 1 and Tranche 2 contracts 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.
UI RAM Proceedings
On September 17, 2022, a final decision was issued by PURA in connection with PURA’s annual review of UI’s rate adjustment mechanisms, or RAM. In the final decision, PURA included certain line-items in the revenue decoupling mechanism, or RDM, resulting in the disallowance of approximately $5.1 million. On September 1, 2022, UI filed a motion for reconsideration with PURA, which was denied. UI’s appeal to the Connecticut Superior Court was filed on October 31, 2022. Oral argument took place on January 3, 2024.
On August 16, 2023, PURA issued a final decision in UI’s annual RAM, similar to the decision in 2022 resulting in disallowances related to the RDM and incentive compensation of approximately $6.8 million. UI requested Reconsideration of the Final Decision to correct the prior year transmission revenue requirement number used in the decision to update it to the current year. PURA granted the request for Reconsideration on September 25, 2023 and issued decision on the motion on October 25, 2023. UI filed an administrative appeal of this matter on December 8, 2023 with the Connecticut Superior Court. A motion to stay the proceeding pending the outcome of the 2022 RAM appeal was granted on February 1, 2024. We cannot predict the outcome of these matters.
UI Interim Rates
UI filed an application to request interim rates to increase incremental base revenues pending the earlier of: (a) resolution of the administrative appeal of the UI rate case; or (b) the issuance of a final rate decision in a subsequent rate proceeding. PURA denied this motion on December 29, 2023. UI appealed the decision on February 9, 2024. We cannot predict the outcome of this matter.
Citizen’s initiative in Maine
On November 7, 2023, Maine voters approved a citizen’s initiative, or the Initiative, that, among other things, prohibits “foreign government-influenced entities” from any political spending on candidate or referendum campaigns in the state of Maine. The Initiative defines a “foreign government-influenced entity” as an entity in which a foreign government directly or indirectly owns at least a 5% interest. On December 12, 2023, CMP filed suit in the United States District Court for the District of Maine challenging the constitutionality of the Initiative and seeking to enjoin its enforcement. Several other challengers filed similar constitutional challenges. These cases have been consolidated and oral argument will be held on February 23, 2024. We cannot predict the outcome of this matter.
PURA Investigation of the Preparation for and Response to the Tropical Storm Isaias and Connecticut Storm Reimbursement Legislation
On August 6, 2020, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.
On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of approximately $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court.
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This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. Following oral arguments in October 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI filed a notice of appeal to Connecticut's Appellate court on November 7, 2022. The matter has been briefed and oral argument was held on December 11, 2023.We cannot predict the outcome of this proceeding.
Proposed Connecticut Performance-Based Regulation
On March 17, 2023, PURA issued a draft decision proposing a regulatory framework for Performance-Based Regulation, or PBR, for electric distribution companies. The Draft Decision establishes the regulatory goals, foundational considerations, and priority outcomes to guide PBR development among other things. The intent of the PBR framework is to drive improvement in utility performance to better serve the public interest. Additional areas of focus include establishing an equitable modern grid framework, and providing a toolkit for regulatory reform. We cannot predict the outcome of this proposed regulation.
Proposed New York Legislation in Response to the Tropical Storm Isaias
Proposed legislation has been introduced that would amend the public service law to, among other things, increase potential penalties and give greater discretion to the NYPSC to assess penalties for violations of the Public Service Law, Regulations, or Orders of the NYPSC. We cannot predict the outcome of this proposed legislation.
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. 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. The investigation was closed by the MPUC with no findings.
CMP Storm Cost Disallowance
On September 6, 2023, the Maine Office of the Public Advocate (OPA) initiated a regulatory proceeding before the MPUC challenging CMP’s 2022 incremental storm costs. The OPA claims that CMP was imprudent in its storm restoration activities in 2022 by retaining an “excessive” number of external storm restoration crews to restore electric service, and seeks a disallowance of approximately $53.6 million of storm related costs from recovery from customers. A hearing is set for May 30, 2024, with MPUC deliberations scheduled for the third quarter of 2024. We cannot predict the outcome of this proceeding.
Late Payment Charge Order
Due to the COVID-19 pandemic, the State of New York previously issued an executive order on March 20, 2020 which, among other items, resulted in the suspension of recovery of unbilled fees, including late payment fees and other fees associated with customer non-payment including, but not limited to, connection fees and reconnection fees. On June 17, 2022, the NYPSC issued an order authorizing NYSEG and RG&E to establish a surcharge to recover unbilled fees for Rate Year One and a surcharge/surcredit for Rate Years Two and Three, subject to the offsetting cost reductions resulting from the COVID-19 pandemic, starting on July 1, 2022.
New York Climate Leadership and Community Protection Act
In June 2019, the New York State legislature passed a new law titled the Climate Leadership and Community Protection Act, or CLCPA, which could have significant impacts on the operations of electric and gas utilities in New York. A Climate Action Council has been formed consistent with the CLCPA, and that Council will be providing guidance to New York State in reaching aggressive renewable and emission reduction goals delineated in the CLCPA. On December 30, 2021, the Climate Action Council issued a Draft Scoping Plan, which includes numerous draft recommendations designed to ensure a fair transition to achieving New York’s greenhouse gas emission reduction goals and renewable energy goals. The Draft Scoping Plan is subject to a 120-day public comment period, and the Climate Action Council published the final Scoping Plan on December 16, 2022, which was approved by the Climate Action Council on December 19, 2022.
On February 16, 2023, the NYPSC issued an order to authorize transmission upgrades solely to support new renewable generation sources (Phase 2) pursuant to the implementation of the Accelerated Renewable Growth and Community Benefit Act.
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The order approves an estimated $4.4 billion in transmission upgrades proposed by upstate utilities to help integrate 3,500 MW of clean energy capacity into the grid, of which NYSEG and RG&E are approved for estimated upgrade costs of $2.2 billion, including participation with other upstate utilities on certain projects.
The Joint Proposal (2023 JP) for a three-year rate plan filed by NYSEG and RG&E and approved by the NYPSC on October 12, 2023, contains provisions consistent with, supportive of, and in furtherance of the objectives of the CLCPA including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe.
Propel NY Energy Project
On June 20, 2023, a proposal by New York TransCo, in partnership with the New York Power Authority, or NYPA, was selected as the most cost-efficient project by the NYISO in response to a solicitation for the Long Island Offshore Wind Export Public Policy Transmission Need to provide transfer capability of at least 3,000 MW, from the Long Island transmission district to another utility's transmission infrastructure. This project, titled Propel NY Energy Project, has an estimated cost of approximately $2.2 billion, excluding certain interconnection costs that are not yet finalized. Networks holds an approximate 20% ownership interest in New York TransCo.
Customer Arrearages Reduction Order
On June 16, 2022, the NYPSC issued an order authorizing an arrears reduction program targeting low-income customers to provide COVID-19-related relief through a one-time bill credit to eliminate accrued arrears through May 1, 2022. A portion of the targeted arrearages will be funded via direct contributions from the State of New York, and the remainder is to be received via a surcharge to all customers. The surcharge recovery is over five years for RG&E and three years for NYSEG beginning on August 1, 2022.
On January 19, 2023, the NYPSC issued a subsequent order providing bill relief for customers who did not receive a credit as part of the Phase 1 Program approved in 2022 (Low Income Program participants). Qualifying residential and small business customers are eligible to have any past-due balance from bills for service through May 1, 2022, reduced through a one-time bill credit, up to a maximum credit below:
Residential Total Forecast Residential Credits Small Business Total Forecast Small Business Credits
Company (Millions) (Millions)
NYSEG Up to $1,000 $ 16.9 Up to $1,250 $ 1.4
RG&E Up to $1,500 $ 15.2 Up to $1,500 $ 0.6
Inflation Reduction Act
In August 2022, the Inflation Reduction Act of 2022, or IRA, was signed into United States law. The IRA created a new corporate alternative minimum tax, or CAMT, of 15% on adjusted financial statement income and an excise tax of 1% on the value of certain stock repurchases. The IRA also contains a number of additional provisions related to tax incentives for investments in renewable energy production, carbon capture, and other climate actions. The CAMT and other various applicable provisions of the IRA are effective for the Company for periods beginning after December 31, 2022. The impact of CAMT will depend on our facts in each year, as well as on anticipated guidance from the U.S. Department of Treasury. The Company paid $32 million of CAMT in 2023, comprised of an estimated $129 million of gross initial obligation; partially offset by $97 million of tax credit utilization. The Company also established an equivalent $129 million, unlimited lived gross CAMT carryforward asset, which will be available in future periods to offset regular income tax that exceeds CAMT.
Pillar Two
The Organization for Economic Co-operation and Development (OECD) has issued Pillar Two model rules that subjects adoptees to a new global minimum tax of 15% intended to be effective on January 1, 2024. In Spain, the Ministry of Finance published draft legislation on Pillar Two in December 2023, but the final rules remain uncertain. The US has not adopted the Pillar Two model rules. Therefore, applicability to Avangrid is currently limited to the indirect impact Spain’s adoption of these rules could have on Iberdrola and its subsidiaries. As part of its financial reporting, Iberdrola Group has assessed Pillar Two implications and concluded that it does not expect a significant equity impact derived from the application of the model rules. Consistent with this assessment, Avangrid does not currently believe Pillar Two will have a significant impact on its earnings or cash flows.
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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.
The IRA extended and enhanced solar and wind tax incentives. The IRA also added certain prevailing wage and apprenticeship rules for projects to claim the full credit value unless construction started prior to January 29, 2023. The IRA provides other credit enhancements for qualifying projects that meet domestic content and/or energy community siting requirements.
The 2020 Consolidated Appropriations Act provided favorable extensions to renewable income tax incentives. Onshore and offshore wind projects could claim a 60% PTC for projects commencing construction in 2020 and 2021 and placed in service prior to 2022. Previously, the Setting Every Community up for Retirement Enhancement Act of 2019 extended the PTC and ITC options for wind facilities to 60% of the full credit for facilities commencing construction in 2020 and placed in service prior to 2022.
Solar projects commencing construction before 2020 and placed in service before 2022 could claim a 30% ITC. Solar projects commencing construction in 2020 and 2021 and placed in service before 2022, could claim a 26% ITC.
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 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 806 MW offshore wind project that is a joint venture with CIP.
Lawsuits were filed in July 2021, August 2021, September 2021 and January 2022 against the federal permitting agencies and related officials, including 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. Vineyard Wind 1 has intervened in these lawsuits to support the federal defense and protect its rights. Motions to dismiss filed in each of these lawsuits were granted in favor of the federal defendants and Vineyard Wind 1. Each of these lawsuits has been appealed. We cannot predict the outcome of these proceedings.
Texas Weather Event
During February 2021, Texas and the surrounding region experienced unprecedented extreme cold weather, resulting in outages impacting millions in the state. Renewables safely operated our Texas wind generation facilities during this event meeting all of our delivery obligations in Texas and producing excess energy that was sold based on the rules established at the time by the Energy Reliability Council of Texas, or ERCOT. If the received payments are adjusted by ERCOT, it could adversely affect our results of operations.
In connection with the Texas Weather Event, a number of plaintiffs have filed multiple cases against generators and natural gas suppliers, including certain Renewables entities in Texas, alleging liability for injuries and damages arising from the event under a variety of legal theories. The plaintiffs have amended many of their petitions within the multidistrict litigation, and more than 100 of the cases now name Renewables entities among the defendants. Four of the consolidated cases have been designated as “bellwether” cases and are proceeding to resolve certain common issues of fact and law. In May 2022, the Renewables entities were part of a broader motion to dismiss by all generators in the bellwether cases in which they were named. These motions were argued on October 11, 2022. On January 27, 2023 the Court issued orders granting in part and denying in part the generators’ motion to dismiss. The Court’s order dismissed plaintiffs’ tortious interference and conspiracy claims, but allowed all other claims to proceed. The generators subsequently filed mandamus petitions with the Texas Courts of Appeal, seeking review of the lower court’s decision on the motions. On December 14, 2023, the Houston Court of Appeals dismissed all claims against generators in Texas arising out of the Texas Winter Event holding that the generator defendants (including the Renewables entities) have no legal duty to retail customers, and therefore the retail customers have no negligence causes of action against them. The plaintiffs have appealed the decision.
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Partnership with Navajo Tribal Utility Authority
In March 2023, Renewables and Navajo Tribal Utility Authority Generation, Inc., or NTUAG, a wholly-owned subsidiary of Navajo Tribal Utility Authority, or NTUA, signed a Memorandum of Understanding, or MoU, to jointly explore opportunities for developing up to 1 GW of renewable energy generation, including solar, wind, hydrogen and back-up battery storage, on the reservation of Navajo Nation located in portions of states of New Mexico, Utah and Arizona. Once built, that would constitute enough generation to supply clean energy to hundreds of thousands of homes and businesses, both on the reservation, and in regional markets through export to surrounding states. All projects built through the partnership would be joint ventures, with NTUA maintaining at least 51% majority ownership to retain tribal sovereignty and control.
Commonwealth Wind and Park City PPAs
In October 2022 Commonwealth Wind and Park City Wind announced that they would seek to re-negotiate the price of the certain Power Purchase Agreements, or PPAs, to help mitigate the impacts of inflation, increased interest rates and supply chain disruptions on the projects. Following DPU's approval of the Commonwealth Wind PPAs, motions filed with the DPU with respect to the suspension of the proceeding to review the PPAs and termination of the PPAs and appeal to the Supreme Judicial Court of Massachusetts of the DPU's approval order, each of the EDCs filed with the DPU a first amendment, termination agreement and release agreed with Commonwealth Wind, providing for an orderly termination of the PPAs, withdrawal or dismissal of Commonwealth Wind’s appeal, and payment by Commonwealth Wind of a $48 million termination payment to the EDCs an amount equal to the development period security provided for in the PPAs on July 13, 2023. The DPU approved the termination agreements on August 2, 2023 and Commonwealth Wind filed for a dismissal of its appeal of the DPU’s approval order.
On October 2, 2023, Park City Wind entered into a first amendment, termination agreement and release with each of the Connecticut EDCs, providing for an orderly termination of the Park City Wind PPAs and payment by Park City Wind of an approximately $16 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs. On October 13, 2023, PURA approved the termination agreements.
Results of Operations
The following table sets forth financial information by segment for each of the periods indicated.
  Year Ended December 31, 2023
  Total Networks Renewables Other(1)
  (in millions)
Operating Revenues $ 8,309  $ 6,855  $ 1,456  $ (2)
Operating Expenses
Purchased power, natural gas and fuel used 2,429  1,987  442  — 
Operations and maintenance 3,109  2,582  529  (2)
Depreciation and amortization 1,158  694  456  8 
Taxes other than income taxes 683  596  74  13 
Total Operating Expenses 7,379  5,859  1,501  19 
Operating Income 930  996  (45) (21)
Other Income (Expense)
Other income (expense) 129  146  24  (41)
Earnings (losses) from equity method investments 6  15  (9) — 
Interest expense, net of capitalization (409) (287) (16) (106)
Income Before Income Tax 656  870  (46) (168)
Income tax expense (benefit) (9) 141  (67) (83)
Net Income (Loss) 665  729  21  (85)
Net loss (income) attributable to noncontrolling interests 121  (3) 124  — 
Net Income (Loss) Attributable to Avangrid, Inc. $ 786  $ 726  $ 145  $ (85)
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  Year Ended December 31, 2022
  Total Networks Renewables Other(1)
 
 (in millions)
Operating Revenues $ 7,923  $ 6,782  $ 1,141  $ — 
Operating Expenses
Purchased power, natural gas and fuel used 2,456  2,295  161  — 
Operations and maintenance 2,872  2,338  526  8 
Depreciation and amortization 1,085  660  424  1 
Taxes other than income taxes 658  588  66  4 
Total Operating Expenses 7,071  5,881  1,177  13 
Operating Income 852  901  (36) (13)
Other Income (Expense)
Other income (expense) 30  33  10  (13)
Earnings (losses) from equity method investments 262  11  251  — 
Interest expense, net of capitalization (303) (220) (16) (67)
Income Before Income Tax 841  725  209  (93)
Income tax expense (benefit) 20  94  (114) 40 
Net Income (Loss) 821  631  323  (133)
Net loss (income) attributable to noncontrolling interests 60  (3) 63  — 
Net Income (Loss) Attributable to Avangrid, Inc. $ 881  $ 628  $ 386  $ (133)
  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 (Loss) 895  876  26  (7)
Other Income (Expense)
Other (expense) income 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 (Loss) 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)
(1)Other amounts represent Corporate and intersegment eliminations.
Comparison of Period to Period Results of Operations
Operating revenues increased by $386 million from $7,923 million for the year ended December 31, 2022, to $8,309 million for the year ended December 31, 2023.
Purchased power, natural gas and fuel used decreased by $27 million from $2,456 million for the year ended December 31, 2022, to $2,429 million for the year ended December 31, 2023.
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Operations and maintenance increased by $237 million from $2,872 million for the year ended December 31, 2022, to $3,109 million for the year ended December 31, 2023.
Details of the period to period comparison are described below at the segment level.
Year Ended December 31, 2023 Compared to the Year Ended December 31, 2022
Networks
Operating revenues for the year ended December 31, 2023 increased by $73 million from $6,782 million for the year ended December 31, 2022, to $6,855 million. Electricity and gas revenues increased by $311 million, primarily due to rate increases in New York effective October 12, 2023, offset by a $4 million unfavorable impact from deferrals mainly driven by unfavorable changes in net plant reconciliation due to delays in the meters' installation schedules in New York in the current period. Electricity and gas revenues changed due to the following items that have offsets within the income statement: a decrease of $308 million in purchased power and purchased gas (offset in purchased power) driven by lower average pricing in commodities in the period, offset by an increase of $74 million in flow through amortizations (offset in operating expenses).
Purchased power, natural gas and fuel used for the year ended December 31, 2023 decreased by $308 million from $2,295 million for the year ended December 31, 2022, to $1,987 million. The decrease is primarily driven by a $308 million decrease in average commodity prices and an overall decrease in electricity and gas units procured due to lower degree days in the period.
Operations and maintenance during the year ended December 31, 2023 increased by $244 million from $2,338 million for the year ended December 31, 2022, to $2,582 million. The increase is driven by increased business and corporate costs of $74 million, a $46 million increase in personnel expenses primarily driven by higher headcount and a $50 million increase in uncollectible expenses due to higher bad debt provision in the current period. In addition, there were increases of $74 million in flow-through amortizations (which is offset in revenue)
Renewables
Operating revenues for the year ended December 31, 2023 increased by $315 million from $1,141 million for the year ended December 31, 2022, to $1,456 million. The increase in operating revenues was primarily due to an increase of $123 million in favorable thermal and power trading due to wider spark spreads in the period primarily driven by weather, favorable MtM changes of $274 million on energy derivative transactions entered for economic hedging purposes, $6 million from the sale of assets, offset by a $83 million decrease in merchant prices driven by lower average prices in the current period and a $5 million decrease from production, including new assets in service and curtailment payments in the current period.
Purchased power, natural gas and fuel used for the year ended December 31, 2023 increased by $281 million from $161 million for the year ended December 31, 2022, to $442 million. The increase is primarily due to unfavorable MtM changes on derivatives of $253 million driven by market price changes in the period and an increase of $28 million in power and gas purchases due to higher average prices in the current period driven by weather.
Operations and maintenance for the year ended December 31, 2023 increased by $3 million from $526 million for the year ended December 31, 2022, to $529 million. The increase is primarily due to a $16 million increase in connection with an offshore contract provision compared to the same period of 2022, a $6 million increase driven by the write-off of certain development projects and $5 million higher corporate charges in the current period, offset by a $24 million decrease in the bad debt provision in the current period driven by lower uncollectibles billed arising from the weather event in the PJM market in 2022.
Depreciation, Amortization and Impairment
Depreciation, amortization and impairment expenses for the year ended December 31, 2023 increased by $73 million from $1,085 million for the year ended December 31, 2022, to $1,158 million. The increase is primarily driven by $66 million from plant additions in Networks and Renewables and $7 million in Other in the current period.
Other Income and (Expense) and Equity Earnings
Other income and (expense) and equity earnings for the year ended December 31, 2023 decreased by $157 million from $292 million for the year ended December 31, 2022, to $135 million. The decrease is primarily due to $256 million of unfavorable equity earnings, driven by a $246 million gain recognized in 2022 from the offshore joint venture restructuring transaction in Renewables, offset by a $80 million favorable change in non-service component of pension expense driven by revised actuarial studies (which is partially offset within revenue) and a $19 million increase in allowance for funds used during construction in Networks primarily driven by the NECEC project construction resumed in 2023.
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Interest Expense, Net of Capitalization
Interest expense for the year ended December 31, 2023 increased by $106 million from $303 million for the year ended December 31, 2022, to $409 million. The change is primarily due to an increase of $27 million in carrying charges on regulatory deferrals and $32 million due to increased debt in the period at Networks and a $110 million increase in Other mainly driven by increased outstanding balances on commercial paper and the intragroup loan and unfavorable changes in the fair value hedges in the current period, offset by $63 million of capitalized interest driven by higher interest rates in the period.
Income Tax Expense
The effective tax rate, inclusive of federal and state income tax, for the year ended December 31, 2023 was (1.4)%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, Tax Act excess deferred tax amortization, state tax benefit, the equity component of allowance for funds used during construction and other property related flow through items, partially offset by tax equity financing impacts. The effective tax rate, inclusive of federal and state income tax, for the year ended December 31, 2022, was 2.4%, primarily due to the recognition of production tax credits, Tax Act excess deferred tax amortization, the equity component of allowance for funds used during construction, and the release of our federal valuation allowance in 2022 as a result of the Inflation Reduction Act enacted in August 2022 that will permit us to utilize tax attributes that were previously expected to expire.
Year Ended December 31, 2022 Compared to the Year Ended December 31, 2021
Networks
Operating revenues for the year ended December 31, 2022 increased by $1,028 million from $5,754 million for the year ended December 31, 2021, to $6,782 million. Electricity and gas revenues increased by $116 million, primarily due to rate increases in New York effective December 1, 2020, $10 million increase in late payment fees, and a favorable $16 million of other various deferrals primarily driven by sales use tax payments in the period. Electricity and gas revenues changed due to the following items that have offsets within the income statement: an increase of $806 million in purchased power and purchased gas (offset in purchased power) driven by higher average pricing in commodities in the period, a $25 million increase from deferral of pension settlement charges (offset in other income) as a result of freezing of pension benefit accruals and contribution credits for non-union employees in 2022 and an increase of $55 million in flow through amortizations (offset in operating expenses).
Purchased power, natural gas and fuel used for the year ended December 31, 2022 increased by $806 million, from $1,489 million for the year ended December 31, 2021, to $2,295 million. The increase is primarily driven by a $806 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, 2022 increased by $140 million from $2,198 million for the year ended December 31, 2021, to $2,338 million. The increase is driven by increased business costs of $41 million, an increase of $27 million in uncollectible expenses driven primarily by higher bad debt provisions in New York, and a $17 million increase in personnel expenses primarily driven by higher headcount in the period. In addition, there were increases of $55 million in flow-through amortizations (which is offset in revenue).
Renewables
Operating revenues for the year ended December 31, 2022 decreased by $79 million from $1,220 million for the year ended December 31, 2021, to $1,141 million. The decrease in operating revenues was primarily due to a $128 million decrease in merchant prices driven mainly by lower demand as compared to the same period of 2021 when demand was higher during the Texas storm, $15 million from the sale of assets in 2021 and unfavorable MtM changes of $5 million on energy derivative transactions entered for economic hedging purposes, offset by $42 million in favorable thermal and power trading driven by higher average prices in the period, a $24 million increase driven by higher demand during the weather event in the PJM market and $3 million from production, including new assets in service and curtailment payments in the current period.
Purchased power, natural gas and fuel used for the year ended December 31, 2022 decreased by $69 million from $230 million for the year ended December 31, 2021, to $161 million. The decrease is primarily due to a decrease of $11 million in power and gas purchases due to lower average prices in 2022 compared to 2021 and favorable MtM changes on derivatives of $58 million driven by market price changes in the period.
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Operations and maintenance for the year ended December 31, 2022 increased by $31 million from $495 million for the year ended December 31, 2021, to $526 million. The increase is primarily due to a $13 million increase in the bad debt provision driven mainly by provisions during the weather event in the PJM market in 2022, a $24 million increase in connection with an offshore contract provision, a $13 million increase in personnel costs driven primarily by increase in headcount in the period, $9 million increase in other operating costs primarily driven by an increase in corporate charges in the period, and $5 million driven by settlement of liquidated damage claims recorded in 2021, offset by a decrease of $33 million primarily driven by the write-off of certain development projects in the same period of 2021.
Depreciation, Amortization and Impairment
Depreciation, amortization and impairment expenses for the year ended December 31, 2022 increased by $71 million from $1,014 million for the year ended December 31, 2021, to $1,085 million. The increase is driven by $65 million from plant additions in Networks and Renewables in the period and $6 million increase driven by amortization of a deferred gain recorded in 2021.
Other Income and (Expense) and Equity Earnings
Other income and (expense) and equity earnings for the year ended December 31, 2022 increased by $225 million from $67 million for the year ended December 31, 2021, to $292 million. The increase is primarily due to a $246 million gain recognized in 2022 from the offshore joint venture restructuring transaction in Renewables, offset by a $21 million unfavorable change in the non-service component of pension expense driven by revised actuarial studies in Networks (which is partially offset within revenue).
Interest Expense, Net of Capitalization
Interest expense for the year ended December 31, 2022 decreased by $5 million from $298 million for the year ended December 31, 2021, to $303 million. The change is primarily due to an increase of $2 million of interest expense at Networks (unfavorable $11 million interest expense from increased debt, offset by $5 million of favorable carrying charges and $4 million favorable regulatory amortizations primarily driven by lower regulatory deferrals from the rate case in New York that was approved November 19, 2020) and a $4 million increase in Other mainly driven by increased outstanding balances on commercial papers.
Income Tax Expense
The effective tax rate, inclusive of federal and state income tax, for the year ended December 31, 2022 was 2.4%, which is below the federal statutory tax rate of 21%, primarily due to the recognition of production tax credits, Tax Act excess deferred tax amortization, the equity component of allowance for funds used during construction, and the release of our federal valuation allowance in 2022 as a result of the Inflation Reduction Act enacted in August 2022 that will permit us to utilize tax attributes that were previously expected to expire. 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, Tax Act excess deferred tax amortization and the equity component of allowance for funds used during construction.
Non-GAAP Financial Measures
To supplement our consolidated financial statements presented in accordance with U.S. GAAP, we consider adjusted net income and adjusted earnings per share, adjusted EBITDA and adjusted EBITDA with Tax Credits as financial measures that are not prepared in accordance with U.S. GAAP. The non-GAAP financial measures we use are specific to Avangrid and the non-GAAP financial measures of other companies may not be calculated in the same manner. We use these non-GAAP financial measures, in addition to U.S. GAAP measures, to establish operating budgets and operational goals to manage and monitor our business, evaluate our operating and financial performance and to compare such performance to prior periods and to the performance of our competitors. We believe that presenting such non-GAAP financial measures is useful because such measures can be used to analyze and compare profitability between companies and industries by eliminating the impact of certain non-cash charges. In addition, we present non-GAAP financial measures because we believe that they and other similar measures are widely used by certain investors, securities analysts and other interested parties as supplemental measures of performance.
We define adjusted net income as net income adjusted to exclude mark-to-market earnings from changes in the fair value of derivative instruments, costs incurred in connection with the COVID-19 pandemic, costs incurred related to the PNMR Merger and other transactions, accelerated depreciation from the repowering of wind farms, and costs incurred in connection with an offshore contract provision. 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.
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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, 2023, 2022 and 2021, respectively:
  Year Ended December 31, 2023
  Total Networks Renewables Corporate *
  (in millions)
Net Income Attributable to Avangrid, Inc. $ 786  $ 726  $ 145  $ (85)
Adjustments:
Mark-to-market adjustments - Renewables (21) —  (21) — 
Merger and other transaction costs 11  1  6  3 
Offshore contract provision 40  —  40  — 
Accelerated depreciation from repowering 1  —  1  — 
Income tax impact of adjustments (1) (8) —  (7) (1)
Adjusted Net Income (2) $ 808  $ 727  $ 163  $ (82)
Net (loss) income attributable to noncontrolling interests (121) 3  (124) — 
Income tax (benefit) expense (1) 141  (60) (82)
Depreciation and amortization 1,158  694  456  8 
Interest expense, net of capitalization 409  287  16  106 
Other (income) expense (129) (146) (24) 41 
Losses (earnings) from equity method investments (6) (15) 9  — 
Adjusted EBITDA (3) $ 2,118  $ 1,691  $ 436  $ (9)
Retained PTCs and ITCs 162  —  162  — 
PTCs allocated to tax equity investors 150  —  150  — 
Adjusted EBITDA with Tax Credits (3) $ 2,430  $ 1,691  $ 749  $ (9)
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Year Ended December 31, 2022
Total Networks Renewables Corporate *
(in millions)
Net Income Attributable to Avangrid, Inc. $ 881  $ 628  $ 386  $ (133)
Adjustments:
Mark-to-market adjustments - Renewables —  —  —  — 
Impact of COVID-19 —  —  —  — 
Merger and other transaction costs 4  —  —  4 
Offshore contract provision 24  —  24  — 
Accelerated depreciation from repowering —  —  —  — 
Income tax impact of adjustments (1) (7) —  (6) (1)
Adjusted Net Income (2) $ 901  $ 628  $ 403  $ (130)
Net (loss) income attributable to noncontrolling interests (60) 3  (63) — 
Income tax (benefit) expense 27  94  (108) 41 
Depreciation and amortization 1,085  660  424  1 
Interest expense, net of capitalization 303  220  16  67 
Other (income) expense (30) (33) (10) 13 
Losses (earnings) from equity method investments (262) (11) (251) — 
Adjusted EBITDA (3) $ 1,964  $ 1,561  $ 411  $ (8)
Retained PTCs and ITCs 162  —  162  — 
PTCs allocated to tax equity investors 119  —  119  — 
Adjusted EBITDA with Tax Credits (3) $ 2,246  $ 1,561  $ 693  $ (8)
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Year Ended December 31, 2021
Total Networks Renewables Corporate *
(in millions)
Net Income (Loss) Attributable to Avangrid, Inc. $ 707  $ 636  $ 131  $ (60)
Adjustments:
Mark-to-market adjustments - Renewables 53  —  53  — 
Impact of COVID-19 34  34  —  — 
Merger and other transaction costs 12  —  —  12 
Offshore contract provision —  —  —  — 
Accelerated depreciation from repowering —  —  —  — 
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 
(1)Income tax impact of adjustments: For the year ended December 31, 2023, $6 million from MtM adjustment, $(3) million from merger and other transaction costs and $(11) million from an offshore contract provision. For the year ended December 31, 2022, $(6) million from an offshore contract provision and $(1) million from merger and other transaction costs. For the year ended December 31, 2021, $14 million from MtM adjustment, $9 million from COVID-19 impacts and $3 million from merger and other transaction costs.
(2)Adjusted Net Income is a non-GAAP financial measure and is presented after excluding MtM activities in Renewables, costs incurred related to the PNMR Merger and other transactions, accelerated depreciation from the repowering of wind farms, an offshore contract provision 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, 2023 Compared to the Year Ended December 31, 2022
Adjusted net income
Adjusted net income decreased by $93 million from $901 million for the year ended December 31, 2022 to $808 million for the year ended December 31, 2023. The decrease is primarily due to a $240 million decrease in Renewables driven by a gain recognized in 2022 from the offshore joint venture restructuring transaction, offset by a $99 million increase in Networks driven primarily by rate increases in New York effective October 12, 2023 and a $48 million increase in Corporate mainly driven by a tax benefit from unitary state tax changes in the period.
Year Ended December 31, 2022 Compared to the Year Ended December 31, 2021
Adjusted net income
Adjusted net income increased by $121 million from $780 million for the year ended December 31, 2021 to $901 million for the year ended December 31, 2022. The increase is primarily due to a $233 million increase in Renewables driven by a gain recognized in 2022 from the offshore joint venture restructuring transaction and favorable tax expense from valuation allowances and state tax rate changes which are primarily offset in Corporate, offset by a $33 million decrease in Networks driven primarily by higher business costs and uncollectible expenses in the period, $79 million decrease in Corporate mainly driven by unfavorable tax expense from unitary rate changes in the period which are primarily offset in Renewables.
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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, 2023, 2022 and 2021, respectively:
Year Ended December 31,
2023 2022 2021
(in millions)
Networks $ 726  $ 628  $ 636 
Renewables 145  386  131 
Corporate (1) (85) (133) (60)
Net Income 786  881  707 
Adjustments:
Mark-to-market adjustments - Renewables (2) (21) —  53 
Impact of COVID-19 (3) —  —  34 
Merger and other transaction costs (4) 11  4  12 
Offshore contract provision (5) 40  24  — 
Accelerated depreciation from repowering (6) 1  —  — 
Income tax impact of adjustments (8) (7) (26)
Adjusted Net Income (7) $ 808  $ 901  $ 780 
Year Ended December 31,
2023 2022 2021
Networks $ 1.88  $ 1.62  $ 1.78 
Renewables 0.37  1.00  0.37 
Corporate (1) (0.22) (0.34) (0.17)
Earnings Per Share 2.03  2.28  1.97 
Adjustments:
Mark-to-market adjustments - Renewables (2) (0.06) —  0.15 
Impact of COVID-19 (3) —  —  0.10 
Merger and other transaction costs (4) 0.03  0.01  0.03 
Offshore contract provision (5) 0.10  0.06  — 
Accelerated depreciation from repowering (6) —  —  — 
Income tax impact of adjustments (0.02) (0.02) (0.07)
Adjusted Earnings Per Share (7) $ 2.09  $ 2.33  $ 2.18 
(1)Includes corporate and other non-regulated entities as well as intersegment eliminations.
(2)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.
(3)Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions.
(4)Pre-merger and other transaction costs incurred.
(5)Costs incurred in connection with an offshore contract provision.
(6)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.
(7)Adjusted Net Income and Adjusted Earnings Per Share are non-GAAP financial measures and are presented after excluding MtM activities in Renewables, costs incurred related to the PNMR Merger and other transactions, accelerated depreciation from the repowering of wind farms, an offshore contract provision 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 sources of liquidity and capital are critical to us. Risks may increase due to circumstances beyond our control, such as a general disruption of the financial markets and adverse economic conditions.
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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. These arrangements minimize overall short-term funding costs and maximize returns on the temporary cash investments of the subsidiaries. At December 31, 2023, we had cash and cash equivalents of $91 million, as compared to $69 million at December 31, 2022. We have the capacity to borrow up to $3,575 million from the lenders committed to the Avangrid Credit Facility 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, 2023 and February 21, 2024, there was $1,332 million and $1,906 million, respectively, of commercial paper outstanding, presented net of discounts on the balance sheet. As of December 31, 2023, the weighted-average interest rate on outstanding commercial paper was 5.65%.
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.
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. On July 17, 2023, the Avangrid Credit Facility was amended and restated to, among other things, provide for the replacement of LIBOR-based rates with SOFR-based rates and remove provisions related to the extension of credit to the Public Service Company of New Mexico and Texas-New Mexico Power Company. As of both December 31, 2023 and February 21, 2024, 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, 2023 and February 21, 2024, was $2,233 million and $1,656 million, respectively.
Iberdrola Group Credit Facility
On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of December 31, 2023 and February 21, 2024, there was $0 and $100 million outstanding amount under this credit facility, respectively.
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, 2023 and 2022, the amount of notes payable under supplier financing arrangements was $0 and $171 million, respectively. For the period ended December 31, 2023, $175 million of confirmed invoices were paid under the program. As of December 31, 2022, the weighted average interest rate on the balance was 5.48%.
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.
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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, 2023 and 2022, 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, 2023, we had approximately $2,188 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, 2023, 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.
Our long-term debt issuances during 2023 were as follows:
Company Issue Date Type Amount (Millions) Interest rate Maturity
NYSEG 7/3/2023 Tax Exempt Bond $ 100 
4.00%
 2034
UI 10/2/2023 Tax Exempt Bond $ 64 
4.50%
 2033
NYSEG 8/8/2023 Green 144A Bond $ 350 
5.65%
 2028
NYSEG 8/8/2023 Green 144A Bond $ 400 
5.85%
 2033
RG&E 12/13/2023 Green Private Bond $ 100 
5.62%
 2028
RG&E 12/13/2023 Green Private Bond $ 25 
5.89%
 2034
RG&E 12/13/2023 Green Private Bond $ 50 
5.99%
 2036
RG&E 12/13/2023 Green Private Bond $ 75 
6.22%
 2053
CMP 12/13/2023 Green Private Bond $ 55 
5.65%
 2029
CMP 12/13/2023 Green Private Bond $ 70 
6.04%
 2038
UI 12/13/2023 Green Private Bond $ 156 
6.09%
 2034
UI 12/13/2023 Green Private Bond $ 34 
6.29%
 2038
CNG 12/13/2023 Private Bond $ 36 
6.20%
 2032
CNG 12/13/2023 Private Bond $ 19 
6.49%
 2038
SCG 12/13/2023 Private Bond $ 30 
6.04%
 2034
SCG 12/13/2023 Private Bond $ 30 
6.24%
 2038
Corporate 7/19/2023 Intragroup Green Loan $ 800 
5.45%
 2033

At December 31, 2023, Networks had $7,791 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.
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Networks’ regulated utilities were in compliance with these regulatory orders as of December 31, 2023.
At December 31, 2023, we had a $39 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 April 29, 2022, we closed on a TEF agreement, receiving $14 million from a tax equity investor related to the Lund Hill solar farm that reached partial mechanical completion on the same date. In March 2023 we received additional investment from our investor in the amount of $61 million. Lund Hill is owned by Solis Solar Power I, LLC (Solis I). In November 2023, we received additional funding of $124 million from tax equity investor related to Aeolus VIII.
At December 31, 2023, Corporate had $2,805 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, 750 million of 3.80% notes due in 2029 and $800 million of 5.45% intragroup loan due in 2033.
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, 2023 and throughout 2023.
Intragroup Green Loan
On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., an affiliate of Iberdrola, with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan).
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. 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:
  2023 2022 2021
  (in millions)
NYSEG $ 852  $ 759  $ 743 
RG&E 410  374  394 
CMP* 554  338  682 
UI 264  226  186 
SCG 111  101  86 
CNG 74  66  63 
BGC 32  22  17 
MNG 2  3  4 
Corporate 8  23  55 
Total $ 2,307  $ 1,912  $ 2,230 
*Includes NECEC Transmission LLC’s capital expenditures in the NECEC project.
Networks continued its capital expenditures during 2023 to upgrade and expand electricity and natural gas transmission and distribution infrastructure. In 2023, we continued capital investments in a number of programs in Maine, New York and Connecticut, including substation modernization, storm resiliency program grid automation, new transmission investments, pole replacement programs, projects related to improvement of system operations, reliability and resiliency, replacement of aging infrastructure, and new customer connections.
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Renewables’ capital expenditures for the years set forth below were as follows:
  2023 2022 2021
  (in millions)
Wind & solar $ 477  $ 662  $ 928 
Thermal 13  28  18 
Corporate (1) 17  13  12 
Other capitalized costs (2) 256  83  106 
Total capital expenditures $ 763  $ 786  $ 1,064 
(1)Includes information technology and facilities and safety (security).
(2)Includes capitalized interest, labor and other costs.
In 2023, Renewables made capital expenditures of $477 million on construction of True North Solar, Powell Creek Solar, Lund Hill Solar, Bakeoven Solar, Montague Solar, Midland, and other wind and solar assets and $13 million in capital expenditures on the Klamath gas-fired cogeneration facility, or the Klamath Plant, along with other capitalized costs incurred on wind and solar assets.
Capital Projects
An important part of our business strategy involves capital projects. Networks plans to invest a total of approximately $13 billion from 2024 to 2028 to upgrade and expand electricity and natural gas transmission and distribution infrastructure. In the next 12 months, Networks plans to invest $413 million in Maine, including Distribution Line Inspection Repairs Program, Transmission Line Asset Condition Replacements Program, Substation Modernization Program, Storm Resiliency Program and Grid Automation. NECEC plans to invest $644 million in the next 12 months. NYSEG plans to invest $1 billion 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, CLCPA Transmission Projects, Storm Resiliency Program, Make Ready, Pole Replacement Program and Gas Distribution Mains and Leak Prone Main replacements. RG&E plans to invest $422 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 $472 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.
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, 2023, 2022 and 2021, respectively:
  Year Ended December 31,
  2023 2022 2021
  (in millions)
Cash Flows      
Net cash provided by operating activities $ 919  $ 1,035  $ 1,561 
Net cash used in investing activities (3,099) (2,548) (2,440)
Net cash provided by financing activities 2,202  108  889 
Net increase (decrease) in cash, cash equivalents and restricted cash $ 22  $ (1,405) $ 10 
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, 2023 compared to the year ended December 31, 2022 decreased by $116 million, primarily attributable to a net decrease in current assets and liabilities driven by timing of cash collections and cash disbursements, and higher interest payments during the period.
The cash from operating activities for the year ended December 31, 2022 compared to the year ended December 31, 2021 decreased by $526 million, primarily attributable to a net decrease in current assets and liabilities driven by timing of cash collections and cash disbursements during the period.
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.
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 2023, net cash used in investing activities was $3,099 million, which primarily was comprised of $2,972 million of capital expenditures and $287 million of capital contributions to the offshore joint venture, partially offset by $112 million of contributions in aid of construction.
In 2022, net cash used in investing activities was $2,548 million, which primarily was comprised of $2,519 million of capital expenditures and $168 million of payment for the offshore joint venture restructuring transaction, partially offset by $123 million of contributions in aid of construction.
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.
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 2023, financing activities provided $2,202 million in cash reflecting primarily a net increase in non-current debt and current notes payable of $2,705 million and contribution from non-controlling interests of $203 million in the period, offset by distributions to non-controlling interests of $16 million and dividends of $681 million.
In 2022, financing activities provided $108 million in cash reflecting primarily a net increase in non-current debt and current notes payable of $662 million and contribution from non-controlling interests of $147 million in the period, offset by distributions to non-controlling interests of $10 million and dividends of $681 million.
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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.
Contractual Obligations
As of December 31, 2023, our contractual obligations (excluding any tax reserves) were as follows:
  Total 2024 2025 2026 2027 2028 Thereafter
  (in millions)
Leases (1) $ 436  $ 51  $ 25  $ 26  $ 29  $ 35  $ 271 
Easements (2) 1,105  29  32  32  31  33  948 
Projected future pension benefit plan contributions (3) 239  36  19  46  33  29  76 
Long-term debt (including current maturities) (4) 10,596  612  1,107  660  484  716  7,017 
Interest payments (5) 4,684  436  414  415  373  350  2,696 
Material purchase commitments (6) 1,909  1,484  214  84  52  18  57 
Total Contractual Obligations $ 18,969  $ 2,648  $ 1,811  $ 1,263  $ 1,001  $ 1,181  $ 11,065 
(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 Security 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.
(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, 2023, 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, 2023.
(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, 2023.
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 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.
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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, 2023, 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 rate used in accounting for qualified pension obligations in 2023 was 5.18%, representing an increase of 233 basis points from 2022. The expected rate of return on plan assets for qualified pension benefits in 2023 was 6.35%, representing an increase of 2 basis points from 2022. 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 2023 Pension Expense Increase (Decrease)
Change in Assumption Pension Benefits Post Retirement Benefits
(in millions)
Increase in discount rate 50 basis points $ (12) $ (1)
Decrease in discount rate 50 basis points $ 12  $ 1 
Increase in return on plan assets 50 basis points $ (11) $ — 
Decrease in return on plan assets 50 basis points $ 11  $ — 
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 judgments, 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 judgment in the valuation process.
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.
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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 2023, 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.
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.
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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 judgments and estimates of the timing and probability of recognition of income and deductions by taxing authorities. In making these judgments, 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 judgment to determine when a tax position reaches this threshold.
Our assessment regarding the realizability of deferred tax assets involves judgments 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. Further information regarding derivative financial instruments and hedging activities is provided in Notes 11 and 12 of our consolidated financial statements contained in this Annual Report on Form 10-K.
Renewables merchant wind facilities are subject to price risk, which is hedged with fixed price power trades and gas 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 2023 was $11.4 million compared to a 2022 average of $13.6 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 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.
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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 $11,928 million at December 31, 2023, of which $2,082 million had a floating interest rate. A change of 25 basis points in this interest rate would result in an interest expense or income fluctuation of approximately $3 million annually. The estimated fair value of our long-term debt at December 31, 2023 was $10,266 million, in comparison to a book value of $10,596 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.
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, 2023, approximately 97% 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 $750 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 $39 million at December 31, 2023.
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 2023, Renewables recorded a net non-cash dividend of $453 million to Avangrid, Inc. to zero out account balances that had principally accumulated prior to January 2023.
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Item 8. Financial Statements and Supplementary Data

78

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, 2023 and 2022, 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, 2023, and the related notes and financial statement schedule 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, 2023 and 2022, and the results of its operations and its cash flows for each of the years in the three-year period ended December 31, 2023, 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, 2023, 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 22, 2024 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, 2023 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.
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.
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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 power production and forecasted market prices by comparing them to third-party published reports published 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.
/s/ KPMG LLP 

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

New York, New York
February 22, 2024
80

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, 2023, 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, 2023, 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, 2023 and 2022, 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, 2023, and the related notes and financial statement schedule I (collectively, the consolidated financial statements), and our report dated February 22, 2024 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 22, 2024
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Avangrid, Inc. and Subsidiaries
Consolidated Statements of Income
Years Ended December 31, 2023 2022 2021
(Millions, except for number of shares and per share data)      
Operating Revenues $ 8,309  $ 7,923  $ 6,974 
Operating Expenses
Purchased power, natural gas and fuel used 2,429  2,456  1,719 
Operations and maintenance 3,109  2,872  2,706 
Depreciation and amortization 1,158  1,085  1,014 
Taxes other than income taxes, net 683  658  640 
Total Operating Expenses 7,379  7,071  6,079 
Operating Income 930  852  895 
Other Income and (Expense)
Other income 129  30  60 
Earnings from equity method investments 6  262  7 
Interest expense, net of capitalization (409) (303) (298)
Income Before Income Tax 656  841  664 
Income tax (benefit) expense (9) 20  21 
Net Income 665  821  643 
Net loss attributable to noncontrolling interests 121  60  64 
Net Income Attributable to Avangrid, Inc. $ 786  $ 881  $ 707 
Earnings Per Common Share, Basic: $ 2.03  $ 2.28  $ 1.97 
Earnings Per Common Share, Diluted: $ 2.03  $ 2.27  $ 1.97 
Weighted-average Number of Common Shares Outstanding:
Basic 386,810,088  386,727,246  358,086,621 
Diluted 387,164,874  387,215,785  358,578,608 
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, 2023 2022 2021
(Millions)      
Net Income $ 665  $ 821  $ 643 
Other Comprehensive Income
Gain for defined benefit plans, net of income taxes of $0, $3 and $0, respectively
—  14  2 
Amortization of pension cost, net of income taxes of $0, $1 and $(1), respectively
(1) 4  (8)
Unrealized gain (loss) from equity method investment, net of income taxes of $1, $6 and $(3), respectively
 5  22  (9)
Unrealized gain (loss) during the year on derivatives qualifying as cash flow hedges, net of income taxes of $6, $0 and $(44), respectively
 17  (1) (159)
Reclassification to net income of losses on cash flow hedges, net of income taxes of $48, $19 and $(3), respectively
 134  54  12 
Other Comprehensive Income (Loss) 155  93  (162)
Comprehensive Income 820  914  481 
Net loss attributable to noncontrolling interests 121  60  64 
Comprehensive Income Attributable to Avangrid, Inc. $ 941  $ 974  $ 545 
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, 2023 2022
(Millions)    
Assets    
Current Assets    
Cash and cash equivalents $ 91  $ 69 
Accounts receivable and unbilled revenues, net 1,588  1,737 
Accounts receivable from affiliates 11  5 
Notes receivable from affiliates 4  3 
Derivative assets 68  60 
Fuel and gas in storage 185  268 
Materials and supplies 310  235 
Prepayments and other current assets 429  386 
Regulatory assets 718  447 
Total Current Assets 3,404  3,210 
Total Property, Plant and Equipment ($2,643 and $2,707 related to VIEs, respectively)
 32,857  30,994 
Operating lease right-of-use assets 195  159 
Equity method investments 718  437 
Other investments 46  49 
Regulatory assets 2,811  2,321 
Other Assets
Goodwill 3,119  3,119 
Intangible assets 284  281 
Derivative assets 162  140 
Other 393  413 
Total Other Assets 3,958  3,953 
Total Assets $ 43,989  $ 41,123 
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, 2023 2022
(Millions, except share information)    
Liabilities    
Current Liabilities    
Current portion of debt $ 612  $ 412 
Notes payable 1,347  566 
Notes payable to affiliate 13  2 
Interest accrued 104  66 
Accounts payable and accrued liabilities 1,924  2,007 
Accounts payable to affiliates —  39 
Dividends payable 170  170 
Taxes accrued 66  61 
Operating lease liabilities 16  13 
Derivative liabilities 64  133 
Other current liabilities 662  593 
Regulatory liabilities 261  354 
Total Current Liabilities 5,239  4,416 
Regulatory liabilities 2,694  2,915 
Other Non-current Liabilities    
Deferred income taxes 2,451  2,234 
Deferred income 996  1,062 
Pension and other postretirement 554  491 
Operating lease liabilities 199  161 
Derivative liabilities 111  164 
Asset retirement obligations 306  273 
Environmental remediation costs 254  279 
Other 525  563 
Total Other Non-current Liabilities 5,396  5,227 
Non-current debt 9,184  8,215 
Non-current debt to affiliate 800  8 
Total Non-current Liabilities 18,074  16,365 
Total Liabilities 23,313  20,781 
Commitments and Contingencies —  — 
Equity    
Stockholders' Equity:    
Common stock, $.01 par value, 500,000,000 shares authorized, 387,872,787 and 387,734,757 shares issued; 386,770,915 and 386,628,586 shares outstanding, respectively
 4  3 
Additional paid-in capital 17,701  17,694 
Treasury stock (47) (47)
Retained earnings 2,015  1,910 
Accumulated other comprehensive loss (25) (180)
Total Stockholders’ Equity 19,648  19,380 
Noncontrolling interests 1,028  962 
Total Equity 20,676  20,342 
Total Liabilities and Equity $ 43,989  $ 41,123 
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The accompanying notes are an integral part of our consolidated financial statements.
86

Avangrid, Inc. and Subsidiaries
Consolidated Statements of Cash Flows
Years Ended December 31, 2023 2022 2021
(Millions)      
Cash Flow from Operating Activities      
Net income $ 665  $ 821  $ 643 
Adjustments to reconcile net income to net cash provided by operating activities
Depreciation and amortization 1,158  1,085  1,014 
Accretion expenses 15  14  12 
Regulatory assets/liabilities amortization and carrying cost (39) (65) (72)
Pension cost (13) 11  52 
Earnings from equity method investments (6) (262) (7)
Distribution of earnings from equity method investments 28  23  17 
Unrealized (gains) losses on marked to market derivative contracts (21) —  86 
Loss from divestment and disposal of property 5  2  24 
Deferred taxes 44  18  11 
Other non-cash items (87) (48) (82)
Changes in operating assets and liabilities:      
Current assets (162) (837) (275)
Noncurrent assets (401) (123) (45)
Current liabilities (147) 385  286 
Noncurrent liabilities (120) 11  (103)
Net Cash Provided by Operating Activities 919  1,035  1,561 
Cash Flow from Investing Activities      
Capital expenditures (2,972) (2,519) (2,976)
Contributions in aid of construction 112  123  130 
Proceeds from sale of property, plant and equipment 65  31  24 
(Payments to) receipts from affiliates —  (3) 5 
Cash distribution from equity method investments 4  18  155 
Other investments and equity method investments, net (308) (198) 222 
Net Cash Used in Investing Activities (3,099) (2,548) (2,440)
Cash Flow from Financing Activities      
Non-current debt issuances 1,515  791  833 
Non-current debt issuance with affiliate 800  —  — 
Repayments of non-current debt (378) (365) (304)
Repayment of non-current debt with affiliate —  —  (3,000)
Receipts (Repayments) of other short-term debt, net 768  236  (306)
Repayments of financing leases (6) (9) (6)
Repurchase of common stock —  —  (33)
Issuance of common stock (3) (1) 3,998 
Distributions to noncontrolling interests (16) (10) (10)
Contributions from noncontrolling interests 203  147  330 
Dividends paid (681) (681) (613)
Net Cash Provided by Financing Activities 2,202  108  889 
Net Increase (Decrease) in Cash, Cash Equivalents and Restricted Cash 22  (1,405) 10 
Cash, Cash Equivalents and Restricted Cash, Beginning of Year 72  1,477  1,467 
Cash, Cash Equivalents and Restricted Cash, End of Year $ 94  $ 72  $ 1,477 
Supplemental Cash Flow Information
Cash paid for interest, net of amounts capitalized $ 338  $ 273  $ 279 
Cash (refund) paid for income taxes, net of transferred tax credits (Note 16) $ (40) $ 15  $ 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, 2020 309,077,300  $ 3  $ 13,665  $ (14) $ 1,666  $ (111) $ 15,209  $ 617  $ 15,826 
Net income —  —  —  —  707  —  707  (64) 643 
Other comprehensive loss, 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 
Net income —  —  —  —  881  —  881  (60) 821 
Other comprehensive income, net of tax of $29
 —  —  —  —  —  93  93  —  93 
Comprehensive income 914 
Dividends declared, $1.76/share
 —  —  —  —  (681) —  (681) —  (681)
Release of common stock held in trust 4,355  —  —  —  —  —  —  —  — 
Issuance of common stock 56,127  —  (1) —  —  —  (1) —  (1)
Repurchase of common stock —  —  —  —  —  —  —  —  — 
Stock-based compensation —  —  16  —  —  —  16  —  16 
Distributions to noncontrolling interests —  —  —  —  —  —  —  (10) (10)
Contributions from noncontrolling interests —  —  —  —  (4) —  (4) 147  143 
Balances, December 31, 2022 386,628,586  3  17,694  (47) 1,910  (180) 19,380  962  20,342 
Net income —  —  —  —  786  —  786  (121) 665 
Other comprehensive income, net of tax of $55
 —  —  —  —  —  155  155  —  155 
Comprehensive income 820 
Dividends declared, $1.76/share
 —  —  —  —  (681) —  (681) —  (681)
Release of common stock held in trust 4,299  —  —  —  —  —  —  —  — 
Issuance of common stock 138,030  1  (4) —  —  —  (3) —  (3)
Stock-based compensation —  —  11  —  —  —  11  —  11 
Distributions to noncontrolling interests —  —  —  —  —  —  —  (16) (16)
Contributions from noncontrolling interests —  —  —  —  —  —  —  203  203 
Balances, December 31, 2023 386,770,915  $ 4  $ 17,701  $ (47) $ 2,015  $ (25) $ 19,648  $ 1,028  $ 20,676 
(*) 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 14.7% of Avangrid's outstanding shares publicly-traded on the New York Stock Exchange (NYSE).
Termination of a Material Definitive Agreement
On December 31, 2023, Avangrid sent a notice to PNM Resources, Inc., a New Mexico corporation (PNMR), terminating the previously announced Agreement and Plan of Merger (as amended by the Amendment to Merger Agreement dated January 3, 2022, Amendment No. 2 to the Merger Agreement dated April 12, 2023 and Amendment No. 3 to the Merger Agreement dated June 19, 2023 (Merger Agreement)), pursuant to which NM Green Holdings, Inc. a New Mexico corporation and wholly-owned subsidiary of the corporation (Merger Sub), agreed to merge with and into PNMR (Merger), with PNMR surviving the Merger as a direct wholly-owned subsidiary of Avangrid. A description of the Merger Agreement was included in the Current Reports on Form 8-K filed by Avangrid on October 21, 2020, January 3, 2022, April 12, 2023 and June 20, 2023, and is incorporated herein by reference.
The Merger was conditioned, among other things, upon the receipt of certain required regulatory approvals, including the approval of the New Mexico Public Regulation Commission (NMPRC), and provided that the Merger Agreement may be terminated by either Avangrid or PNMR if the closing of the Merger shall not have occurred by 5:00 PM New York City Time on December 31, 2023 (End Date). Because the required approval of the NMPRC was not received by the End Date and the conditions to the closing of the Merger were thus not satisfied by the End Date, Avangrid exercised its right to terminate the Merger Agreement. No termination penalties were incurred by either party in connection with the termination of the Merger Agreement. The Funding Commitment Letter and related side letter agreement terminated automatically upon termination of the Merger Agreement.
In light of the termination of the Merger Agreement, on January 8, 2024, Avangrid filed a motion to withdraw from the appeal it and PNMR’s subsidiary, Public Service Company of New Mexico (PNM), had filed with the New Mexico Supreme Court with respect to the NMPRC’s December 8, 2021, order which had rejected the amended stipulated agreement entered into by PNM, Avangrid and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application.
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 primarily 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 and other equity investments 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 equity method investments as a reduction in the carrying amount of the investment and not as dividend income. When an equity method investee executes derivative transactions that have cash flow hedge accounting treatment, we recognize our share of the OCI in our consolidated balance sheet. 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.
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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
Structural components
25-40
Rotary components
25-30
Solar power stations
30
Transmission and transport facilities
10-80
Distribution facilities
4-80
Equipment Conventional meters and measuring devices
10-85
Computer software
1-25
Other Buildings
10-75
Operations offices
4-70
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. Networks charges the original cost of utility plant retired or otherwise disposed to accumulated depreciation. Networks' composite rate of depreciation was 2.8% of average depreciable property for both 2023 and 2022.
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.
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(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. For the Renewables segment, the property, plant and equipment are grouped on a market hub-basis where we have interdependent revenues. Renewables development projects (e.g., prior to reaching the commercial operation date) are analyzed for impairment at a project level.
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 that 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 that hedge a liability (i.e. debt)
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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.
Renewables classifies certain contracts for the purchase and sale of both gas and electricity as derivatives, in accordance with the applicable accounting standards. Renewables may also have gains or losses from certain contracts, that are not designated as cash flow hedges, including those entered into for proprietary trading purposes, which it generally classifies as derivative revenue.
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 receivables and unbilled revenues, 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. As required by their state regulatory commissions, the affected 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.
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.
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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 payments from transactions in advance of the resulting performance obligations arising from the transaction. It is our policy to defer such payments 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.
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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.
We record AROs for the decommissioning of the wind and solar farms and thermal facilities. Projected removal costs are based on engineering estimates which are updated on an annual basis based on the relevant inflation and discount rate factors.
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. If a plan meets settlement or curtailment criteria, we recognize a regulatory asset or liability if these costs are probable of recovery from ratepayers. 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 regulatory assets and liabilities for the net revenue requirements to be recovered from or refunded to customers for the related future tax expense or benefit 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. We consider the effect of the corporate alternative minimum tax system in determining the need for a valuation allowance for deferred taxes.
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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. Our policy is to recognize interest and penalties related to unrecognized tax benefits within “Interest expense, net of capitalization” in our consolidated statements of income. Uncertain tax positions have been classified as non-current unless expected to be paid within one year.
Federal production tax credits (PTCs) applicable to our renewable energy facilities, that are not part of a tax equity financing arrangement, are recognized as a reduction in deferred income tax expense with a corresponding reduction in deferred income tax liabilities. Subsequent sales of PTCs under transferability rules are currently recognized with an offset to deferred taxes, with any difference between the sale price and the carrying value of the PTC adjusted to deferred income tax expense.
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) Improvements to Reportable Segment Disclosures
In November 2023, the FASB issued guidance requiring incremental disclosures for reportable segments. These incremental requirements include disclosing significant expenses that are regularly provided to the chief operating decision maker (CODM) and other segment items, including a description of its composition. The other segment items category is the difference between segment revenue less the significant segment expenses, and each reported measure of segment profit or loss. The guidance clarifies that if the CODM reviews multiple measures of a segments total profit or loss, that the entity may under certain conditions report multiple measures in the segment footnote; however, if only one measure is reported, it should be the one that best conforms with U.S. GAAP. The guidance requires disclosure of the title and position of the individual or the name of the group identified as the CODM. Finally, all annual disclosures are required in interim reporting. We adopted the new disclosure requirements pursuant to this guidance on January 1, 2024.
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) Improvements to Income Tax Disclosures
In December 2023, the FASB issued guidance to enhance income tax disclosures. The standard is required to be adopted by public business entities for annual periods beginning after December 15, 2024. Early adoption is permitted. The two primary enhancements relate to disaggregation of the annual effective tax rate reconciliation and income taxes paid disclosures. For the rate reconciliation, it requires additional disaggregation of information in a tabular format using both percentages and amounts broken out into specific categories (e.g., state and local income tax net of federal income tax effect, foreign tax effects, effect of changes in tax laws, tax credits, changes in valuation allowances, nontaxable or nondeductible items, and changes in unrecognized tax benefits). For income taxes paid, it requires disaggregation by jurisdiction (e.g., federal, state and foreign). We do not expect the new guidance to have a material impact on our consolidated results of operations, financial position and cash flows.
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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 and projects under development; (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 derived from HLBV (hypothetical liquidation at book value) accounting. 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.
Union collective bargaining agreements
We have approximately 45.8% of our employees covered by a collective bargaining agreement. Agreements which will expire within the coming year apply to approximately 24.1% of our employees.
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 the FASB issued ASC Topic 606, Revenue from Contracts with Customers (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.
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(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 significant financing elements in any of the arrangements. 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.
Renewables classifies certain contracts for the sale of electricity as derivatives, in accordance with the applicable accounting standards. Renewables also has revenue from its energy trading operations, which it generally classifies as derivative revenue. However, trading contracts not classified as derivatives are within the scope of ASC 606, with the performance obligation of the delivery of energy (electricity, natural gas) and settlement of the contracts satisfied at a point in time at which time we recognize the revenue. Renewables also has other ASC 606 revenue, which we recognize based on the amount invoiced to the customer.
Certain customers may receive cash credits, which we account for as variable consideration. Renewables estimates those amounts based on the expected amount to be provided to customers and reduces revenues recognized. We believe that there will not be significant changes to our estimates of variable consideration.
Other
Other, which does not represent a segment, includes miscellaneous Corporate revenues and intersegment eliminations.
Contract Costs, Contract Liabilities and Practical Expedient
We have contract assets for costs from development success fees, which we paid during a solar farm 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 April 2024 upon commercial operation. Contract assets totaled $9 million as of both December 31, 2023 and 2022, and are presented in "Other non-current assets" on our consolidated balance sheets.
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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 $18 million and $33 million at December 31, 2023 and 2022, respectively, and are presented in "Other current liabilities" on our consolidated balance sheets. We recognized $45 million, $33 million and $22 million as revenue related to contract liabilities for the years ended December 31, 2023, 2022 and 2021, respectively.
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, 2023, 2022 and 2021 are as follows:
  Year Ended December 31, 2023
  Networks Renewables Other (b) Total
(Millions)        
Regulated operations – electricity $ 4,962  $ —  $ —  $ 4,962 
Regulated operations – natural gas 1,617  —  —  1,617 
Nonregulated operations – wind —  817  —  817 
Nonregulated operations – solar —  46  —  46 
Nonregulated operations – thermal —  180  —  180 
Other (a) 76  (52) (2) 22 
Revenue from contracts with customers 6,655  991  (2) 7,644 
Leasing revenue 9  —  —  9 
Derivative revenue —  450  —  450 
Alternative revenue programs 137  —  —  137 
Other revenue 54  15  —  69 
Total operating revenues $ 6,855  $ 1,456  $ (2) $ 8,309 
  Year Ended December 31, 2022
  Networks Renewables Other (b) Total
(Millions)
Regulated operations – electricity $ 4,610  $ —  $ —  $ 4,610 
Regulated operations – natural gas 1,931  —  —  1,931 
Nonregulated operations – wind —  947  —  947 
Nonregulated operations – solar —  36  —  36 
Nonregulated operations – thermal —  96  —  96 
Other (a) 117  48  —  165 
Revenue from contracts with customers 6,658  1,127  —  7,785 
Leasing revenue 8  —  —  8 
Derivative revenue —  4  —  4 
Alternative revenue programs 68  —  —  68 
Other revenue 48  10  —  58 
Total operating revenues $ 6,782  $ 1,141  $ —  $ 7,923 
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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 
(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, 2023 and 2022, accounts receivable balances related to contracts with customers were approximately $1,441 million and $1,622 million, respectively, including unbilled revenues of $426 million and $541 million, which are included in “Accounts receivable and unbilled revenues, net” on our consolidated balance sheets.
As of December 31, 2023, the aggregate amount of the transaction price allocated to performance obligations that are unsatisfied (or partially unsatisfied) were as follows:
As of December 31, 2023 2024 2025 2026 2027 2028 Thereafter Total
(Millions)              
Revenue expected to be recognized on multiyear retail energy sales contracts in place $ 1  $ —  $ —  $ —  $ —  $ —  $ 1 
Revenue expected to be recognized on multiyear renewable energy credit sale contracts 69  67  34  13  1  2  186 
Revenue expected to be recognized on multiyear capacity and carbon-free energy sale contracts 89  28  10  7  5  54  193 
Total operating revenues $ 159  $ 95  $ 44  $ 20  $ 6  $ 56  $ 380 
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 their operating costs, including energy costs, finance costs and the costs of equity, the last of which reflects our capital ratio and a reasonable ROE.
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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, proceedings on Transmission Planning Pursuant to the Accelerated Renewable Energy Growth and Community Benefit Act, Climate Leadership and Community Protection Act (CLCPA), Gas Planning Order, 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. Commencing on March 1, 2020, the MPUC also imposed a 1.00% ROE reduction (to 8.25%) for management efficiency associated with CMP’s customer service performance following the implementation of its new billing system in 2017 which would be removed after demonstrating satisfactory customer service performance. In September 2021, CMP met the 18-month required rolling average satisfactory customer service benchmarks and filed with the MPUC a request for removal of the management efficiency adjustment, which was approved by the MPUC effective as of its February 18, 2022 order.
On August 11, 2022, CMP filed a three-year rate plan, with adjustments to the distribution revenue requirement in each year. On May 31, 2023, CMP filed a Stipulation resolving all issues in the case providing for a 9.35% ROE, 50% equity ratio, and 50% earnings sharing for annual earnings in excess of 100 basis points of CMP’s allowed ROE. The Stipulation also provides for a two-year forward looking rate plan with increases to occur in four equal levelized amounts every six months beginning on July 1, 2023. The next three increases will occur on January 1, 2024, July 1, 2024, and January 1, 2025. The amount of each increase is $16.75 million. These revenue increases include amounts for operations and maintenance but are primarily driven by increases in capital investment forecast by CMP to occur during the period covered by the Stipulation. The Stipulation also imposes a service quality indicator incentive mechanism on CMP. The incentive is provided by a penalty mechanism that would impose a maximum of $8.8 million per year for a failure to meet specified service quality indicator targets.
No party opposed the Stipulation and it was approved in its entirety by the MPUC on June 6, 2023.
NYSEG and RG&E Rate Plans
2020 Joint Proposal
On November 19, 2020, the NYPSC approved a new three-year rate plan for NYSEG and RG&E (2020 Joint Proposal), with modifications to the rate increases at the two electric businesses. The effective date of new tariffs was December 1, 2020 with a make-whole provision back to April 17, 2020. The proposed rates facilitate the companies’ transition to a cleaner energy future while allowing for important initiatives such as COVID-19 relief for customers and additional funding for vegetation management, hardening/resiliency and emergency preparedness. The rate plans continue the RAM designed to return or collect certain defined reconciled revenues and costs, have new depreciation rates and continue existing RDMs for each business. The 2020 Joint Proposal bases delivery revenues on an 8.80% ROE and 48.00% equity ratio; however, for the proposed ESM, the equity ratio is the lower of the actual equity ratio or 50.00%.
2023 Joint Proposal
On May 26, 2022, NYSEG and RG&E filed for a new rate plan with the NYPSC. The rate filings were based on test year 2021 financial results adjusted to the rate year May 1, 2023 – April 30, 2024. NYSEG and RG&E filed for a one-year rate plan but expressed interest in exploring a multi-year plan during the pendency of the case (as is the custom in New York).
On September 16, 2022, the NYPSC suspended new tariffs and rates through April 21, 2023, and NYSEG and RG&E voluntarily agreed to subsequent suspensions through October 18, 2023, subject to a make-whole provision.
Following discovery and settlement negotiations, on June 14, 2023, NYSEG and RG&E filed a Joint Proposal (2023 JP) settlement for a three-year rate plan with the NYPSC. Hearings on the settlement followed in July 2023. The 2023 JP provides for a three-year rate plan for electric and gas service at NYSEG and RG&E commencing May 1, 2023 and continuing through April 30, 2026.
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For purposes of the 2023 JP, the three rate years are defined as the 12 months ending April 30, 2024 (New York Rate Year 1); April 30, 2025 (New York Rate Year 2); and April 30, 2026 (New York Rate Year 3); respectively. On October 12, 2023, the NYPSC approved the JP 2023, commencing May 1, 2023 and continuing through April 30, 2026. The effective date of new tariffs was November 1, 2023 with a make-whole provision back to May 1, 2023.
The 2023 JP, as approved, includes levelization across the three years of the rate plan for delivery rates for NYSEG's and RG&E’s Electric and Gas businesses. Actual bill impacts vary by customer class based on the agreed‑upon revenue allocation and rate design. The allowed rate of return on common equity for NYSEG Electric, NYSEG Gas, RG&E Electric and RG&E Gas is 9.20%. The common equity ratio for each business is 48.00%.
The 2023 JP also includes Earnings Sharing Mechanism (ESM) applicable to each business varies based on the earned ROE with 100% of the customers’ portion of earnings above the sharing threshold that would otherwise be deferred for the benefit of customers will be used to reduce NYSEG's and RG&E’s respective outstanding regulatory asset deferral balances. In addition, 50% of NYSEG's and RG&E’s portion will be used to reduce their respective outstanding storm-related regulatory asset deferral balances to the extent such balances exist.
The 2023 JP further enhances distribution vegetation management, maintains gas safety performance measures, establishes threshold performance levels for designated aspects of customer service quality, and includes three Electric Reliability Performance Measures (SAIFI, CAIDI, and Distribution Line Inspection Program Metric for Level II Deficiencies) with a negative revenue adjustment (NRA) beginning with calendar year 2023, if NYSEG fails to meet its annual SAIFI performance metric.
NYSEG and RG&E will continue a RAM to return or collect the remaining Customer Bill Credits established in the prior rate plan and will continue an Electric Revenue Decoupling Mechanism on a total revenue per class basis.
The 2023 JP reflects the recovery of deferred NYSEG Electric and RG&E Electric Major Storm costs of approximately $371 million and $54.6 million, respectively. NYSEG’s remaining super storm regulatory asset of $52.3 million and the non-super storm regulatory asset of $96.6 million from the 2020 Joint Proposal are being amortized over seven years. RG&E’s remaining non-super storm regulatory asset of $19.6 million established prior to the 2020 Joint Proposal is being amortized over two years. All other deferred storm costs at both NYSEG and RG&E are being amortized over 10 years. The 2023 JP gradually increases NYSEG’s and RG&E’s Major Storm rate allowances over the term of the 2023 JP to better align NYSEG’s and RG&E’s actual Major Storm costs with such rate allowances and to support NYSEG’s and RG&E’s credit metrics.
The 2023 JP contains provisions consistent with, supportive of, and in furtherance of the objectives of the CLCPA including provisions that will, among other things, increase funding for energy efficiency programs, enhance the electric system in anticipation of increased electrification and increase funding for electric heat pump programs, provide funding for improved electric and gas reliability and resiliency, encourage non-pipe and non-wire alternatives, and replace leak prone pipe. The 2023 JP also includes support for $634 million of capital investment for CLCPA Phase 1 investments projected to be placed in-service beyond the three-year rate plan.
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 2024 and 50% of the second half of 2024. 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 2024.
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.
On September 9, 2022, UI filed a distribution revenue requirement case proposing a three-year rate plan commencing September 1, 2023 through August 31, 2026. The filing was based on a test year ending December 31, 2021, for the rate years beginning September 1, 2023 (UI Rate Year 1), September 1, 2024 (UI Rate Year 2), and September 1, 2025 (UI Rate Year 3).
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UI requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $91 million in UI Rate Year 1, an incremental increase of approximately $20 million in UI Rate Year 2, and an incremental increase of approximately $19 million in UI Rate Year 3, compared to total revenues that would otherwise be recovered under UI’s current rate schedules. UI’s Rate Plan also included several measures to moderate the impact of the proposed rate update for all customers, including, without limitation, a rate levelization proposal to spread the proposed total rate increase over the three rate years, which would result in a change in revenue in UI Rate Year 1 of approximately $54 million. On July 21, 2023, PURA issued a proposed Final Decision (draft decision), providing for an 8.8% ROE, 50% equity ratio, and for a one-year rate plan. UI filed exceptions to the draft decision on August 7, 2023. On August 25, 2023 PURA issued its Final Decision on UI's one-year rate plan commencing on September 1, 2023, providing for a rate increase of $23 million based on an allowed ROE of 9.1% that was reduced to 8.63% by certain adjustments. The Final Decision established a capital structure consisting of 50% common equity and 50% debt. The Final Decision results in an average increase in base distribution rates of about 6.6% and an average increase in customer bills of about 2% compared to current levels. On September 18, 2023, UI filed an appeal of the PURA's Final Decision in Connecticut Superior Court, because of factual and legal errors related to the treatment of deferred assets, plant in service, and operating expenses. We cannot predict the outcome of this matter.
In 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 an approximately 52.00% equity ratio. Any dollars due to customers from the ESM are be first applied against any environmental regulatory asset balance as defined in the settlement agreement (if one exists at that time) or refunded to customers through a bill credit if such environmental regulatory asset balance does not exist.
In 2018, PURA approved new tariffs for 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 April 24, 2023 the Connecticut Attorney General, Office of Consumer Counsel, Connecticut Public Utilities Regulatory Authority Office of Education, Outreach, and Enforcement and the Connecticut Industrial Energy Consumer filed a Petition requesting that PURA conduct a general rate hearing for CNG. On May 5, 2023, CNG and SCG responded indicating a willingness to file general rate cases for each company by November 1, 2023. PURA assented to the companies’ proposal on May 21, 2023. On September 29, 2023, SCG and CNG filed a notice of intent to file general rate cases on or about November 3, 2023.
On November 3, 2023, CNG and SCG filed a distribution revenue requirement case proposing a one-year rate plan commencing November 1, 2024 through October 31, 2025, for each company respectively. The filing was based on a test year ending December 31, 2022. CNG requested that PURA approve new distribution rates to recover an increase in revenue requirements of approximately $19.8 million, and SCG requested approval of new distribution rates to recover an increase in revenue requirements of approximately $40.6 million. CNG’s and SCG’s Rate Plan also included several measures to moderate the impact of the proposed rate update for all customers, including, the adoption of a low-income discount rate and seeks to maintain its current revenue decoupling and earning sharing mechanisms.
On June 24, 2022, BGC filed a Settlement Agreement with the Massachusetts Attorney General’s Office (AGO) for DPU approval. The Settlement Agreement followed BGC’s December 14, 2021 filing of a Notice of Intent to File Rate Schedules. Following that filing, BGC and the AGO negotiated the Settlement Agreement in lieu of a fully litigated rate case before the DPU. The Settlement Agreement allows for agreed-upon adjustments to BGC’s revenue requirement as well as various step increases BGC shall be entitled to on January 1, 2023 and January 1, 2024. The Settlement Agreement provides that it shall be void unless approved in its entirety by the DPU by November 1, 2022. It provides for the opportunity to increase BGC’s revenue requirement by as much as $5.6 million over current rates (reflective of a 9.70% ROE and a 54.00% equity ratio as well as other stepped adjustments) through January 1, 2024. The Settlement Agreement was approved in its entirety by the DPU on October 27, 2022, and new rates went into effect January 1, 2023.
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 was 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.
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The NYPSC issued a 2015 order in Track 1, which acknowledged the utilities’ role as a Distribution System Platform provider, and required the utilities to file an initial Distribution System Implementation Plan (DSIP) followed by bi-annual updates. The next scheduled DSIP update is June 30, 2025.
A Track 2 order was issued in May 2016, and included guidance related to the potential for Earnings Adjustment Mechanisms (EAMs), Platform Service Revenues, innovative rate designs and data utilization and security. EAMs were approved by the Commission on November 19, 2020 in its Order approving the companies' 2020 Rate Plan. Modifications to EAMs were approved by the Commission on October 12, 2023 in its Order approving the companies' 2023 Rate Plan.
In 2017, the NYPSC approved a transition from traditional Net Energy Metering (NEM) towards a more values-based approach (Value Stack) for compensating DER. Since that time, the Commission has issued a number of orders on additional Value of Distributed Energy Resources matters. Most recently, the NYPSC Staff issued a proposal on Community Distributed Generation (CDG) Billing and Crediting Performance Metrics and Negative Revenue Adjustments (NRA). The NYPSC Staff recommends six CDG performance metrics with associated NRAs that would incent improvements to the CDG billing processes. At this time, the outcome of this proceeding is unknown.
Other REV-related orders pertaining to electric vehicles (EV), an Integrated Energy Data Resource (IEDR) platform and energy storage are summarized below.
•The NYPSC issued an Order on April 20, 2023 instituting a proceeding to advance infrastructure for medium and heavy-duty vehicles. The Joint Utilities filed an implementation plan with the NYPSC for the medium and heavy-duty pilot program. The Joint Utilities are awaiting the NYPSC's approval of the implementation plan.
•On February 11, 2021, the NYPSC issued an Order to implement an Integrated Energy Data Resource platform, where NYSERDA was designated as the Program Sponsor of the platform. 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 January 19, 2024, the NYPSC issued an Order approving Phase 2 budget, with costs up to the combined cost cap deferred for future recovery in the same manner as Phase 1.
•An order 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 EV charging stations.
•On December 13, 2018, the NYPSC issued an Order for utilities to file implementation plans detailing a competitive procurement process and cost recovery for deploying qualified storage systems. NYSEG and RG&E have tariffs in effect to collect costs for the procurement of qualified energy storage assets.
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, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions. 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.
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 $130 million and $137 million, respectively for this item at December 31, 2023 and 2022.
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 process was completed and the final audit report issued by the NYPSC on November 21, 2023 with no impacts to the recorded regulatory assets. In January 2018, the MPUC published the Power Tax audit report with respect to CMP, which required CMP to provide support for the beginning balance of the regulatory assets.
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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 ratings 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 $6,860 million associated with the minimum equity requirements as of December 31, 2023.
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. UI terminated eight of these contracts in 2022 and 2023, and the remaining three projects with existing contracts from these 2019 procurements are with Millstone Nuclear, Seabrook Nuclear and Revolution Wind.
In 2020, pursuant to the 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 were recoverable through electric rates. On October 13, 2023, PURA approved the termination of this agreement between UI and its affiliate for the development of Park City Wind Project.
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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 August 17, 2013, CMP entered into a 20-year fixed rate agreement with Maine Wood Pellets, a 7.1 MW wood-fired biomass cogeneration facility. Pursuant to a MPUC Order dated September 22, 2016, CMP entered into a 20-year fixed rate agreement with Georges River Energy, a 7.5 MW wood-fired biomass cogeneration facility. Pursuant to a MPUC Order dated August 3, 2017, CMP entered into a 20-year fixed rate agreement with Pittsfield Solar 9.9 MW photovoltaic facility. 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 of which six have been terminated. In October 2021 CMP executed contracts with six additional facilities (Tranche 2), of which one has since terminated. Each of the Tranche 1 and Tranche 2 contracts 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. On June 29, 2023 the Governor of Connecticut signed SB7 into law, which included language that Level 1 storm events were exempt from the waiver. We will continue to review the requirements of the program for the next legislative session.
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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, PURA opened a docket to investigate the preparation for and response to Tropical Storm Isaias by the electric distribution companies in Connecticut including UI. Following hearings and the submission of testimony, PURA issued a final decision on April 15, 2021, finding that UI “generally met standards of acceptable performance in its preparation and response to Tropical Storm Isaias," subject to certain exceptions noted in the decision, but ordered a 15-basis point reduction to UI's ROE in its next rate case to incentivize better performance and indicated that penalties could be forthcoming in the penalty phase of the proceedings. On June 11, 2021, UI filed an appeal of PURA’s decision with the Connecticut Superior Court.
On May 6, 2021, in connection with its findings in the Tropical Storm Isaias docket, PURA issued a Notice of Violation to UI for allegedly failing to comply with standards of acceptable performance in emergency preparation or restoration of service in an emergency and with orders of the Authority, and for violations of accident reporting requirements. PURA assessed a civil penalty in the total amount of approximately $2 million. PURA held a hearing on this matter and, in an order dated July 14, 2021, reduced the civil penalty to approximately $1 million. UI filed an appeal of PURA’s decision with the Connecticut Superior Court. This appeal and the appeal of PURA’s decision on the Tropical Storm Isaias docket have been consolidated. Following oral arguments in October 2022, the court denied UI’s appeal and affirmed PURA’s decisions in their entirety. UI filed a notice of appeal to Connecticut's Appellate court on November 7, 2022. This matter has been briefed and oral argument was held December 11, 2023. We cannot predict the outcome of this proceeding.
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 $1,249 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, 2023 and 2022 consisted of:
As of December 31, 2023 2022
(Millions)
Pension and other post-retirement benefits $ 445  $ 365 
Pension and other post-retirement benefits cost deferrals 58  93 
Storm costs 868  671 
Rate adjustment mechanism 24  41 
Revenue decoupling mechanism 86  52 
Contracts for differences 38  56 
Hardship programs 23  33 
Deferred purchased gas 16  56 
Environmental remediation costs 240  248 
Debt premium 58  64 
Unamortized losses on reacquired debt 17  19 
Unfunded future income taxes 578  492 
Federal tax depreciation normalization adjustment 130  137 
Asset retirement obligation 19  20 
Deferred meter replacement costs 59  55 
COVID-19 cost recovery and late payment surcharge 12  17 
Low income arrears forgiveness 55  31 
Excess generation service charge 52  24 
System Expansion 22  21 
Non-bypassable charge 103  14 
Hedges losses 34  13 
Rate change levelization 60  — 
Value of distributed energy resources 49  36 
Uncollectible reserve 104  — 
New York make-whole provision 96  — 
Other 283  210 
Total regulatory assets 3,529  2,768 
Less: current portion 718  447 
Total non-current regulatory assets $ 2,811  $ 2,321 
“Pension and other post-retirement benefits” represent the actuarial losses on the pension and other post-retirement plans that will be reflected in customer rates when they are amortized and recognized in future pension expenses.
“Pension and other post-retirement benefits cost deferrals” include the difference between actual expense for pension and other post-retirement benefits and the amount provided for in rates for certain of our regulated utilities. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
“Storm costs” for CMP, NYSEG, RG&E and UI are allowed in rates based on an estimate of the routine costs of service restoration. The companies are also allowed to defer unusually high levels of service restoration costs resulting from major storms when they meet certain criteria for severity and duration. A portion of this balance is amortized through current rates, and the remaining portion will be determined through future rate cases.
“Rate adjustment mechanism” represents an interim rate change to return or collect certain defined reconciled revenues and costs for NYSEG and RG&E following the approval of the Joint Proposal by the NYPSC. The RAM, when triggered, is implemented in rates on July 1 of each year for return or collection over a twelve-month period.
"Revenue decoupling mechanism" represents the mechanism established to disassociate the utility's profits from its delivery/commodity sales.
“Contracts for Differences” represent the deferral of unrealized gains and losses on contracts for differences derivative contracts.
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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.
“Deferred Purchased Gas” represents the difference between actual gas costs and gas costs collected in rates.
“Environmental remediation costs” includes spending that has occurred and is eligible for future recovery in customer rates. Environmental costs are currently recovered through a reserve mechanism whereby projected spending is included in rates with any variance recorded as a regulatory asset or a regulatory liability. The amortization period will be established in future proceedings and will depend upon the timing of spending for the remediation costs. It also includes the anticipated future rate recovery of costs that are recorded as environmental liabilities since these will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future spending, it does not accrue carrying costs and is not included within rate base.
“Debt premium” represents the regulatory asset recorded to offset the fair value adjustment to the regulatory component of the non-current debt of UIL at the acquisition date. This amount is being amortized to interest expense over the remaining term of the related outstanding debt instruments.
“Unamortized losses on reacquired debt” represent deferred losses on debt reacquisitions that will be recovered over the remaining original amortization period of the reacquired debt.
“Unfunded future income taxes” represent unrecovered federal and state income taxes primarily resulting from regulatory flow through accounting treatment and are the offset to the unfunded future deferred income tax liability recorded. The income tax benefits or charges for certain plant related timing differences, such as removal costs, are immediately flowed through to, or collected from, customers. This amount is being amortized as the amounts related to temporary differences that give rise to the deferrals are recovered in rates. These amounts are being collected over a period of 46 years, and the NYPSC staff has initiated an audit, as required, of the unfunded future income taxes and other tax assets to verify the balances.
“Federal tax depreciation normalization adjustment” represents the revenue requirement impact of the difference in the deferred income tax expense required to be recorded under the IRS normalization rules and the amount of deferred income tax expense that was included in cost of service for rate years covering 2011 forward. The recovery period in New York is from 25 to 35 years and for CMP 32.5 years beginning in 2020.
“Asset retirement obligations” represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.
“Deferred meter replacement costs” represent the deferral of the book value of retired meters which were replaced or are planned to be replaced by AMI meters. This amount is being amortized over the initial depreciation period of related retired meters.
"COVID-19 cost recovery and late payment surcharge" represents: a) deferred COVID-19-related costs in the state of Connecticut based on the order issued by PURA on April 29, 2020, requiring utilities to track COVID-19-related expenses and lost revenue and create a regulatory asset, and b) deferred lost late payment revenue in the state of New York based on the order issued by the NYPSC on June 17, 2022, approving deferral and surcharge/sur-credit mechanism to recover/return deferred balances starting July 1, 2022.
“Low-income arrears forgiveness” represents deferred bill credits in the state of New York based on the order issued by the NYPSC on June 16, 2022, approving deferral of bill credits for low-income customers and recovery of regulatory asset from all customers over five years for RG&E and three years for NYSEG. Surcharge started August 1, 2022.
“Excess generation service charge” represents deferred generation-related costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
“System expansion” represents expenses not covered by system expansion rates related to expanding the natural gas system and converting customers to natural gas.
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“Non-bypassable charges” represent non-bypassable federally mandated congestion costs or revenues for future recovery from or return to customers. The amount fluctuates based upon timing differences between revenues collected from rates and actual costs incurred.
“Hedge losses” represents the deferred fair value losses on electric and gas hedge contracts.
“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.
“Value of distributed energy resources” represents the mechanism to compensate for energy created by distributed energy resources, such as solar.
“Uncollectible reserve” includes the anticipated future rate recovery of costs that are recorded as uncollectible since those will be recovered when incurred. Because no funds have yet been expended for the regulatory asset related to future uncollectible expense, it does not accrue carrying costs and is not included within rate base. It also includes the variance between actual uncollectible expense and uncollectible expense included in rates that is eligible for future recovery in customer rates. The amortization period will be established in future proceedings.
“New York make-whole provision” represents the regulatory asset to recover revenues that would have been received by NYSEG/RGE had Rate Year 1 rates approved in the 22-E-0317 et al. joint proposal gone into effect on the effective date of May 1, 2023. The balance is being recovered through a separately stated make-whole rate, effective November 1, 2022, over 6-30 months.
“Other” includes various items subject to reconciliation including vegetation management and systems benefit charge.
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Regulatory liabilities as of December 31, 2023 and 2022 consisted of:
As of December 31, 2023 2022
(Millions)
Energy efficiency portfolio standard $ 15  $ 30 
Gas supply charge and deferred natural gas cost 8  15 
Pension and other post-retirement benefits cost deferrals 89  117 
Carrying costs on deferred income tax bonus depreciation 3  9 
Carrying costs on deferred income tax - Mixed Services 263(a) 2  3 
2017 Tax Act 1,190  1,232 
Accrued removal obligations 1,139  1,178 
Positive benefit adjustment 9  16 
Deferred property tax 21  17 
Net plant reconciliation 23  11 
Debt rate reconciliation 18  32 
Rate refund – FERC ROE proceeding 39  36 
Transmission congestion contracts 26  31 
Merger-related rate credits 8  10 
Accumulated deferred investment tax credits 21  22 
Asset retirement obligation 19  18 
Middletown/Norwalk local transmission network service collections 16  17 
Non-firm margin sharing credits 34  27 
Non by-passable charges 9  76 
Transmission revenue reconciliation mechanism 57  75 
Other 209  297 
Total regulatory liabilities 2,955  3,269 
Less: current portion 261  354 
Total non-current regulatory liabilities $ 2,694  $ 2,915 
“Energy efficiency portfolio standard” represents the costs of energy efficiency programs deferred for future recovery to the extent they exceed the amount in rates. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
"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.
“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.
“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.
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The NYPSC, MPUC, PURA, DPU and the FERC held separate proceedings in New York, Maine, Connecticut, Massachusetts and the FERC, respectively, and for the majority of our regulated utilities, authorized the amortization periods for the return of regulatory liabilities and the recovery of regulatory assets, including the authorization of sur-credits to return the related benefits to rate payers in certain jurisdictions.
“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.
“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.
"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.
"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.
"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 RG&E. A portion of this balance is amortized through current rates, the remaining portion will be refunded in future periods through future rate cases.
“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, 2023 and 2022, $2 million of rate credits were applied against customer bills.
"Asset retirement obligation" represents the differences in timing of the recognition of costs associated with our AROs and the collection of such amounts through rates. This amount is being amortized at the related depreciation and accretion amounts of the underlying liability.
"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.
“Non-firm margin sharing credits” represents the portion of interruptible and off-system sales revenue set aside to fund gas expansion projects.
“Other” includes various items subject to reconciliation or being returned through rates, such as service quality metrics.
Note 7. Goodwill and Intangible Assets
Goodwill by reportable segment as of December 31, 2023 and 2022 consisted of:
As of December 31, 2023 2022
(Millions)    
Networks $ 2,747  $ 2,747 
Renewables 372  372 
Total $ 3,119  $ 3,119 
During 2023, 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.
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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 2023, we utilized a qualitative assessment for the Networks reporting units and a quantitative assessment for the Renewables reporting unit. We had no impairment of goodwill in 2023 and 2022 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, 2023 and 2022:
As of December 31, 2023 Gross Carrying Amount Accumulated Amortization Net Carrying Amount
(Millions)      
Wind development $ 587  $ (325) $ 262 
Other 48  (26) 22 
Total Intangible Assets $ 635  $ (351) $ 284 
As of December 31, 2022 Gross Carrying Amount Accumulated Amortization Net Carrying Amount
(Millions)      
Wind development $ 590  $ (313) $ 277 
Other 22  (18) 4 
Total Intangible Assets $ 612  $ (331) $ 281 
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 $15 million, $14 million and $13 million for the years ended December 31, 2023, 2022 and 2021, 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, 2023, to be as follows:
Year ending December 31, Amount
(Millions)  
2024 $ 15 
2025 $ 14 
2026 $ 14 
2027 $ 13 
2028 $ 12 
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Note 8. Property, Plant and Equipment
Property, plant and equipment as of December 31, 2023, consisted of:
As of December 31, 2023 Regulated Nonregulated Total
(Millions)      
Electric generation, distribution, transmission and other $ 19,729  $ 14,620  $ 34,349 
Natural gas transportation, distribution and other 5,751  14  5,765 
Other common operating property —  341  341 
Total Property, Plant and Equipment in Service 25,480  14,975  40,455 
Total accumulated depreciation (6,742) (5,737) (12,479)
Total Net Property, Plant and Equipment in Service 18,738  9,238  27,976 
Construction work in progress 2,902  1,979  4,881 
Total Property, Plant and Equipment $ 21,640  $ 11,217  $ 32,857 
Property, plant and equipment as of December 31, 2022, consisted of:
As of December 31, 2022 Regulated Nonregulated Total
(Millions)      
Electric generation, distribution, transmission and other $ 18,634  $ 14,096  $ 32,730 
Natural gas transportation, distribution and other 5,392  14  5,406 
Other common operating property —  317  317 
Total Property, Plant and Equipment in Service 24,026  14,427  38,453 
Total accumulated depreciation (6,277) (5,265) (11,542)
Total Net Property, Plant and Equipment in Service 17,749  9,162  26,911 
Construction work in progress 2,225  1,858  4,083 
Total Property, Plant and Equipment $ 19,974  $ 11,020  $ 30,994 
Capitalized interest costs were $115 million, $53 million and $33 million for the years ended December 31, 2023, 2022 and 2021, respectively. Accrued liabilities for property, plant and equipment additions were $653 million, $481 million and $297 million as of December 31, 2023, 2022 and 2021, respectively.
We impaired or wrote off amounts of $6 million, $11 million and $20 million for the years ended December 31, 2023, 2022 and 2021, respectively, resulting from reassessment of the economic feasibility of our various Renewables development projects under construction.
Depreciation expense for the years ended December 31, 2023, 2022 and 2021, amounted to $1,143 million, $1,071 million and $1,001 million, respectively.
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.
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The reconciliation of ARO carrying amounts for the years ended December 31, 2023 and 2022 consisted of:
(Millions)  
As of December 31, 2021 $ 253 
Liabilities settled during the year (1)
Liabilities incurred during the year 13 
Accretion expense 14 
Revisions in estimated cash flows (a) (6)
As of December 31, 2022 $ 273 
Liabilities settled during the year (1)
Liabilities incurred during the year 12 
Accretion expense 15 
Revisions in estimated cash flows (a) 7 
As of December 31, 2023 $ 306 
(a)Represents an increase (decrease) 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, 2023 and 2022, 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.
Note 10. Debt
Long-term debt as of December 31, 2023 and 2022 consisted of:
As of December 31, 2023 2022
Maturity Dates Balances Interest Rates Balances Interest Rates
(Millions)
First mortgage bonds - fixed (a)
2025-2053
 $ 3,316 
1.85%-8.00%
 $ 2,882 
1.85%-8.00%
Unsecured pollution control notes - fixed
2024-2034
 545 
1.40%-4.00%
 545 
1.40%-4.00%
Intragroup Green Loan
2033
 800 
5.45%
 — 
Other various non-current debt - fixed
2024-2052
 5,988 
1.95%-6.66%
 5,276 
1.95%-6.66%
Unamortized debt issuance costs and discount (53) (76)
Total Debt including with affiliate 10,596  8,627 
Less: debt due within one year, included in current liabilities 612  412 
Total Non-current Debt including with affiliate $ 9,984  $ 8,215 
(a)The first mortgage bonds have pledged collateral of substantially all the respective utility’s in service properties of approximately $8,906 million.
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2023 Long-Term Debt Issuances
Company Issue Date Type Amount (Millions) Interest rate Maturity
NYSEG 7/3/2023 Tax Exempt Bond $ 100 
4.00%
 2034
UI 10/2/2023 Tax Exempt Bond $ 64 
4.50%
 2033
NYSEG 8/8/2023 Green 144A Bond $ 350 
5.65%
 2028
NYSEG 8/8/2023 Green 144A Bond $ 400 
5.85%
 2033
RG&E 12/13/2023 Green Private Bond $ 100 
5.62%
 2028
RG&E 12/13/2023 Green Private Bond $ 25 
5.89%
 2034
RG&E 12/13/2023 Green Private Bond $ 50 
5.99%
 2036
RG&E 12/13/2023 Green Private Bond $ 75 
6.22%
 2053
CMP 12/13/2023 Green Private Bond $ 55 
5.65%
 2029
CMP 12/13/2023 Green Private Bond $ 70 
6.04%
 2038
UI 12/13/2023 Green Private Bond $ 156 
6.09%
 2034
UI 12/13/2023 Green Private Bond $ 34 
6.29%
 2038
CNG 12/13/2023 Private Bond $ 36 
6.20%
 2032
CNG 12/13/2023 Private Bond $ 19 
6.49%
 2038
SCG 12/13/2023 Private Bond $ 30 
6.04%
 2034
SCG 12/13/2023 Private Bond $ 30 
6.24%
 2038
Corporate 7/19/2023 Intragroup Green Loan $ 800 
5.45%
 2033
Long-term debt maturities, including sinking fund obligations, due over the next five years consist of:
2024 2025 2026 2027 2028 Total
(Millions)
$ 612  $ 1,107  $ 660  $ 484  $ 716  $ 3,579 
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, 2023 and 2022 and throughout 2023 and 2022.
Fair Value of Debt
As of December 31, 2023 and 2022, the estimated fair value of long-term debt, including the Intragroup Green Loan, was $10,266 million and $7,991 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.
Intragroup Green Loan
On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan).
Short-term Debt
Avangrid had $1,347 million and $566 million of notes payable as of December 31, 2023 and 2022, 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, 2023 and 2022, the amount of notes payable under the commercial paper program was $1,332 million and $397 million, respectively, presented net of discounts on the balance sheet. As of December 31, 2023, the weighted-average interest rate on outstanding commercial paper was 5.65%.
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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.
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. On July 17, 2023, the Avangrid Credit Facility was amended and restated to, among other things, provide for the replacement of LIBOR-based rates with SOFR-based rates and remove provisions related to the extension of credit to the Public Service Company of New Mexico and Texas-New Mexico Power Company. As of both December 31, 2023 and 2022, we had no borrowings outstanding under this credit facility.
Since the Avangrid credit facility is also a backstop to the Avangrid commercial paper program, the total amount available under the facility as of December 31, 2023 was $2,233 million.
Iberdrola Group Credit Facility
On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of both December 31, 2023 and 2022, 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, 2023 and 2022, the amount of notes payable under supplier financing arrangements was $0 and $171 million, respectively. For the year ended December 31, 2023, $4 million of invoices were confirmed and $175 million of confirmed invoices were paid under the program. As of December 31, 2022, the weighted average interest rate on the balance was 5.48%.
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. Our Rabbi Trusts, which cover certain deferred compensation plans and non-qualified pension plan obligations, consist of equity and other investments. The Rabbi Trusts primarily invest in equity securities, fixed income and money market funds. Certain Rabbi Trusts also invest in trust or company owned life insurance policies. We measure the fair value of our Rabbi Trust portfolio using observable, unadjusted quoted market prices in active markets for identical assets and include the measurements in Level 1. We measure the fair value of the supplemental retirement benefit life insurance trust based on quoted prices in the active markets for the various funds within which the assets are held and include the measurement in Level 2.
•NYSEG and RG&E enter into electric energy derivative contracts to hedge the forecasted purchases required to serve their electric load obligations. They hedge their electric load obligations using derivative contracts that are settled based upon Locational Based Marginal Pricing published by the NYISO. NYSEG and RG&E hedge approximately 70% of their electric load obligations using contracts for a NYISO location where an active market exists. The forward market prices used to value the companies’ open electric energy derivative contracts are based on quoted prices in active markets for identical assets or liabilities with no adjustment required and therefore we include the fair value measurements in Level 1.
•NYSEG and RG&E enter into natural gas derivative contracts to hedge their forecasted purchases required to serve their natural gas load obligations. NYSEG and RG&E hedge up to approximately 55% of their forecasted winter demand through the use of financial transactions and storage withdrawals. The forward market prices used to value open natural gas derivative contracts are exchange-based prices for the identical derivative contracts traded actively on the New York Mercantile Exchange (NYMEX). We include the fair value measurements in Level 1 because we use prices quoted in an active market.
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•UI enters into CfDs, which are marked-to-market based on a probability-based expected cash flow analysis that is discounted at risk-free interest rates and an adjustment for non-performance risk using credit default swap rates. We include the fair value measurement for these contracts in Level 3 (See Note 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 modeled volumes on unit-contingent contracts, extrapolated power curves through May 2032 and scheduling assumptions on California power exports to cover Nevada physical power sales. The valuation for this category is based on our judgments about the assumptions market participants would use in pricing the asset or liability since limited market data exists.
We determine the fair value of our interest rate derivative instruments based on a model whose inputs are observable, such as SOFR, forward interest rate curves or other relevant benchmark. We include the fair value measurement for these contracts in Level 2 (See Note 12 for further discussion of interest rate contracts).
We determine the fair value of our foreign currency exchange derivative instruments based on current exchange rates compared to the rates at inception of the hedge. We include the fair value measurement for these contracts in Level 2.
The carrying amounts for cash and cash equivalents, restricted cash, accounts receivable, accounts payable, notes payable, lease obligations and interest accrued approximate fair value.
Restricted cash was $3 million as of both December 31, 2023 and 2022, 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, 2023 and 2022 consisted of:
As of December 31, 2023 Level 1 Level 2 Level 3 Netting Total
(Millions)          
Equity and other investments with readily determinable fair values $ 29  $ 16  $ —  $ —  $ 45 
Derivative assets
Derivative financial instruments - power $ 15  $ 42  $ 114  $ (69) $ 102 
Derivative financial instruments - gas —  17  —  (12) 5 
Contracts for differences —  —  1  —  1 
Derivative financial instruments – Other —  122  —  —  122 
Total $ 15  $ 181  $ 115  $ (81) $ 230 
Derivative liabilities
Derivative financial instruments - power $ (37) $ (101) $ (40) $ 135  $ (43)
Derivative financial instruments - gas (12) (26) —  37  (1)
Contracts for differences —  —  (39) —  (39)
Derivative financial instruments – Other —  (92) —  —  (92)
Total $ (49) $ (219) $ (79) $ 172  $ (175)
As of December 31, 2022 Level 1 Level 2 Level 3 Netting Total
(Millions)          
Equity and other investments with readily determinable fair values $ 35  $ 13  $ —  $ —  $ 48 
Derivative assets
Derivative financial instruments - power $ 37  $ 55  $ 165  $ (177) $ 80 
Derivative financial instruments - gas 1  47  —  (45) 3 
Contracts for differences —  —  1  —  1 
Derivative financial instruments – Other —  116  —  —  116 
Total $ 38  $ 218  $ 166  $ (222) $ 200 
Derivative liabilities
Derivative financial instruments - power $ (46) $ (350) $ (93) $ 364  $ (125)
Derivative financial instruments - gas (4) (26) —  30  — 
Contracts for differences —  —  (57) —  (57)
Derivative financial instruments – Other —  (115) —  —  (115)
Total $ (50) $ (491) $ (150) $ 394  $ (297)
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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, 2023, 2022 and 2021 consisted of:
(Millions) 2023 2022 2021
Fair value as of January 1, $ 16  $ (69) $ 13 
Gains for the year recognized in operating revenues 10  108  21 
Losses for the year recognized in operating revenues (22) (30) (34)
Total gains or losses for the period recognized in operating revenues (12) 78  (13)
Gains recognized in OCI 7  2  2 
Losses recognized in OCI (8) (57) (52)
Total gains or losses recognized in OCI (1) (55) (50)
Net change recognized in regulatory assets and liabilities 18  17  13 
Purchases 90  10  (17)
Settlements (87) 8  (13)
Transfers out of Level 3 (a) 12  27  (2)
Fair value as of December 31, $ 36  $ 16  $ (69)
(Losses) 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 $ (12) $ 78  $ (13)
(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, 2023.
Index Avg. Max. Min.
NYMEX ($/MMBtu) $ 4.44  $ 9.86  $ 1.99 
AECO ($/MMBtu) $ 3.11  $ 10.80  $ 1.00 
Ameren ($/MWh) $ 53.73  $ 225.62  $ 20.92 
COB ($/MWh) $ 81.30  $ 400.10  $ 10.85 
ComEd ($/MWh) $ 48.92  $ 222.49  $ 16.77 
ERCOT S hub ($/MWh) $ 50.77  $ 320.63  $ 16.85 
Mid C ($/MWh) $ 78.47  $ 400.10  $ 7.85 
AEP-DAYTON hub ($/MWh) $ 54.53  $ 229.75  $ 22.50 
PJM W hub ($/MWh) $ 57.22  $ 227.60  $ 21.61 
Our Level 3 valuations primarily consist of a Hydro PPA utilized for balancing services for the Northwest wind fleet, power swaps with delivery periods extending through May 2032 hedging Midwest and Texas wind farms and physical power sales agreements in Nevada.
We considered the measurement uncertainty regarding the Level 3 gas and power positions to changes in the valuation inputs. Given the nature of the transactions in Level 3, the primary input to the valuation is the market price of gas or power for transactions with delivery periods exceeding two years. The fixed price power swaps are economic hedges of future power generation, with decreases in power prices resulting in unrealized gains and increases in power prices resulting in unrealized losses. The hydro PPA is a long capacity/energy position in the Northwest that provides balancing services with increases in power prices resulting in unrealized gains and decreases in power prices resulting in unrealized losses. The gas swaps are economic hedges of fuel purchases for a combined cycle gas plant, with increases in gas prices resulting in unrealized gains and decreases in gas prices resulting in unrealized losses. As all transactions are economic hedges of the underlying position, any changes in the fair value of these transactions will be offset by changes in the anticipated purchase/sales price of the underlying commodity.
Two elements of the analytical infrastructure employed in valuing transactions are the price curves used in the calculation of market value and the modeled volumes on unit-contingent agreements. We maintain and document authorized trading points and associated forward price curves, and we develop and document models used in valuation of the various products.
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Transactions are valued in part on the basis of forward prices and estimated volumes. We maintain and document descriptions of these curves and their derivations. Forward price curves used in valuing the transactions are applied to the full duration of the transaction.
The determination of fair value of the CfDs (see Note 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, 2023
Risk of non-performance
0.42% - 0.52%
Discount rate
3.84% - 4.01%
Forward pricing ($ per KW-month)
$2.00 - $2.61
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.
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(a) Networks activities
The tables below present Networks' derivative positions as of December 31, 2023 and 2022, 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, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets $ 13  $ 3  $ 12  $ 3 
Derivative liabilities (12) (3) (57) (32)
1  —  (45) (29)
Designated as hedging instruments
Derivative assets —  —  —  — 
Derivative liabilities —  —  —  — 
—  —  —  — 
Total derivatives before offset of cash collateral 1  —  (45) (29)
Cash collateral receivable —  —  27  7 
Total derivatives as presented in the balance sheet $ 1  $ —  $ (18) $ (22)
As of December 31, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities
(Millions)
Not designated as hedging instruments
Derivative assets $ 30  $ 8  $ 30  $ 7 
Derivative liabilities (30) (7) (58) (50)
—  1  (28) (43)
Designated as hedging instruments
Derivative assets —  —  —  — 
Derivative liabilities —  —  —  — 
—  —  —  — 
Total derivatives before offset of cash collateral —  1  (28) (43)
Cash collateral receivable —  —  11  2 
Total derivatives as presented in the balance sheet $ —  $ 1  $ (17) $ (41)
The net notional volumes of the outstanding derivative instruments associated with Networks' activities as of December 31, 2023 and 2022, respectively, consisted of:
As of December 31, 2023 2022
(Millions)    
Wholesale electricity purchase contracts (MWh) 5.6 5.7
Natural gas purchase contracts (Dth) 10.7 9.6
Derivatives not designated as hedging instruments
NYSEG and RG&E have an electric commodity charge that passes costs for the market price of electricity through rates. We use electricity contracts, both physical and financial, to manage fluctuations in electricity commodity prices in order to provide price stability to customers. We include the cost or benefit of those contracts in the amount expensed for electricity purchased when the related electricity is sold. We record changes in the fair value of electric hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities, in accordance with the accounting requirements concerning regulated operations.
NYSEG and RG&E have purchased gas adjustment clauses that allow us to recover through rates any changes in the market price of purchased natural gas, substantially eliminating our exposure to natural gas price risk. NYSEG and RG&E use natural gas futures and forwards to manage fluctuations in natural gas commodity prices to provide price stability to customers. We include the cost or benefit of natural gas futures and forwards in the commodity cost that is passed on to customers when the related sales commitments are fulfilled. We record changes in the fair value of natural gas hedge contracts to derivative assets and/or liabilities with an offset to regulatory assets and/or regulatory liabilities in accordance with the accounting requirements for regulated operations.
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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, 2023 and 2022 and amounts reclassified from regulatory assets and liabilities into income for the years ended December 31, 2023, 2022 and 2021 are as follows:
(Millions) Loss or Gain Recognized in Regulatory Assets/Liabilities Location of Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income Loss (Gain) Reclassified from Regulatory Assets/Liabilities into Income
As of For the Year Ended December 31,
December 31, 2023 Electricity Natural Gas 2023  Electricity Natural Gas
Regulatory assets $ 22  $ 12  Purchased power, natural gas and fuel used $ 102  $ 15 
Regulatory liabilities $ —  $ — 
December 31, 2022 2022 
Regulatory assets $ 9  $ 4  Purchased power, natural gas and fuel used $ (127) $ (16)
Regulatory liabilities $ —  $ — 
2021 
Purchased power, natural gas and fuel used $ (23) $ (11)
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, 2023, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $38 million, a gross derivative liability of $39 million ($38 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0. As of December 31, 2022, UI has recorded a gross derivative asset of $1 million ($0 of which is related to UI’s portion of the CfD signed by CL&P), a regulatory asset of $56 million, a gross derivative liability of $57 million ($55 million of which is related to UI’s portion of the CfD signed by CL&P) and a regulatory liability of $0.
The unrealized gains and losses from fair value adjustments to these derivatives, which are recorded in regulatory assets, for the years ended December 31, 2023, 2022 and 2021, respectively, were as follows:
Years Ended December 31,
2023 2022 2021
(Millions)      
Derivative Assets $ —  $ (1) $ — 
Derivative Liabilities $ 18  $ 18  $ 13 

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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, 2023, 2022 and 2021, 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)
2023      
Interest rate contracts $ —  Interest expense $ 4  $ 409 
Commodity contracts —  Purchased power, natural gas and fuel used —  2,429 
Total $ —  $ 4 
2022
Interest rate contracts $ —  Interest expense $ 4  $ 303 
Commodity contracts 2  Purchased power, natural gas and fuel used (3) 2,456 
Foreign currency exchange contracts —  — 
Total $ 2  $ 1 
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 
(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 $39 million and $43 million as of December 31, 2023 and 2022, respectively. We recorded $4 million in net derivative losses related to discontinued cash flow hedges during each of the years ended December 31, 2023, 2022 and 2021, respectively. We will amortize approximately $4 million of discontinued cash flow hedges in 2024.
(b) Renewables activities
Renewables sells fixed-price gas and power forwards to hedge our merchant wind assets from declining commodity prices for our Renewables business. Renewables also purchases fixed-price gas and basis swaps and sells fixed-price power in the forward market to hedge the spark spread or heat rate of our merchant thermal assets and enters into tolling arrangements to sell the output of its thermal generation facilities.
Renewables has proprietary trading operations that enter into fixed-price power and gas forwards in addition to basis swaps. The intent is to speculate on fixed-price commodity and basis volatility in the U.S. commodity markets.
Renewables will periodically designate derivative contracts as cash flow hedges for both its thermal and wind portfolios. The fair value changes are recorded in OCI. For thermal operations, Renewables will periodically designate both fixed price NYMEX gas contracts and natural gas basis swaps that hedge the fuel requirements of its Klamath Plant in Klamath, Oregon. Renewables will also designate fixed price power swaps at various locations in the U.S. market to hedge future power sales from its Klamath facility and various wind farms.
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The net notional volumes of outstanding derivative instruments associated with Renewables' activities as of December 31, 2023 and 2022, respectively, consisted of:
As of December 31, 2023 2022
(MWh/Dth in Millions)    
Wholesale electricity purchase contracts 1  2 
Wholesale electricity sales contracts 6  7 
Natural gas and other fuel purchase contracts 21  15 
Financial power contracts 4  6 
Basis swaps - purchases 24  22 
Basis swaps - sales 1  — 
The fair values of derivative contracts associated with Renewables' activities as of December 31, 2023 and 2022, respectively, consisted of:
As of December 31, 2023 2022
(Millions)    
Wholesale electricity purchase contracts $ 29  $ 149 
Wholesale electricity sales contracts 14  (200)
Natural gas and other fuel purchase contracts 4  2 
Financial power contracts 17  8 
Total $ 64  $ (41)
On May 27, 2021, Renewables entered into a forward interest rate swap, with a total notional amount of $935 million, to hedge the issuance of forecasted variable rate debt. The forward interest rate swap is designated and qualifies as a cash flow hedge. As part of the financial close of Vineyard Wind 1 described in Note 22, this hedge was novated to the lending institutions and the notional value changed to $956 million. As of December 31, 2023 and 2022, the fair value of the interest rate swap was $122 million and $116 million, respectively, as non-current assets. The gain or loss on the interest rate swap is reported as a component of accumulated OCI and will be reclassified into earnings in the period or periods during which the related interest expense on the debt is incurred.
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The tables below present Renewables' derivative positions as of December 31, 2023 and 2022, 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, 2023 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities
(Millions)        
Not designated as hedging instruments        
Derivative assets $ 53  $ 52  $ 53  $ 1 
Derivative liabilities —  (3) (73) (4)
53  49  (20) (3)
Designated as hedging instruments
Derivative assets 15  113  7  1 
Derivative liabilities (1) —  (47) (37)
14  113  (40) (36)
Total derivatives before offset of cash collateral 67  162  (60) (39)
Cash collateral receivable —  —  43  13 
Total derivatives as presented in the balance sheet $ 67  $ 162  $ (17) $ (26)
As of December 31, 2022 Current Assets Noncurrent Assets Current Liabilities Noncurrent Liabilities
(Millions)        
Not designated as hedging instruments        
Derivative assets $ 121  $ 63  $ 79  $ 4 
Derivative liabilities (61) (40) (103) (7)
60  23  (24) (3)
Designated as hedging instruments
Derivative assets —  116  —  1 
Derivative liabilities —  —  (168) (89)
—  116  (168) (88)
Total derivatives before offset of cash collateral 60  139  (192) (91)
Cash collateral receivable —  —  105  54 
Total derivatives as presented in the balance sheet $ 60  $ 139  $ (87) $ (37)
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Derivatives not designated as hedging instruments
The effects of trading and non-trading derivatives associated with Renewables' activities for the years ended December 31, 2023, 2022 and 2021 consisted of:
Year Ended December 31, 2023
Trading Non-trading Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts $ (8) $ (5)
Wholesale electricity sales contracts 71  67 
Financial power contracts (5) 41 
Financial and natural gas contracts —  10 
Total gain included in operating revenues $ 58  $ 113  $ 8,309 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts $ —  $ (109)
Financial and natural gas contracts —  (41)
Total loss included in purchased power, natural gas and fuel used $ —  $ (150) $ 2,429 
Total Gain (Loss) $ 58  $ (37)
Year Ended December 31, 2022
Trading Non-trading Total amount per income statement
(Millions)
Operating Revenues
Wholesale electricity purchase contracts $ 9  $ 6 
Wholesale electricity sales contracts 1  (63)
Financial power contracts 1  (52)
Financial and natural gas contracts 1  (6)
Total gain (loss) included in operating revenues $ 12  $ (115) $ 7,923 
Purchased power, natural gas and fuel used
Wholesale electricity purchase contracts $ —  $ 98 
Financial and natural gas contracts —  5 
Total gain included in purchased power, natural gas and fuel used $ —  $ 103  $ 2,456 
Total Gain (Loss) $ 12  $ (12)
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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 gain (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)
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, 2023, 2022 and 2021 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)
2023      
Interest rate contracts $ 122  Interest Expense $ —  $ 409 
Commodity contracts $ 17  Operating revenues $ 169  $ 8,309 
Total $ 139  $ 169 
2022
Interest rate contracts $ 116  Interest Expense $ —  $ 303 
Commodity contracts $ (178) Operating revenues $ 59  $ 7,923 
$ (62) $ 59 
2021
Interest rate contracts $ (58) Interest Expense $ —  $ 298 
Commodity contracts $ (142) Operating revenues $ (3) $ 6,974 
$ (200)   $ (3)
(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 $41 million of loss included in accumulated OCI at December 31, 2023 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, 2023, 2022 and 2021.
(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 $29 million and $38 million as of December 31, 2023 and 2022, respectively. We amortized into income $9 million of the loss related to the settled interest rate contracts for each of the years ended December 31, 2023, 2022 and 2021.
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We will amortize approximately $9 million of the net loss on the interest rate contracts during 2024.
The effect of derivatives in cash flow hedging relationships on accumulated OCI for the years ended December 31, 2023, 2022 and 2021 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)
2023
Interest rate contracts $ —  Interest expense $ 9  $ 409 
2022
Interest rate contracts $ —  Interest expense $ 9  $ 303 
2021
Interest rate contracts $ —  Interest expense $ 9  $ 298 
(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 years ended December 31, 2023 and 2022 are as follows:
Fair value of hedge Location of (Gain) Recognized in Income Statement Loss Recognized in Income Statement Year to date total per Income Statement
(Millions) As of December 31, 2023 Year Ended December 31, 2023
Current liabilities $ (26) Interest Expense $ 31  $ 409 
Non-current liabilities $ (63)
Cumulative effect on hedged debt
Current debt $ — 
Non-current debt $ 89 
Fair value of hedge Location of (Gain) Recognized in Income Statement (Gain) Recognized in Income Statement Year to date total per Income Statement
(Millions) As of December 31, 2022 Year Ended December 31, 2022
Current liabilities $ (29) Interest Expense $ 6  $ 303 
Non-current liabilities $ (86)
Cumulative effect on hedged debt
Current debt $ 29 
Non-current debt $ 86 
(d) Counterparty credit risk management
NYSEG and RG&E face risks related to counterparty performance on hedging contracts due to counterparty credit default. We have developed a matrix of unsecured credit thresholds that are applicable based on the respective counterparty’s or the counterparty guarantor’s credit rating, as provided by Moody’s or Standard & Poor’s. When our exposure to risk for a counterparty exceeds the unsecured credit threshold, the counterparty is required to post additional collateral or we will no longer transact with the counterparty until the exposure drops below the unsecured credit threshold.
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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, 2023, UI would have had to post an aggregate of approximately $46 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 $63 million and $97 million as of December 31, 2023 and 2022, 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, 2023 is $34 million, 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 50 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, 2023, 2022 and 2021 were as follows:
For the Year Ended December 31, 2023 2022 2021
(Millions)
Lease cost
Finance lease cost
Amortization of right-of-use assets $ 11  $ 12  $ 8 
Interest on lease liabilities 3  3  3 
Total finance lease cost 14  15  11 
Operating lease cost 18  20  14 
Short-term lease cost 8  6  4 
Variable lease cost 3  3  4 
Total lease cost $ 43  $ 44  $ 33 
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Balance sheet and other information as of December 31, 2023 and 2022 was as follows:
As of December 31, 2023 2022
(Millions, except lease term and discount rate)
Operating Leases
Operating lease right-of-use assets $ 195  $ 159 
Operating lease liabilities, current 16  13 
Operating lease liabilities, long-term 199  161 
Total operating lease liabilities $ 215  $ 174 
Finance Leases
Other assets $ 132  $ 143 
Other current liabilities 28  7 
Other non-current liabilities 53  80 
Total finance lease liabilities $ 81  $ 87 
Weighted-average Remaining Lease Term (years)
Finance leases 5.6 6.4
Operating leases 20.8 16.9
Weighted-average Discount Rate
Finance leases 3.39  % 3.46  %
Operating leases 4.19  % 3.69  %
For the years ended December 31, 2023, 2022 and 2021 supplemental cash flow information related to leases was as follows:
For the Year Ended December 31, 2023 2022 2021
(Millions)
Cash paid for amounts included in the measurement of lease liabilities:
Operating cash flows from operating leases $ 16  $ 14  $ 16 
Operating cash flows from finance leases $ 3  $ 1  $ 3 
Financing cash flows from finance leases $ 6  $ 9  $ 6 
Right-of-use assets obtained in exchange for lease obligations:
Finance leases $ —  $ (1) $ — 
Operating leases $ 55  $ 25  $ 10 
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As of December 31, 2023, maturities of lease liabilities were as follows:
Finance Leases Operating Leases
(Millions)
Year ending December 31,
2024 $ 30  $ 21 
2025 8  17 
2026 9  17 
2027 10  19 
2028 19  16 
Thereafter 14  257 
Total lease payments 90  346 
Less: imputed interest (9) (131)
Total $ 81  215 
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 $39 million and $41 million at December 31, 2023 and December 31, 2022, 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. During 2022, Renewables elected not to exercise the early buyout option and prospectively adjusted the accounting for the lease, which contains a buyout option at fair value at the end of the lease term. 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 of 9.2%. CMP and UI are NETOs with assets and service rates that are governed by the OATT and will thereby be affected by any FERC order resulting from the filed complaint.
On December 26, 2012, a second related complaint for a subsequent rate period was filed requesting the ROE be reduced to 8.7%. On July 31, 2014, a third related complaint was filed for a subsequent rate period requesting the ROE be reduced to 8.84%. On April 29, 2016, a fourth complaint was filed for a rate period subsequent to prior complaints requesting the base ROE be 8.61% and ROE Cap be 11.24%.
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 FERC. We cannot predict the final outcome of the proceedings.
Customer Service Invoice Dispute
On May 4, 2021, Nike USA, Inc. (Nike), the buyer under a virtual PPA with a subsidiary of Renewables, provided notice that it disagrees with the settlement amounts included in certain invoices. The PPA provides for a monthly settlement between the parties based on the metered output of the project based on a stated hub price. The disagreement relates as to the appropriate hub price to use for settlement calculations, most notably during Winter Storm Uri in February of 2021. Nike has requested an adjustment to the invoices that would increase the amount payable by approximately $31 million. Renewables has responded that the invoices have been properly calculated in accordance with the provisions of the PPA, and that Nike is not entitled to any further payments. On June 16, 2023, Nike filed suit against the Company and certain subsidiaries of Renewables alleging breach of contract, and seeking more than $31 million in invoice adjustments, fees, and interest.
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The Company filed a motion to dismiss the complaint, which the Circuit Court of the State of Oregon for the County of Multnomah denied on October 25, 2023 following oral arguments. The case is currently proceeding with an expected trial beginning on October 14, 2024. We cannot predict the outcome of this matter.
Commonwealth Wind and Park City PPAs
In October 2022, Commonwealth Wind and Park City Wind announced that they would seek to re-negotiate the price of the certain Power Purchase Agreements, or PPAs, to help mitigate the impacts of inflation, increased interest rates and supply chain disruptions on the projects.
On October 21, 2022, Commonwealth Wind filed a motion with the DPU seeking a one-month suspension in the DPU’s proceeding to review the power purchase agreements between Commonwealth Wind and the Massachusetts electric distribution companies, or EDCs, in order to provide an opportunity for Commonwealth Wind, the EDCs, state and regulatory officials, and other stakeholders to evaluate the current economic challenges facing Commonwealth Wind and assess measures that would return the project to economic viability including, but not limited to, certain amendments to the Power Purchase Agreements, or PPAs. In December 2022, Commonwealth Wind filed a motion opposing approval of the PPAs by the DPU and requesting that the proceeding be dismissed. On December 30, 2022, the DPU entered an order denying Commonwealth Wind’s motion and approving the PPAs. On January 30, 2023, Commonwealth Wind appealed the DPU’s December 30th order to the Supreme Judicial Court of Massachusetts. On July 13, 2023, each of the EDCs filed with the DPU a first amendment, termination agreement and release agreed with Commonwealth Wind, providing for an orderly termination of the PPAs, withdrawal of Commonwealth Wind’s appeal, and payment by Commonwealth Wind of a $48 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs in connection with the regulatory approval that is under appeal. The DPU approved the termination agreements on August 2, 2023 and Commonwealth Wind dismissed its appeal of the DPU’s December 30th order.
On October 2, 2023, Park City Wind entered into a first amendment, termination agreement and release with each of the Connecticut EDCs, providing for an orderly termination of the Park City Wind PPAs and payment by Park City Wind of an approximately $16 million termination payment to the EDCs, an amount equal to the development period security provided for in the PPAs. On October 13, 2023, PURA approved the termination agreements.
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, BGC and MNG (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.
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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, 2023.
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), (iii) fixed priced energy purchases to cover firming & shaping commitments and (iv) fixed price REC purchases to supply merchant REC sales. 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 2023 was $1 million.
Renewables also has easement contracts which are included in the table below under purchases.
Forward purchases and sales commitments under power, gas and other arrangements as of December 31, 2023 consisted of:
Year Purchases Sales
(Millions)
2024 $ 1,513  $ 285 
2025 246  161 
2026 116  58 
2027 83  34 
2028 51  6 
Thereafter 1,005  56 
Totals $ 3,014  $ 600 
Guarantee Commitments to Third Parties
As of December 31, 2023, we had approximately $911 million of standby letters of credit, surety bonds, guarantees and indemnifications outstanding. We also provided a guaranty related to Renewables' commitment to contribute equity to Vineyard Wind and an indemnification of Vineyard Wind tax equity investors as described in Note 22, which are 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, 2023, 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. 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 $10 million was paid through the end of 2023.
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.
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Waste sites
The Environmental Protection Agency and various state environmental agencies, as appropriate, have notified us that we are among the potentially responsible parties that may be liable for costs incurred to remediate certain hazardous substances at twenty-four waste sites, which do not include sites where gas was manufactured in the past. Sixteen of the twenty-four sites are included in the New York State Registry of Inactive Hazardous Waste Disposal Sites; two sites are included in Maine’s Uncontrolled Sites Program; and one site is included on the Massachusetts Non-Priority Confirmed Disposal Site list. The remaining sites are not included in any registry list. Finally, five of the twenty-four sites are also included on the National Priorities list. Any liability may be joint and several for certain sites.
We have recorded an estimated liability of $6 million related to six of the twenty-four sites. We have paid remediation costs related to the remaining eighteen sites and do not expect to incur additional liabilities. Additionally, we have recorded an estimated liability of $10 million related to another ten 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, 2023, our estimate for costs to remediate these sites ranges from $15 million to $22 million. Factors affecting the estimated remediation amount include the remedial action plan selected, the extent of site contamination and the allocation of the clean-up costs.
Manufactured Gas Plants
We have a program to investigate and perform necessary remediation at our fifty-three sites where gas was manufactured in the past (Manufactured Gas Plants, or MGPs). Six sites are included in the New York State Registry, thirty-nine sites are included in the New York State Department of Environmental Conservation (NYSDEC) Multi-Site Order of Consent; two sites with individual NYSDEC Orders of Consent; two sites under a Brownfield Cleanup Program and two sites are included in Maine Department of Environmental Protection programs (none in the Voluntary Response Action Program, Brownfield Cleanup Program and Uncontrolled Sites Program). The remaining sites are not included in a formal program. We have entered into consent orders with various environmental agencies to investigate and, where necessary, remediate forty-one of the fifty-three sites.
As of December 31, 2023, our estimate for all costs related to investigation and remediation of the fifty-three sites ranges from $122 million to $218 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 of 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, 2023, no liability was recorded related to these sites and no amount of loss, if any, can be reasonably estimated at this time. In the past, the companies have received approval for the recovery of MGP-related remediation expenses from customers through rates and will seek recovery in rates for ongoing MGP-related remediation expenses for all of their MGP sites.
As of both December 31, 2023 and 2022, the liability associated with our MGP sites in Connecticut was $112 million, the remediation costs of which could be significant and will be subject to a review by PURA as to whether these costs are recoverable in rates.
As of December 31, 2023 and 2022, our total recorded liability to investigate and perform remediation at all known inactive MGP sites discussed above and other sites was $250 million and $289 million, respectively. We recorded a corresponding regulatory asset, net of insurance recoveries and the amount collected from FirstEnergy, as described below, because we expect to recover the net costs in rates. Our environmental liability accruals are recorded on an undiscounted basis and are expected to be paid through the year 2058.
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.
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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, 2023, FirstEnergy’s share of clean-up costs owed to NYSEG & RG&E is estimated at approximately $8 million and $6 million, respectively. These amounts are being treated as contingent assets and have not been recorded as either a receivable or a decrease to the environmental provision. Any recovery will be flowed through to NYSEG and RG&E customers, as applicable.
English Station
On August 4, 2016, DEEP issued a partial consent order (the consent order), that requires UI to investigate and remediate certain environmental conditions within the perimeter of a former generation site on the Mill River in New Haven (English Station) that UI sold to Quinnipiac Energy in 2000. 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. UI must comply with the terms of the consent order, but may seek to recover costs above $30 million in consultation with the state. UI continues its activities to investigate and remediate the environmental conditions at the site. In 2023 and 2024, DEEP sent UI a series of letters requesting details on remediation plans and security, which UI has responded to.
On January 25, 2024, DEEP issued a notice of declaratory ruling to determine the “high occupancy standard” necessary “to abate on-site pollution and impacts for industrial/commercial use of the Site…inside the buildings” as referenced in section (B)(1)(e)(4) of the Partial Consent Order. On January 29, 2024, DEEP served UI with a Summons and Complaint seeking injunctive relief and enforcement of the consent order from the Connecticut Superior Court.
As of both December 31, 2023 and 2022, the amount reserved related to English Station was $19 million. Since its inception, we have recorded $35 million to the reserve which has been offset with cash payments over time. We cannot predict the outcome of these proceedings.
Eagle Takings Inquiry
In April 2023, Avangrid Renewables received a letter from the U.S. Fish and Wildlife Service regarding certain bald and gold eagle fatalities that allegedly occurred at certain Avangrid Renewables facilities that are not covered by an eagle take permit. Avangrid Renewables has responded to the U.S. Fish and Wildlife Service providing information about the relevant eagle taking permit applications and relevant mitigation activity at each facility. We cannot predict the outcome of this preliminary inquiry.
Note 16. Income Taxes
In August 2022, the Inflation Reduction Act of 2022 (IRA) was signed into United States law. The IRA created a new corporate alternative minimum tax (CAMT) of 15% on adjusted financial statement income and an excise tax of 1% on the value of certain stock repurchases. The IRA also contains several additional provisions related to tax incentives for investments in renewable energy production, carbon capture, and other climate actions. The CAMT and other various provisions of the IRA are effective for periods beginning after December 31, 2022. The Company paid $32 million of CAMT in 2023, comprised of an estimated $129 million of gross initial obligation; partially offset by $97 million of tax credit utilization. The Company also established an equivalent $129 million, unlimited lived gross CAMT carryforward asset which will be available in future periods to offset regular income tax that exceeds CAMT.
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 Average Rate Assumption Method (ARAM) and Reverse South Georgia (RSG) methodologies.
Current and deferred taxes charged to expense for the years ended December 31, 2023, 2022 and 2021 consisted of:
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Years Ended December 31, 2023 2022 2021
(Millions)      
Current      
Federal $ 36  $ —  $ 6 
State (1) 2  4 
Current taxes charged to expense 35  2  10 
Deferred
Federal 62  67  49 
State (8) 49  72 
Deferred taxes charged to expense 54  116  121 
Production tax credits (97) (97) (109)
Investment tax credits (1) (1) (1)
Total Income Tax (Benefit) Expense $ (9) $ 20  $ 21 
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, 2023, 2022 and 2021 consisted of:
Years Ended December 31, 2023 2022 2021
(Millions)      
Tax expense at federal statutory rate $ 138  $ 176  $ 140 
Depreciation and amortization not normalized (27) (20) (19)
Investment tax credit amortization (1) (1) (1)
Tax return related adjustments (4) 2  — 
Production tax credits (97) (97) (109)
Tax equity financing arrangements 26  13  14 
State tax (benefit) expense, net of federal effect (7) 40  61 
Excess ADIT amortization (35) (66) (65)
Valuation allowance —  (35) 21 
Other, net (2) 8  (21)
Total Income Tax (Benefit) Expense $ (9) $ 20  $ 21 
Deferred tax assets and liabilities as of December 31, 2023 and 2022 consisted of:
As of December 31, 2023 2022
(Millions)    
Deferred Income Tax Liabilities (Assets)    
Property related $ 4,650  $ 4,504 
Unfunded future income taxes 141  129 
Federal and state tax credits (986) (942)
Federal and state NOL’s (1,308) (1,086)
Joint ventures/partnerships 244  210 
Nontaxable grant revenue (250) (270)
Tax Act - tax on regulatory remeasurement (317) (328)
Valuation allowance 82  87 
Other 180  (91)
Deferred Income Tax Liabilities $ 2,436  $ 2,213 
Deferred tax assets $ 2,861  $ 2,717 
Deferred tax liabilities 5,297  4,930 
Net Accumulated Deferred Income Tax Liabilities $ 2,436  $ 2,213 
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As of December 31, 2023, we had gross federal tax net operating losses of $4.7 billion, federal PTCs and ITCs, R&D and other federal credits of $948 million, state tax effected net operating losses of $401 million in several jurisdictions and miscellaneous state tax credits of $145 million available to carry forward and reduce future income tax liabilities. The federal net operating losses begin to expire in 2028, while the federal tax credits begin to expire in 2024. 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, 2023 and 2022 was $82 million and $87 million, respectively. The $5 million decrease is related to state net operating losses and tax credit carryforwards. The $82 million balance as of December 31, 2023 includes federal net operating loss and tax credit carryforward valuation allowance of $3 million and state net operating loss and state tax credit carryforward valuation allowance of $79 million.
The reconciliation of unrecognized income tax benefits for the years ended December 31, 2023, 2022 and 2021 consisted of:
Years ended December 31, 2023 2022 2021
(Millions)      
Beginning Balance $ 127  $ 127  $ 127 
Increases for tax positions related to prior years 7  2  3 
Increases for tax positions related to current year —  2  — 
Decreases for tax positions related to prior years (4) (4) (3)
Ending Balance $ 130  $ 127  $ 127 
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, 2023, 2022 and 2021. If recognized, $109 million of the total gross unrecognized tax benefits would affect the effective tax rate. Within the next twelve months, Avangrid could resolve $83 million of various state uncertainties under appeal, of which, the entire amount if recognized, would reduce the effective tax rate. An estimated range of impact to Avangrid’s earnings related to uncertain tax benefit changes in the next twelve months cannot be made.
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, 2023, 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.
In 2023, Avangrid executed an agreement to transfer the production tax credits generated in 2023 pursuant to the transferability provisions of the Inflation Reduction Act of 2022. Avangrid received cash of $81 million for the transfer of tax credits for the year ended December 31, 2023.
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.
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Qualified Retirement Benefit Plans
As of December 31, 2023 and 2022, our obligations and funded status consisted of:
  Pension Benefits Postretirement Benefits
As of December 31, 2023 2022 2023 2022
(Millions)        
Change in benefit obligation        
Benefit Obligation as of January 1, $ 2,452  $ 3,487  $ 284  $ 408 
Service cost 6  27  1  2 
Interest cost 121  111  14  10 
Plan amendments —  1  —  — 
Actuarial loss (gain) 131  (716) 36  (103)
Curtailments/Settlements (2) (274) —  — 
Benefits paid (208) (184) (34) (33)
Benefit Obligation as of December 31, 2,500  2,452  301  284 
Change in plan assets
Fair Value of Plan Assets as of January 1, 2,151  3,079  89  127 
Actual return on plan assets 204  (584) 12  (22)
Employer contributions 14  22  16  17 
Settlements (2) (182) —  — 
Benefits paid (208) (184) (34) (33)
Fair Value of Plan Assets as of December 31, 2,159  2,151  83  89 
Funded Status as of December 31, $ (341) $ (301) $ (218) $ (195)
During 2023, the pension and postretirement benefit obligations had actuarial losses of, respectively, $131 million and $36 million, primarily due to losses from discount rate decreases of $112 million and $12 million, respectively.
During 2022, the pension and postretirement benefit obligations had actuarial gains of, respectively, $716 million and $103 million, primarily due to gains from discount rate increases of $644 million and $70 million, respectively. The pension benefit obligation had a reduction of $274 million from settlements ($182 million) and curtailments ($92 million). The settlements were lump-sum payments made within the pension plan guidelines at the discretion of the plan participants who opted to retire. The curtailments were driven by a Company decision to freeze pension benefit accruals and contribution credits for Networks non-union employees and transition their retirement benefits to a 401(k) plan.
As of December 31, 2023 and 2022, funded status amounts recognized on our consolidated balance sheets consisted of:
  Pension Benefits Postretirement Benefits
As of December 31, 2023 2022 2023 2022
(Millions)        
Current liabilities $ —  $ —  $ (5) $ (5)
Non-current liabilities (341) (301) (213) (190)
Total $ (341) $ (301) $ (218) $ (195)
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.
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Amounts recognized as a component of regulatory assets or regulatory liabilities for Networks for the years ended December 31, 2023 and 2022 consisted of:
  Pension Benefits Postretirement Benefits
Years Ended December 31, 2023 2022 2023 2022
(Millions)        
Net loss (gain) $ 251  $ 181  $ (52) $ (91)
Prior service cost (credit) $ 6  $ 7  $ (1) $ (1)
Amounts recognized in OCI for ARHI for the years ended December 31, 2023 and 2022, consisted of:
  Pension Benefits Postretirement Benefits
Years Ended December 31, 2023 2022 2023 2022
(Millions)        
Net loss (gain) $ 11  $ 12  $ (4) $ (6)
As of December 31, 2023 and 2022, the projected benefit obligation (PBO) and accumulated benefit obligation (ABO) exceeded the fair value of pension plan assets for all qualified plans. 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, 2023 2022
(Millions)    
Projected benefit obligation $ 2,500  $ 2,452 
Fair value of plan assets $ 2,159  $ 2,151 
ABO in excess of plan assets
As of December 31, 2023 2022
(Millions)    
Accumulated benefit obligation $ 2,479  $ 2,429 
Fair value of plan assets $ 2,159  $ 2,151 
As of December 31, 2023 and 2022, 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, 2023, 2022 and 2021 consisted of:
Pension Benefits Postretirement Benefits
For the years ended December 31, 2023 2022 2021 2023 2022 2021
(Millions)
Net Periodic Benefit Cost:            
Service cost $ 5  $ 26  $ 39  $ 1  $ 2  $ 3 
Interest cost 119  109  86  14  10  10 
Expected return on plan assets (143) (162) (199) (5) (6) (7)
Amortization of prior service cost (benefit) 1  1  2  —  (1) (5)
Amortization of net loss 3  49  115  (12) (4) 2 
Settlement charge —  17  6  —  —  — 
Curtailment charge —  (32) —  —  —  — 
Net Periodic Benefit Cost (15) 8  49  (2) 1  3 
Other changes in plan assets and benefit obligations recognized in regulatory assets and regulatory liabilities:
Curtailments —  (59) —  —  —  — 
Settlement charge —  (17) (6) —  —  — 
Net loss (gain) 73  33  (218) 26  (75) (31)
Amortization of net loss (3) (49) (115) 12  4  (2)
Current year prior service cost (credit) —  1  2  —  —  1 
Amortization of prior service (cost) benefit (1) (1) (2) —  1  5 
Total Other Changes 69  (92) (339) 38  (70) (27)
Total Recognized $ 54  $ (84) $ (290) $ 36  $ (69) $ (24)
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, 2023, 2022 and 2021 consisted of:
Pension Benefits Postretirement Benefits
For the years ended December 31, 2023 2022 2021 2023 2022 2021
(Millions)
Net Periodic Benefit Cost:            
Service cost $ 1  $ 1  $ 1  $ —  $ —  $ — 
Interest cost 2  2  1  —  —  — 
Expected return on plan assets (2) (2) (2) —  —  — 
Amortization of net loss (gain) —  1  2  (1) (1) (1)
Settlement/Curtailment charge 1  1  1  —  —  — 
Net Periodic Benefit Cost 2  3  3  (1) (1) (1)
Other Changes in plan assets and benefit obligations recognized in OCI:
Settlement charge (1) (1) (1) (1) (1) (1)
Net loss (gain) —  (1) (3) 1  (1) 1 
Amortization of net (loss) gain —  (1) (2) 1  1  1 
Amortization of prior service cost —  —  —  —  —  — 
Total Other Changes (1) (3) (6) 1  (1) 1 
Total Recognized $ 1  $ —  $ (3) $ —  $ (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. 
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The weighted-average assumptions used to determine our benefit obligations as of December 31, 2023 and 2022 consisted of:
  Pension Benefits Postretirement Benefits
As of December 31, 2023 2022 2023 2022
Discount rate 4.69  % 5.18  % 4.66  % 5.12  %
Rate of compensation increase 2.60  % 2.99  % 3.00  % 3.00  %
Interest crediting rate 3.37  % 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, 2023, 2022 and 2021 consisted of:
  Pension Benefits Postretirement Benefits
Years Ended December 31, 2023 2022 2021 2023 2022 2021
Discount rate 5.18  % 2.85  % 2.34  % 5.12  % 2.66  % 2.19  %
Expected long-term return on plan assets 6.35  % 6.33  % 7.30  % 5.61  % 4.66  % 4.05  %
Rate of compensation increase 2.99  % 3.53  % 3.52  % 3.00  % 3.50  % 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, 2023 and 2022 consisted of:
As of December 31, 2023 2022
Health care cost trend rate assumed for next year
6.20%/8.60%
5.00%/6.50%
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
2032 / 2028
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 $28 million and $8 million, respectively, to our pension and other postretirement benefit plans during 2024.
Estimated Future Benefit Payments
Expected benefit payments as of December 31, 2023 consisted of:
(Millions) Pension Benefits Postretirement Benefits Medicare Act Subsidy Receipts
2024 $ 235  $ 28  $ — 
2025 $ 221  $ 28  $ — 
2026 $ 216  $ 27  $ — 
2027 $ 210  $ 26  $ — 
2028 $ 204  $ 25  $ — 
2029 - 2033
 $ 918  $ 109  $ 2 
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 $41 million and $44 million at December 31, 2023 and 2022, 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 target allocations to the estimated funded status of each specific plan. Return-Seeking assets range from 15%-70% and Liability-Hedging assets range from 30%-85%. 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.
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The fair values of pension plan assets, by asset category, as of December 31, 2023, consisted of:
As of December 31, 2023 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category        
Cash and cash equivalents $ 63  $ —  $ 63  $ — 
U.S. government securities 295  295  —  — 
Common stocks 58  58  —  — 
Registered investment companies 106  106  —  — 
Corporate bonds 746  —  746  — 
Common collective trusts 708  —  708  — 
Other, principally annuity, fixed income 6  —  6  — 
$ 1,982  $ 459  $ 1,523  $ — 
Other investments measured at net asset value 177 
Total $ 2,159 
The fair values of pension plan assets, by asset category, as of December 31, 2022, consisted of:
As of December 31, 2022 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category        
Cash and cash equivalents $ 51  $ —  $ 51  $ — 
U.S. government securities 252  252  —  — 
Common stocks 57  57  —  — 
Registered investment companies 104  104  —  — 
Corporate bonds 708  —  708  — 
Preferred stocks 1  1  —  — 
Common collective trusts 472  —  472  — 
Other, principally annuity, fixed income 33  —  33  — 
$ 1,678  $ 414  $ 1,264  $ — 
Other investments measured at net asset value 473 
Total $ 2,151 
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.
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•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 62% 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.
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The fair values of other postretirement plan assets, by asset category, as of December 31, 2023 consisted of:
As of December 31, 2023 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category        
Cash and cash equivalents $ 2  $ —  $ 2  $ — 
U.S. government securities 1  1  —  — 
Common stocks 1  1  —  — 
Registered investment companies 61  61  —  — 
Corporate bonds 3  —  3  — 
Common collective trusts 5  —  5  — 
Other, principally annuity, fixed income 8  —  8  — 
$ 81  $ 63  $ 18  $ — 
Other investments measured at net asset value 2 
Total $ 83 
The fair values of other postretirement plan assets, by asset category, as of December 31, 2022 consisted of:
As of December 31, 2022 Fair Value Measurements
(Millions) Total Level 1 Level 2 Level 3
Asset Category        
Cash and cash equivalents $ 2  $ —  $ 2  $ — 
U.S. government securities 1  1  —  — 
Registered investment companies 69  69  —  — 
Corporate bonds 3  —  3  — 
Common collective trusts 4  —  4  — 
Other, principally annuity, fixed income 8  —  8  — 
$ 87  $ 70  $ 17  $ — 
Other investments measured at net asset value 2 
Total $ 89 
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, 2023 and 2022.
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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, 2023, 2022 and 2021, the annual contributions we made to these plans was $84 million, $68 million and $58 million, respectively.
Note 18. Equity
As of December 31, 2023 and 2022, we had 103,889 and 108,188 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2023 and 2022, we issued 138,030 and 56,127 shares of common stock, respectively, and released 4,299 and 4,355 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 relative ownership percentage of approximately 81.5%. The stock repurchase program may be suspended or discontinued at any time upon notice. In 2023, there were no repurchases pursuant to the stock repurchase program. As of December 31, 2023, 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, 2023, the total cost of all repurchases, including commissions, was $47 million.
Accumulated OCI (Loss)
Accumulated OCI (Loss) for the years ended December 31, 2023, 2022 and 2021 consisted of:
Accumulated Other Comprehensive Income (Loss) As of December 31, 2020 2021 Change As of December 31, 2021 2022 Change As of December 31, 2022 2023 Change As of December 31, 2023
(Millions)              
Loss (gain) for defined benefit plans, net of income tax expense of $0 for 2021, $3 for 2022 and $0 for 2023
 $ 2  $ 14  $ — 
Amortization of pension cost, net of income tax (benefit) expense of $(1) for 2021, $1 for 2022 and $0 for 2023
 (8) 4  (1)
Net gain (loss) on pension plans $ (32) $ (6) $ (38) $ 18  $ (20) $ (1) $ (21)
Unrealized (loss) gain from equity method investment, net of income tax (benefit) expense of $(3) for 2021, $6 for 2022 and $1 for 2023 (a)
 $ —  $ (9) $ (9) $ 22  $ 13  $ 5  $ 18 
Unrealized loss during period on derivatives qualifying as cash flow hedges, net of income tax (benefit) expense of $(44) for 2021, $0 for 2022 and $6 for 2023
 (35) (159) (194) (1) (195) 17  (178)
Reclassification to net income of losses (gains) on cash flow hedges, net of income tax (benefit) expense of $(3) for 2021, $19 for 2022 and $48 for 2023 (b)
 (44) 12  (32) 54  22  134  156 
Loss on derivatives qualifying as cash flow hedges (79) (147) (226) 53  (173) 151  (22)
Accumulated Other Comprehensive Loss $ (111) $ (162) $ (273) $ 93  $ (180) $ 155  $ (25)
(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. During the years ended December 31, 2023 and 2021, while we did have securities that were dilutive, these securities did not result in a change in our earnings per share calculations for the years ended December 31, 2023 and 2021.
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The dilutive securities, which consist of performance and restricted units, did result in a change in our earnings per share calculation for the year ended December 31, 2022.
The calculations of basic and diluted earnings per share attributable to Avangrid for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of:
Years Ended December 31, 2023 2022 2021
(Millions, except for number of shares and per share data)      
Numerator:      
Net income attributable to Avangrid
 $ 786  $ 881  $ 707 
Denominator:
Weighted average number of shares outstanding - basic 386,810,088  386,727,246  358,086,621 
Weighted average number of shares outstanding - diluted 387,164,874  387,215,785  358,578,608 
Earnings per share attributable to Avangrid
Earnings Per Common Share, Basic $ 2.03  $ 2.28  $ 1.97 
Earnings Per Common Share, Diluted $ 2.03  $ 2.27  $ 1.97 
Note 20. Variable Interest Entities
We participate in certain partnership arrangements that qualify as VIEs. These arrangements consist of tax equity financing arrangements (TEFs) and partnerships in which an investor holds a noncontrolling interest and does not have substantive kick-out or participating rights.
The sale of a membership interest in the TEFs represents the sale of an equity interest in a structure that is considered a sale of non-financial assets. Under the sale of non-financial assets, the membership interests in the TEFs we sell to third-party investors are reflected as noncontrolling interest on our condensed consolidated balance sheets valued based on an HLBV model. Earnings from the TEFs are recognized in net income attributable to noncontrolling interests in our condensed consolidated statements of income. We consolidate the entities that have TEFs based on being the primary beneficiary for these VIEs.
On September 9, 2021, we sold an additional TEF interest in Aeolus Wind Power VII, LLC (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 was held in escrow until certain conditions were met on August 10, 2022. The two wind farms are the first in a portfolio of companies called Aeolus Wind Power VIII, LLC (Aeolus VIII).
On April 29, 2022, we closed on one TEF agreement, receiving $14 million from a tax equity investor related to one solar facility. The solar facility is the first in a portfolio of companies called Solis Solar Power I, LLC (Solis).
On June 15, 2022, we closed on one TEF agreement related with Aeolus VIII, receiving the initial funding of $109 million from one tax equity investor. Two newly constructed facilities, one wind farm and one solar facility, became part of Aeolus VIII.
On March 31, 2023, we received the second funding of $61 million related to Solis I from one tax equity investor.
On November 21, 2023, we received the second funding of $124 million related to Aeolus VIII from one tax equity investor.
As of December 31, 2023, the assets and liabilities of the VIEs totaled approximately $2,741 million and $174 million, respectively.
As of December 31, 2022, the assets and liabilities of VIEs totaled approximately $2,853 million and $424 million, respectively. At both December 31, 2023 and 2022, the assets and liabilities of the VIEs consisted primarily of property, plant and equipment.
Wind and solar power generation are 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 and solar farms. Under these structures, we contribute certain wind / solar assets, relating both to existing wind farms and wind farms / solar facilities 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.
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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 targeted cumulative annual after-tax return. Once this target return is met, the relative sharing of profit or loss, cash distributions and taxable income or loss between the Company and the third party investor flips, with the sponsor generally receiving higher percentages thereafter. We also have a call option to acquire the third party investors’ membership interest within a defined time period after this target return is met.
Our El Cabo, Patriot, Aeolus VII, Aeolus VIII, and Solis I interests are not subject to any rights of investors that may restrict our ability to access or use the assets or to settle any existing liabilities associated with the interests.
See Note 22 - Equity Method Investments for information on our VIEs we do not consolidate.
Note 21. Grants, Government Incentives and Deferred Income
The changes in government grants recorded in deferred income as of December 31, 2023 and 2022 consisted of:
(Millions) Government grants - Renewables Other deferred income Total
As of December 31, 2021 $ 1,125  $ 5  $ 1,130 
Disposals —  —  — 
Recognized in income (65) (3) (68)
As of December 31, 2022 1,060  2  1,062 
Disposals —  —  — 
Recognized in income (65) (1) (66)
As of December 31, 2023 $ 995  $ 1  $ 996 
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) provided 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).
The changes in government grants recorded as a reduction to the related utility plant as of December 31, 2023 and 2022 consisted of:
(Millions) Government grants - Networks Total
As of December 31, 2021 $ 63  $ 63 
Disposals —  — 
Recognized in income (4) (4)
As of December 31, 2022 59  59 
Disposals —  — 
Recognized in income (5) (5)
As of December 31, 2023 $ 54  $ 54 
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 government. We believe we are in compliance with each grant’s terms and conditions as of December 31, 2023 and 2022.
Note 22. Equity Method Investments
Renewables holds 15% ownership interest in a wind farm located in South Dakota (Tatanka). The investment in Tatanka is accounted for as an equity investment. As of December 31, 2023, and 2022, the carrying value of our Tatanka investment was $22 million and $23 million, respectively.
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Renewables holds 50% ownership interest in a wind farm and a solar project located in Arizona (Poseidon). The investment in Poseidon is accounted for as an equity investment. As of December 31, 2023 and 2022, the carrying value of our Poseidon investment was $77 million and $87 million, respectively.
Renewables holds 20% interest in Coyote Ridge Wind, LLC (Coyote Ridge). The investment in Coyote Ridge is accounted for as an equity investment. As of December 31, 2023 and 2022, the carrying amount of our Coyote Ridge investment was $16 million and $15 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, 2023 and 2022, the carrying amount of Flat Rock I was $81 million and $90 million, respectively, and Flat Rock II was $38 million and $42 million, respectively.
Renewables holds a 50% indirect ownership interest in Vineyard Wind 1, LLC (Vineyard Wind 1), a joint venture with Copenhagen Infrastructure Partners (CIP). Prior to a restructuring transaction that took place on January 10, 2022 (Restructuring Transaction), Renewables held a 50% ownership interest in Vineyard Wind, LLC (Vineyard Wind) which held rights to two easements from the U.S. Bureau of Ocean Energy Management (BOEM) for the development of offshore wind generation, Lease Area 501 which contained 166,886 acres and Lease Area 522 which contained 132,370 acres, both located southeast of Martha’s Vineyard. Lease Area 501 was subdivided in 2021, creating Lease Area 534. On September 15, 2021, Vineyard Wind closed on construction financing for the Vineyard Wind 1 project. Among other items, the Vineyard Wind 1 project was transferred into a separate joint venture, Vineyard Wind 1. Following the Restructuring Transaction, Vineyard Wind 1 remained a 50-50 joint venture and kept the rights to develop Lease Area 501, and Vineyard Wind was effectively dissolved where Renewables received rights to the Lease Area 534 and CIP received rights to Lease Area 522 as liquidating distributions. In contemplation of the liquidating distributions, Renewables also made an incremental payment of approximately $168 million to CIP. Consequently, Renewables recognized a pretax gain of $246 million and an after tax gain of $181 million, driven by the increase in the fair value of its acquired interest in the leases and related development activities over its carrying value. The gain is classified in Earnings from equity method investments in the condensed consolidated statement of income for the year ended December 31, 2022.
Concurrently with the closing on the construction financing for the Vineyard Wind 1 project, Renewables entered into a credit agreement with certain banks to provide future term loans and letters of credit up to a maximum of approximately $1.2 billion to finance a portion of its share of the cost of Vineyard Wind 1 at the maturity of the Vineyard Wind 1 project construction loan. Any term loans mature by October 15, 2031, subject to certain extension provisions. Renewables also entered into an Equity Contribution Agreement in which Renewables agreed to, among other things, make certain equity contributions to fund certain costs of developing and constructing the Vineyard Wind 1 project in accordance with the credit agreement. In addition, we issued a guaranty up to $827 million for Renewables' equity contributions under the Equity Contribution Agreement. As part of the Vineyard Wind 1 financial close, $152 million of Renewables prior contributions for the Vineyard Wind 1 project were returned in 2021.
On October 24, 2023, Vineyard Wind 1 closed on a TEF agreement, pursuant to which Vineyard Wind 1 is expected to receive approximately $1.2 billion from tax equity investors in installments based on the number of turbines reaching or about to reach mechanical completion each month until the entire project reaches commercial operation date. As of December 31, 2023, Vineyard Wind 1 received the initial funding of $85 million from tax equity investors. The remaining $1.1 billion is expected to be received in 2024. In conjunction with the equity installments received since the closing of the TEF agreement, we have issued an indemnification of our joint share of the investor contributions. As of December 31, 2023, our total indemnified amount was $43 million.
Vineyard Wind 1 is considered a VIE because it cannot finance its activities without additional support from its owners or third parties. Renewables is not the primary beneficiary of the entity since it does not have a controlling financial interest, and therefore we do not consolidate this entity. During 2023, Renewables made a capital contribution of $287 million to Vineyard Wind 1. As of December 31, 2023 and 2022, the carrying amount of Renewables' investments in Vineyard Wind, which was dissolved in 2022, and Vineyard Wind 1 was $297 million and $9 million, respectively.
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, 2023 and 2022, the carrying value of our GenConn investment was $90 million and $94 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.
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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. The investment in New York TransCo is accounted for as an equity investment. As of December 31, 2023 and 2022, the carrying value of our New York TransCo investment was $97 million and $77 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 $37 million, $41 million and $21 million for the years ended December 31, 2023, 2022 and 2021 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, 2023, 2022 and 2021, we received $11 million, $12 million and $11 million of distributions in RECs from our equity method investments. As of December 31, 2023, there was $9 million of undistributed earnings from our equity method investments. Capitalized interest costs related to equity method investments were $2 million, $0 and $6 million for the years ended December 31, 2023, 2022 and 2021, respectively.
Note 23. Other Financial Statement Items
Other income (expense)
Other income (expense) for the years ended December 31, 2023, 2022 and 2021 consisted of:
Years ended December 31, 2023 2022 2021
(Millions)      
Allowance for funds used during construction 82  63  88 
Carrying costs on regulatory assets 17  16  17 
Non-service component of net periodic benefit cost 22  (58) (37)
Other 8  9  (8)
Total Other Income $ 129  $ 30  $ 60 
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Accounts receivable and unbilled revenues, net
Accounts receivable and unbilled revenues, net as of December 31, 2023 and 2022 consisted of:
As of December 31, 2023 2022
(Millions)    
Trade receivables and unbilled revenues $ 1,749  $ 1,892 
Allowance for credit losses (161) (155)
Total Accounts receivable and unbilled revenues, net $ 1,588  $ 1,737 
The change in the allowance for credit losses as of December 31, 2023 and 2022 consisted of:
(Millions)  
As of December 31, 2020 $ 108 
Current period provision 110 
Write-off as uncollectible (67)
As of December 31, 2021 $ 151 
Current period provision 110 
Write-off as uncollectible (106)
As of December 31, 2022 $ 155 
Current period provision 137 
Write-off as uncollectible (131)
As of December 31, 2023 $ 161 
DPA receivable balances were $110 million and $102 million as of December 31, 2023 and 2022, respectively. As of December 31, 2023 and 2022, our allowance for credit losses for DPAs was $44 million and $42 million, respectively.
Prepayments and Other Current Assets
Prepayments and other current assets as of December 31, 2023 and 2022 consisted of:
As of December 31, 2023 2022
(Millions)    
Prepaid other taxes $ 142  $ 136 
Broker margin and collateral accounts 165  164 
Other pledged deposits 32  12 
Prepaid expenses 74  68 
Other 16  6 
Total $ 429  $ 386 
Other current liabilities
Other current liabilities as of December 31, 2023 and 2022 consisted of:
As of December 31, 2023 2022
(Millions)    
Advances received $ 236  $ 271 
Accrued salaries 184  153 
Short-term environmental provisions 40  54 
Collateral deposits received 128  68 
Pension and other postretirement 6  5 
Finance leases 28  7 
Other 40  35 
Total $ 662  $ 593 
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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 mark-to-market earnings from changes in the fair value of derivative instruments, costs incurred in connection with the COVID-19 pandemic, costs incurred related to the PNMR Merger and other transactions, accelerated depreciation from the repowering of wind farms, and costs incurred in connection with an offshore contract provision.
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, 2023 consisted of:
For the Year Ended December 31, 2023 Networks Renewables Other(a) Avangrid Consolidated
(Millions)
Revenue - external $ 6,850  $ 1,456  $ 3  $ 8,309 
Revenue - intersegment 5  —  (5) — 
Depreciation and amortization 694  456  8  1,158 
Operating income 996  (45) (21) 930 
Earnings (losses) from equity method investments 15  (9) —  6 
Interest expense, net of capitalization 287  16  106  409 
Income tax expense (benefit) 141  (67) (83) (9)
Capital expenditures 2,192  768  12  2,972 
Adjusted net income 727  163  (82) 808 
As of December 31, 2023
Property, plant and equipment 21,692  11,153  12  32,857 
Equity method investments 186  532  —  718 
Total assets $ 30,413  $ 14,538  $ (962) $ 43,989 
(a)Includes Corporate and intersegment eliminations.
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Segment information as of and for the year ended December 31, 2022 consisted of:
For the year ended December 31, 2022 Networks Renewables Other(a) Avangrid Consolidated
(Millions)
Revenue - external $ 6,781  $ 1,141  $ 1  $ 7,923 
Revenue - intersegment 1  —  (1) — 
Depreciation and amortization 660  424  1  1,085 
Operating income 901  (36) (13) 852 
Earnings (losses) from equity method investments 11  251  —  262 
Interest expense, net of capitalization 220  16  67  303 
Income tax expense (benefit) 94  (114) 40  20 
Capital expenditures 1,803  708  8  2,519 
Adjusted net income 628  403  (130) 901 
As of December 31, 2022
Property, plant and equipment 20,027  10,950  17  30,994 
Equity method investments 171  266  —  437 
Total assets $ 28,069  $ 13,553  $ (499) $ 41,123 
(a)Includes Corporate and intersegment eliminations.
Segment information 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 
(a)Includes Corporate and intersegment eliminations.
Reconciliation of Adjusted Net Income to Net Income attributable to Avangrid for the years ended December 31, 2023, 2022 and 2021 is as follows:
Years Ended December 31, 2023 2022 2021
(Millions)    
Adjusted Net Income Attributable to Avangrid, Inc. $ 808  $ 901  $ 780 
Adjustments:
Mark-to-market adjustments - Renewables (1) 21  —  (53)
Impact of COVID-19 (2) —  —  (34)
Merger and other transaction costs (3) (11) (4) (12)
Offshore contract provision (4) (40) (24) — 
Accelerated depreciation from repowering (5) (1) —  — 
Income tax impact of adjustments 8  7  26 
Net Income Attributable to Avangrid, Inc. $ 786  $ 881  $ 707 
(1)Mark-to-market earnings relates to earnings impacts from changes in the fair value of Renewables' derivative instruments associated with electricity and natural gas.
(2)Represents costs incurred in connection with the COVID-19 pandemic, mainly related to bad debt provisions.
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(3)Pre-merger and other transaction costs incurred.
(4)Costs incurred in connection with an offshore contract provision.
(5)Represents the amount of accelerated depreciation derived from the repowering of wind farms in Renewables.
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.
Related party transactions for the years ended December 31, 2023, 2022 and 2021, respectively, consisted of:
Years Ended December 31, 2023 2022 2021
(Millions) Sales To Purchases From Sales To Purchases From Sales To Purchases From
Iberdrola, S.A. $ 2  $ (45) $ 1  $ (46) $ —  $ (52)
Iberdrola Renovables Energia, S.L. $ —  $ (8) $ 1  $ (5) $ —  $ (10)
Iberdrola Financiación, S.A.U. $ —  $ (36) $ —  $ (12) $ —  $ (9)
Vineyard Wind 1 $ 12  $ —  $ 7  $ —  $ 14  $ — 
Iberdrola Solutions $ —  $ —  $ —  $ —  $ 7  $ (39)
Other $ —  $ (2) $ 1  $ (3) $ 2  $ (3)
Related party balances as of December 31, 2023 and 2022, respectively, consisted of:
As of December 31, 2023 2022
(Millions) Owed By Owed To Owed By Owed To
Iberdrola, S.A. $ 1  $ —  $ 1  $ (29)
Iberdrola Renovables Energía, S.L. $ 4  $ —  $ —  $ — 
Iberdrola Financiación, S.A.U. $ —  $ (799) $ —  $ (9)
Vineyard Wind 1 $ 6  $ (8) $ 3  $ (8)
Iberdrola Solutions $ —  $ (6) $ —  $ (2)
Other $ 4  $ —  $ 4  $ (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 Intragroup Green 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, 2023 and 2022 was $0.
On June 18, 2023, Avangrid's credit facility with Iberdrola Financiación, S.A.U., a subsidiary of Iberdrola, matured. The facility had a limit of $500 million. On July 19, 2023, we replaced this credit facility with an increased limit of $750 million and a maturity date of June 18, 2028. Avangrid pays a quarterly facility fee of 22.5 basis points (rate per annum) on the facility based on Avangrid’s current Moody’s and S&P ratings for senior unsecured long-term debt. As of both December 31, 2023 and 2022, 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 balances of $6 million and $2 million as of December 31, 2023 and 2022, respectively.
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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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, 2023, the total number of shares authorized for stock-based compensation plans was 2,500,000.
Performance Stock Units
In February 2020, a total number of 208,268 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance metrics related to the 2016 through 2019 plan and are payable in three equal installments, net of applicable taxes. In March 2022, 46,737 shares of common stock were issued to settle the third and final installment payment under this plan.
During 2021 and 2022, 1,336,787 PSUs and 215,235 PSUs, were granted to certain officers and employees of Avangrid with achievement measured based on certain performance and market-based metrics for the 2022 performance period. The PSUs are 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.
In March 2023, a total number of 677,752 PSUs, before applicable taxes, were approved to be earned by participants based on achievement of certain performance and market-based metrics for the 2021 to 2022 performance period and are payable in three equal installments, net of applicable taxes, in 2023, 2024 and 2025. The remaining unvested PSUs were forfeited. The first installment was paid in June 2023, and 125,657 shares of common stock were issued in July 2023 to settle this installment payment.
During 2023, 1,067,500 PSUs were granted to certain executives of Avangrid with achievement measured based on certain performance and market-based metrics for the 2023 to 2025 performance period. The PSUs will be payable in three equal installments, net of applicable taxes, in 2026, 2027 and 2028.
The fair value of the PSUs on the grant date was $25.69 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 five years based on expected achievement.
Restricted Stock Units
In October 2018, pursuant to the Avangrid, Inc. Omnibus Incentive Plan 8,000 restricted stock units (RSUs) were granted to an officer of Avangrid. The RSUs vested in full in one installment in December 2020. The fair value on the grant date was determined based on a price of $47.59 per share. In March 2021, this 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. The RSU grant was settled in March 2023, net of applicable taxes, by issuing 3,642 shares of common stock.
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.
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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.
In June 2022, 25,000 RSUs were granted to an officer of Avangrid. The RSUs vest in two equal installments in 2023 and 2024, provided that the grantee remains continuously employed with Avangrid through the applicable vesting dates. The fair value on the grant date was determined based on a price of $47.64 per share. The first installment of this RSU grant was settled in January 2023, net of applicable taxes, by issuing 8,690 shares of common stock. The second installment of this RSU grant was settled in January 2024, net of applicable taxes, by issuing 9,034 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 March 2022, $2 million was paid to settle the third and final installment under this plan.
In February 2022, 9,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in four equal installments in 2022 - 2024 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement. In August 2022, $0.1 million was paid to settle the first installment, and in February and August 2023, in total $0.2 million was paid to settle the second and third installments under this plan.
In February 2023, 81,000 Phantom Shares were granted to certain Avangrid executives and employees. These awards vest in three equal installments in 2024, 2025 and 2026 and will be settled in a cash amount equal to the number of Phantom Shares multiplied by the closing share price of Avangrid’s common stock on the respective vesting dates, subject to continued employment. The liability of these awards is measured based on the closing share price of Avangrid’s common stock at each reporting date until the date of settlement.
As of December 31, 2023 and 2022, the total liability for phantom share units was $2 million and $0, respectively, which is included in other current and non-current liabilities.
The total stock-based compensation expense, which is included in "Operations and maintenance" of our consolidated statements of income for the years ended December 31, 2023, 2022 and 2021 was $14 million, $15 million and $18 million, respectively. The total income tax benefits recognized for stock-based compensation arrangements for each of the years ended December 31, 2023, 2022 and 2021, were $4 million, $4 million and $5 million, respectively.
A summary of the status of the Avangrid's nonvested PSUs and RSUs as of December 31, 2023, and changes during the fiscal year ended December 31, 2023, is presented below:
  Number of PSUs and RSUs Weighted Average Grant Date Fair Value
Nonvested Balance – December 31, 2022
 1,084,951  $ 36.55 
Granted 1,068,326  $ 29.30 
Forfeited (449,876) $ 35.30 
Vested (244,110) $ 37.43 
Nonvested Balance – December 31, 2023
 1,459,291  $ 31.54 
As of December 31, 2023, total unrecognized costs for non-vested PSUs, RSUs and Phantom Shares was $27 million. The weighted-average period over which the PSU, RSU and Phantom Shares costs will be recognized is approximately 5.2 years.
The weighted-average grant date fair value of PSUs and RSUs granted during the year was $29.30 per share for the year ended December 31, 2023.
Note 27. Subsequent Events
On February 15, 2024, 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, 2024 to shareholders of record at the close of business on March 1, 2024.
158

Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF INCOME
FOR THE YEARS ENDED December 31, 2023, 2022 AND 2021
Years Ended December 31, 2023 2022 2021
(Millions)
Operating Revenues $ —  $ —  $ — 
Operating Expenses
Operating expense 9  11  19 
Taxes other than income taxes 7  (1) (11)
Total Operating Expenses 16  10  8 
Operating (Loss) Income (16) (10) (8)
Other Income
Other income 127  49  22 
Equity earnings of subsidiaries 837  999  756 
Interest expense (248) (117) (93)
Income Before Income Tax 700  921  677 
Income tax (benefit) expense (86) 40  (30)
Net Income $ 786  $ 881  $ 707 
See accompanying notes to Schedule I.
159

Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF COMPREHENSIVE INCOME
FOR THE YEARS ENDED December 31, 2023, 2022, AND 2021
Years Ended December 31, 2023 2022 2021
(Millions)
Net Income $ 786  $ 881  $ 707 
Other comprehensive income (loss) of subsidiaries 155  93  (162)
Comprehensive Income $ 941  $ 974  $ 545 
See accompanying notes to Schedule I.
160

Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
BALANCE SHEETS
AS OF December 31, 2023 AND 2022
As of December 31, 2023 2022
(Millions)
Assets
Current Assets
Cash and cash equivalents $ 11  $ 28 
Accounts receivable from subsidiaries 416  190 
Notes receivable from subsidiaries 1,912  1,440 
Prepayments and other current assets 47  17 
Total current assets 2,386  1,675 
Investments in subsidiaries 22,244  20,588 
Other assets
Deferred income taxes 452  358 
Other 3  3 
Total other assets 455  361 
Total Assets $ 25,085  $ 22,624 
Liabilities
Current Liabilities
Current portion of debt $ 600  $ — 
Notes payable 1,331  396 
Notes payable to subsidiaries 977  557 
Accounts payable and accrued liabilities 1  7 
Accounts payable to subsidiaries 2  3 
Interest accrued 9  9 
Interest accrued subsidiaries 48  9 
Dividends payable 170  170 
Other current liabilities 30  30 
Total current liabilities 3,168  1,181 
Derivative liabilities 63  86 
Non-current debt 1,406  1,977 
Non-current debt with affiliate 800  — 
Total non-current liabilities 2,269  2,063 
Total Liabilities 5,437  3,244 
Equity
Stockholders' Equity:
Common stock 4  3 
Additional paid-in capital 17,701  17,694 
Treasury stock (47) (47)
Retained earnings 2,015  1,910 
Accumulated other comprehensive loss (25) (180)
Total Equity 19,648  19,380 
Total Liabilities and Equity $ 25,085  $ 22,624 
See accompanying notes to Schedule I.
161

Schedule I –Financial Statements of Parent
AVANGRID, INC. (PARENT)
CONDENSED FINANCIAL INFORMATION OF PARENT
STATEMENTS OF CASH FLOWS
FOR THE YEARS ENDED December 31, 2023, 2022, AND 2021
Years Ended December 31, 2023 2022 2021
(Millions)
Net Cash used in Operating Activities $ (298) $ (742) $ (397)
Cash Flow from Investing Activities
Notes receivable from subsidiaries (116) (14) 130 
Investments in subsidiaries (1,263) (1,020) (1,026)
Return of capital from investments in subsidiaries 595  664  1,122 
Other investments —  —  300 
Net Cash (used in) provided by Investing Activities (784) (370) 526 
Cash Flow from Financing Activities
Receipts (repayments) of short-term notes payable from subsidiaries, net 14  1  (186)
Receipts (repayments) of short-term notes payable 935  397  (309)
Proceeds (repayments) from non-current debt with affiliate 800  —  (3,000)
Repurchase of common stock —  —  (33)
Issuance of common stock (3) (1) 3,998 
Dividends paid (681) (681) (613)
Net Cash provided by (used in) Financing Activities 1,065  (284) (143)
Net Decrease in Cash and Cash Equivalents (17) (1,396) (14)
Cash and Cash Equivalents, Beginning of Year 28  1,424  1,438 
Cash and Cash Equivalents, End of Year $ 11  $ 28  $ 1,424 
Supplemental Cash Flow Information      
Cash paid for interest $ 181  $ 86  $ 74 
Cash paid (refunded) payment for income taxes $ 21  $ (33) $ (15)
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 and settles its current tax liability or benefit each year directly with Avangrid pursuant to a tax sharing agreement between Avangrid and our members.
162

Termination of a Material Definitive Agreement
On December 31, 2023, Avangrid sent a notice to PNM Resources, Inc., a New Mexico corporation (PNMR), terminating the previously announced Agreement and Plan of Merger (as amended by the Amendment to Merger Agreement dated January 3, 2022, Amendment No. 2 to the Merger Agreement dated April 12, 2023 and Amendment No. 3 to the Merger Agreement dated June 19, 2023 (Merger Agreement)), pursuant to which NM Green Holdings, Inc. a New Mexico corporation and wholly-owned subsidiary of the corporation (Merger Sub), agreed to merge with and into PNMR (Merger), with PNMR surviving the Merger as a direct wholly-owned subsidiary of Avangrid. A description of the Merger Agreement was included in the Current Reports on Form 8-K filed by Avangrid on October 21, 2020, January 3, 2022, April 12, 2023 and June 20, 2023, and is incorporated herein by reference.
The Merger was conditioned, among other things, upon the receipt of certain required regulatory approvals, including the approval of the New Mexico Public Regulation Commission (NMPRC), and provided that the Merger Agreement may be terminated by either Avangrid or PNMR if the closing of the Merger shall not have occurred by 5:00 PM New York City Time on December 31, 2023 (End Date). Because the required approval of the NMPRC was not received by the End Date and the conditions to the closing of the Merger were thus not satisfied by the End Date, Avangrid exercised its right to terminate the Merger Agreement. No termination penalties were incurred by either party in connection with the termination of the Merger Agreement. The Funding Commitment Letter and related side letter agreement terminated automatically upon termination of the Merger Agreement.
In light of the termination of the Merger Agreement, on January 8, 2024, Avangrid filed a motion to withdraw from the appeal it and PNMR’s subsidiary, Public Service Company of New Mexico (PNM), had filed with the New Mexico Supreme Court with respect to the NMPRC’s December 8, 2021, order which had rejected the amended stipulated agreement entered into by PNM, Avangrid and a number of interveners in the NMPRC proceeding with respect to consideration of the joint Merger application.
Note 2. Common Stock
As of December 31, 2023, Avangrid share capital consisted of 500,000,000 shares of common stock authorized, 387,872,787 shares issued and 386,770,915 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 $4 million and additional paid in capital of $17,701 million. As of December 31, 2022, Avangrid share capital consisted of 500,000,000 shares of common stock authorized, 387,734,757 shares issued and 386,628,586 shares outstanding, 81.6% 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 $17,694 million. As of December 31, 2023 and 2022, we had 103,889 and 108,188 shares of common stock held in trust, respectively, and no convertible preferred shares outstanding. During the years ended December 31, 2023 and 2022, we issued 138,030 and 56,127 shares of common stock, respectively, and released 4,299 and 4,355 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 2023, there were no repurchases pursuant to the stock repurchase program. As of December 31, 2023, 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, 2023, the total cost of all repurchases, including commissions, was $47 million.
On February 15, 2024, 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, 2024 to shareholders of record at the close of business on March 1, 2024.
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.
163

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 in two private placements.
On July 19, 2023, we entered into a green term loan agreement with Iberdrola Financiación, S.A.U., with an aggregate principal amount of $800 million maturing on July 13, 2033 at an interest rate of 5.45% (the Intragroup Green Loan).
Note 4. Cash Dividends Paid by Subsidiaries
Cash dividends paid by subsidiary are as follows:
Years ended December 31, 2023 2022 2021
(millions)      
Avangrid Networks $ 595  $ 645  $ 970 
Avangrid Renewables $ —  $ 19  $ 152 
For the years ended December 31, 2023, 2022 and 2021, Avangrid made capital contributions to Networks of $931 million, $986 million and $1,011 million, respectively.
During 2023 and 2022, Avangrid recorded a net non-cash contribution and dividend of $122 million and $473 million, respectively, to and from its subsidiaries to zero out their account balances of notes receivable and payable.
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.
164

Avangrid's management assessed the effectiveness of Avangrid's internal control over financial reporting as of December 31, 2023. 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, 2023.
Our independent registered public accounting firm that audited the financial statements included in this Form 10-K, KPMG LLP, has issued its report on the effectiveness of 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, 2023 that materially affected, or are reasonably likely to materially affect, our internal control over financial reporting.
Item 9B. Other Information.
Insider Trading Arrangements
During the quarter ended December 31, 2023, no director or executive officer of the Company adopted, modified or terminated a “Rule 10b5-1 trading arrangement” or “non-Rule 10b5-1 trading arrangement,” as each term is defined in Item 408(a) of Regulation S-K.
Item 9C. Disclosure Regarding Foreign Jurisdictions that Prevent Inspections.
Not applicable.
165

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 2024 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.
Avangrid has a code of business conduct and ethics that applies to all employees, officers and directors, including Avangrid’s principal executive officer, principal financial officer, principal accounting officer, directors, and other senior financial officers. The code is intended to provide guidance to employees, management, and the board to regarding compliance with law and to promote ethical behavior. Any amendment to the code, or any waivers of its requirements, will be disclosed if required on the company’s website at www.avangrid.com.
Item 11. Executive Compensation.
The information required by this item is incorporated by reference to our Proxy Statement for the 2024 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.
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 2024 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.
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 2024 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.
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 2024 Annual Meeting of Shareholders to be filed with the SEC within 120 days of the fiscal year ended December 31, 2023.
166

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
   
2.2
2.3
2.4
2.5
3.1
   
3.2
   
4.1
   
4.2
   
4.3
   
4.4
   
167

Exhibit Number Exhibit Description
4.5
   
4.6
   
4.7
   
4.8
4.9
4.10
4.11
4.12
4.13
4.14
10.1
10.2
10.3
10.4
168

Exhibit Number Exhibit Description
10.5
10.6
10.7
10.8
10.9
10.10
10.11
10.12
10.13
10.14
10.15
10.16
169

Exhibit Number Exhibit Description
10.17
10.18
10.19
10.20
10.21
10.22
10.23
10.24
10.25
10.26
10.27
10.28
170

Exhibit Number Exhibit Description
10.29
10.30
10.31
10.32
10.33
10.34
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).
10.35
10.36
10.37
10.38
10.39
171

Exhibit Number Exhibit Description
10.40
10.41
10.42
Amendment No. 2, dated July 17, 2023, to the Revolving Credit Agreement, dated as of November 21, 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 Form 8-K filed with the Securities and Exchange Commission on July 21, 2023).
10.43
10.44
10.45
10.46
10.47
10.48
10.49
10.50
21.1
23.1
31.1
31.2
172

Exhibit Number Exhibit Description
32
97.1
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, 2023, 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.
173

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 22, 2024 By: /s/ Pedro Azagra Blázquez
  Pedro Azagra Blázquez
  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/ Pedro Azagra Blázquez   Director and Chief Executive Officer
(Principal Executive Officer)		   February 22, 2024
Pedro Azagra Blázquez        
/s/ Justin B. Lagasse   Senior Vice President - Chief Financial Officer and Controller
(Principal Financial Officer and Principal Accounting Officer )		   February 22, 2024
Justin B. Lagasse        
/s/ Ignacio S. Galán   Chairman of the Board   February 22, 2024
Ignacio S. Galán        
/s/ John E. Baldacci   Director   February 22, 2024
John E. Baldacci        
/s/ Daniel Alcain López
 Director February 22, 2024
Daniel Alcain López
/s/ Robert Duffy   Director   February 22, 2024
Robert Duffy        
/s/ Teresa Herbert Director   February 22, 2024
Teresa Herbert
/s/ Patricia Jacobs   Director   February 22, 2024
Patricia Jacobs        
/s/ John L. Lahey   Director   February 22, 2024
John L. Lahey        
/s/ Santiago Martínez Garrido   Director   February 22, 2024
Santiago Martínez Garrido        
/s/ José Sáinz Armada   Director   February 22, 2024
José Sáinz Armada        
/s/ Alan D. Solomont   Director   February 22, 2024
Alan D. Solomont        
/s/ Camille Joseph Varlack Director February 22, 2024
Camille Joseph Varlack
/s/ Agustín Delgado Martín Director February 22, 2024
Agustín Delgado Martín
/s/ María Fátima Báñez García Director February 22, 2024
María Fátima Báñez García
174
EX-10.46 2 agr-ex1046x2023.htm EX-10.46 Document

EXHIBIT 10.46

Commercial Paper
ISSUING AND PAYING AGENT AGREEMENT
(Book-Entry and Obligations
Using DTC Facilities)
THIS AGREEMENT (“Agreement”) dated as of September 13, 2022 (“Effective Date”) is entered into by and between Avangrid, Inc.(the “Issuer”) with offices at 180 Marsh Hill Road, Orange, CT 06477 and Deutsche Bank Trust Company Americas, a New York banking corporation (the “Bank”) with offices at 1 Columbus Circle, 17th Floor, New York, NY 10019.
Section 1.    Appointment
The Issuer requests and authorizes the Bank to act on a non-exclusive basis as agent for the Issuer in connection with the issuance and payment of unsecured book-entry obligations (each an “Obligation” and collectively the “Obligations”) as evidenced by Master Note Certificate(s) (the “Note Certificate(s)”), in the form appended hereto in Exhibit A. The Bank agrees to act as such agent for the Issuer subject to the provisions of this Agreement commencing on the Effective Date shown above.
Insofar as the context requires, all references herein to an Issuer's “Obligation” shall be deemed to include the Issuer's Note Certificate(s), and all references herein to an Issuer's “Obligations” or “Book-entry Obligations” shall be deemed to include the Issuer's Note Certificate(s).
Section 2.    Certificate Agreement
The Issuer acknowledges that the Bank has previously entered into a certificate agreement (the “Certificate Agreement”) which copy is appended hereto as Exhibit E, with the Depository Trust Company (“DTC”) and the Issuer also acknowledges that the continuation in effect of the Certificate Agreement is a necessary prerequisite to the Bank's providing services related to issuance of the Obligations. The Issuer understands and agrees that the Certificate Agreement shall supplement the provisions of this Agreement and that the Issuer is bound by the provisions of the Certificate Agreement.
Section 3.    Letter of Representations; Resolutions; Authorized Officers
The Issuer will, prior to the Effective Date, deliver to the Bank an executed Letter of Representations (the “Representations”), a copy of which is appended hereto as Exhibit F. Further, the Issuer understands and agrees that such Representations when executed by the Issuer, the Bank and DTC shall supplement the provisions of this Agreement and that the Issuer, the Bank, and DTC shall be bound by the provisions of the Representations. The Bank and the Issuer agree to comply with the relevant portions of DTC's Issuing and Paying Agent Manual, and the DTC Same Day Settlement System Rules (collectively the “DTC Rules”).
The Issuer has delivered to the Bank (a) a certified copy of the resolutions adopted by the Board of Directors of the Issuer concerning the issuance of Obligations by the Issuer (the “Resolutions”), which copy is appended hereto as Exhibit B, and (b) a certified original of the Issuer's certificate of incumbency (the “Certificate of Incumbency”), containing the name, title, and true signature of those officers of the Issuer authorized by the Resolutions to take action with respect to the Obligations (the “Authorized Officers”), which certificate is appended hereto as Exhibit C. The Issuer agrees to provide the Bank with revised certified Resolutions and/or Certificates of Incumbency when and as required by changes in authorization of personnel.
Section 4.    Authorized Persons
The Issuer authorizes the Bank to accept and to execute Instructions, as defined in and given pursuant to Section 6 hereof by any one of the employees and/or Agents (defined as sales agents or dealers authorized by a separate agreement between the Issuer and its sales agents or dealers) of the Issuer who are designated in a writing that is signed by the requisite number of Authorized Officers. Such designated employees or Agents shall be hereinafter collectively referred to as “Authorized Persons”.


The initial written designation of Authorized Person(s) is appended hereto as Exhibit C. The Issuer agrees to provide the Bank with revised written designations in the form of Exhibit C when and as required by changes in authorization or personnel.
Section 5.    Note Certificates
The Issuer will, prior to the Effective Date, deliver to the Bank a Note Certificate evidencing Obligations issued, such Note Certificate bearing the manual, electronic or facsimile signatures of the requisite number of Authorized Officers and specifying the date of issuance, the full legal name of the Issuer, the name of the state in which the Issuer is incorporated, and the name of the Bank, acting as paying agent for the Issuer, in each case the Note Certificate being registered in the name of Cede & Co., a nominee of DTC.
Any Obligation (as evidenced by the Note Certificate bearing the manual, electronic or facsimile signature of an Authorized Officer) shall, upon the Bank's issuance of such Obligation on behalf of the Issuer, bind the Issuer notwithstanding that such Authorized Officer shall have died or shall have otherwise ceased to hold office on the date such Obligation is issued by the Bank. Furthermore, the Issuer agrees that the Bank shall have no duty or responsibility to determine the genuineness of the facsimile, electronic and/or manual signatures appearing on the Note Certificate(s).
Section 6.    Instructions
The term “Instructions” shall mean a communication, purporting to be from an Authorized Officer or Authorized Person, via (a) a written notice including those transmitted through facsimile transmittal equipment; (b) a telephone call (with confirmation to follow in writing pursuant to this Section 6); (c) a transmission through the instruction communication service DTC’s Pre-Issuance Messaging Service (PIM); or (d) a transmission through the instruction communication service known as “Money Market Agent” or “MMA”, in each case received by the Bank or DTC prior to 1:00 p.m. New York time on the day on which the Instructions are to be operative, which shall be a day the Bank is open for business.
If the Bank, at its option, acts upon Instructions transmitted after 1:00 p.m. New York time on the day on which the Instructions are to be operative, the Issuer understands and agrees that (a) such Instructions shall be acted upon, on a best efforts basis, by the Bank pursuant to the custom and practice of the money market instruments market, and (b) the Bank makes no representations or warranties that the issuance and delivery of any Note Certificate or Obligation pursuant to Section 7 hereof shall be completed prior to the close of business on the issue date specified in such Instructions.
Any Instructions given by telephone shall be confirmed to the Bank in a writing purporting to be from an Authorized Officer or Authorized Person prior to 1:00 p.m. New York time on the day on which such Instructions are to be operative. In the absence of the Bank's timely receipt of such written confirmation or in the event the Bank acts upon Instructions received after 1:00 p.m. New York time on the day on which the Instructions are to be operative, the Issuer understands and agrees that the Instructions given by telephone or received after the aforementioned 1:00 p.m. New York time, as understood by the Bank, shall be the true and controlling Instructions for all purposes of this Agreement.
Notwithstanding anything to the contrary in this Agreement, the Issuer acknowledges and agrees that the Bank may act upon the Instructions without any duty to make any inquiry regarding the genuineness of such Instructions.
Section 7.    Issuance
(A)    Book Entry Obligations
The Issuer will, on or before the effective date, deliver to the Bank a Master Note Certificate. The Bank's sole duties in connection with the issuance of the Obligations when the Issuer delivers the Note Certificate(s) to the Bank, shall be as follows:
a.to hold the Master Note Certificate in safekeeping;


b.to assign to each Instruction received from the Issuer a CUSIP number as specified in and in accordance with the CUSIP number assignment received by the Bank from the Issuer;
c.to cause to deliver an Obligation on behalf of the Issuer upon receipt of Instructions from the Issuer, or their designated agent(s), as to the face or principal amount, net dollar amount, date of issue, maturity date, interest rate (if any), and amount of interest due at maturity (if an interest bearing Obligation), by way of data entry or data transfer to the DTC Same Day Funds Settlement System (“SDFS”), and to receive from SDFS a confirmation receipt that such delivery was effected; and
d.to, prior to the close of business on the Issue Date, subject to the receipt of proceeds, credit the net proceeds of all deliveries of the Obligations to the Issuer's account with the Bank (Account No. AA4743.1) under advice to the Issuer at the address specified in Section 16 hereof.
(B)    Book Entry Obligations
The Issuer acknowledges that pursuant to the custom and practice of the money market instruments market, the delivery of an Obligation against payment of the net amount of the Obligation (i.e., the principal amount of the Obligation less the discount specified in the Instructions or the principal amount of an interest bearing Obligation) and the actual receipt of payment thereof are not simultaneous transactions.
Therefore, whenever the Instructions direct the Bank to deliver any Obligation against payment, the Bank is authorized to and will deliver such Obligation to the party specified in the Instructions and hold as receipt a confirmation copy generated by SDFS in lieu of immediate payment by the purchaser of the Obligation (the “Purchaser”). The Issuer also acknowledges that pursuant to the custom and practice of the money market instruments market, the Purchaser is obligated to settle in immediately available funds at or before the close of business on the Issue Date specified on the Obligation. The Issuer understands and agrees that whenever the Bank delivers an Obligation against receipt of funds as set forth above, the Issuer and not the Bank shall bear the risk of the Purchaser's failure to remit the net amount of the Obligation purchased,
The Bank shall have no duty or responsibility to make any transfer of the proceeds of the sale of the Issuer's Obligations, or to advance any monies or effect any credit with respect to such proceeds or transfers unless and until (i) the Bank has actually received the proceeds of the sale of the Obligations, and (ii) such receipt of the proceeds is not subject to reversal or cancellation. If the Bank, at its sole option, effects any such transfer that results in an overdraft in any account of the Issuer, the amount of such overdraft shall be considered as a loan to the Issuer, and the Issuer agrees to pay the Bank on demand the amount of such loan together with interest thereon at the rate of the Federal Funds Daily Rate plus 100 basis points.
Section 8.    Payment
Bank's sole duties in connection with payment of the Obligations shall be, upon presentment at maturity of an issued Obligation, to pay the principal amount of a discounted Obligation or principal plus interest of an interest-at-maturity Obligation to the party appearing to be entitled thereto, and to debit the Issuer's account with the Bank (Account No. AA4743.1) for such amount under advice to the Issuer at the address specified in Section 16 hereof.
The Bank shall have no obligation to pay, at maturity, the amount referred to in this Section 8 unless sufficient funds have been received by the Bank in collected funds. All interest and/or maturity payments when due, shall be made to the Issuer’s account with the Bank (Account No. AA4743.1) in immediately available funds by 2:00 p.m. New York time on the payment date, to ensure obligations under this Agreement have been met.
In the event that the funds to be transmitted in payment of the Obligations are not received by 2:30 p.m. (New York time) on the maturity date, the Bank reserves the right to initiate a “Refusal to Pay” in accordance with the procedures of DTC.


Section 9.    United States Dollars
The Issuer agrees that the Obligations issued or presented hereunder shall be denominated in United States dollars. The Issuer further agrees that payment of any and all amounts due pursuant to the provisions of this Agreement shall be made solely in United States dollars.
Section 10.    MMA System
The Issuer hereby acknowledges that the time-sharing services utilized in connection with MMA are furnished by SS&C Technologies, Inc. ("SS&C"). SS&C has granted permission to the Bank to allow the Bank’s customers to use such time-sharing services and, in consideration for such permission, it is understood and agreed that if the Issuer or another party or person elects to use MMA, such time-sharing services will be supplied "as is" without warranty by SS&C or the Bank. The Issuer hereby waives any claims it may have against SS&C or the Bank arising out of or in connection with the use of such time-sharing services except for any gross negligence or willful misconduct by SS&C or the Bank, and acknowledges that MMA is proprietary and confidential property disclosed in confidence and only on the terms and conditions and for the purposes set forth in this Agreement.
By this Agreement, neither the Issuer nor any other person acquires title, ownership or sublicensing rights whatsoever in MMA or in any trade secret, trademark, copyright or patent of the Bank or SS&C, now or to become applicable to MMA. Neither the Issuer nor any other person may transfer, sub-license, assign, rent, lease, convey, modify, translate, convert to a programming language, decompile, disassemble, recirculate, republish or redistribute MMA for any purpose without the prior written consent of the Bank.
In the event (a) any action is taken or threatened which may result in a disclosure or transfer of MMA or any part thereof, other than as authorized by this Agreement, or (b) the use of any trademark, trade name, service mark, service name, copyright or patent of the Bank or SS&C by the Bank amounts to unfair competition, or otherwise constitutes a possible violation of any kind, then the Bank or SS&C shall each have the right to take any and all action deemed necessary to protect their rights in MMA, and to avoid the substantial and irreparable damage which would result from such disclosure, transfer or use, including the immediate termination of the Issuer's or any other person's right to use MMA.
To permit the use of MMA to transmit information and instructions or obtain reports with respect to the Obligations, the Bank will supply the Issuer with an identification number and initial passwords. From time to time thereafter, the Issuer will keep all information relating to its identification number and passwords strictly confidential and will be responsible for the maintenance of adequate security over its customer identification number and passwords. For security purposes, the Issuer should change its passwords frequently (at least once a year).
Information and instructions transmitted over MMA and received by the Bank and accompanied by the Issuer's identification number and the passwords, shall be deemed conclusive evidence that such instructions and information are correct and complete and that the issuance of the Obligations directed thereby has been duly authorized by the Issuer.
Section 11.    Representations and Warranties
The Issuer and/or the Bank, as indicated below, (each, a “Party” and together the “Parties”) hereby represents and warrants as to itself only and not as to the other Party as follows:
a.This Agreement and the Obligations have been duly authorized by the Issuer, and this Agreement when executed by the Issuer and the Obligations when issued in accordance with Instructions, will be valid and binding obligations of the Issuer, enforceable against the Issuer in accordance with their terms, subject to bankruptcy, insolvency, fraudulent transfer, reorganization, moratorium and other laws of general applicability relating to or affecting creditors’ rights and to general equity principles.
b.This Agreement has been duly authorized and when executed by the Bank will be a valid, legal and binding obligation of the Bank, enforceable against it in accordance with its terms;


c.To the best knowledge of the Issuer, this Agreement and the consummation of the transactions herein contemplated will not (i) conflict with or result in a breach of any of the terms or provisions of, or constitute a default under, any indenture, mortgage, deed of trust, loan agreement or other agreement or instrument for money borrowed to which the Issuer is a party or by which the Issuer is bound or to which any of the property or assets of the Issuer is subject, or (ii) result in any violation of (x) the provisions of the Articles of Incorporation or the By-Laws of the Issuer or (y) to the best knowledge of the Issuer, any statute or any order, rule or regulation of any court or government agency or body having jurisdiction over the Issuer or any of its properties, in any manner which, in the case of clauses (i) and (ii) (y), would have a material adverse effect on the business of the Issuer taken as a whole;
d.To the best knowledge of the Issuer, no consent, approval, authorization, order, registration or qualification of or with any court or governmental agency or body having jurisdiction over the Issuer or any of its properties is required for the issue and sale of the Obligations, except such as have been, or will have been obtained prior to the issue and sale of the Obligations, and such consents, approvals, authorizations, registrations or qualifications as may be required under “blue sky” or state securities laws or insurance laws in connection with the issue and sale of the Obligations by the Issuer; and
e.To the best knowledge of the Issuer, each Obligation issued under this Agreement will be exempt from registration under the Securities Act of 1933, as amended. Each Instruction by the Issuer to issue Obligations under this Agreement shall be deemed a representation and warranty by the Issuer as of the date thereof that the representations and warranties herein are true and correct as if made on and as of such date.
Section 12.    Fees and Expenses
A.The Issuer agrees to pay such compensation for the Bank's issuing and paying agent services pursuant to this Agreement as agreed to in writing between the Bank and the Issuer, as amended from time to time (subject to prior written notification delivered to the Issuer not less than thirty (30) days prior to the effective date of any amendment) dated July 8, 2022 and executed by the Issuer with respect to such fees.
B.The Issuer shall promptly reimburse the Bank upon its request for all reasonable expenses and disbursements incurred by the Bank in connection with its performance under this Agreement (including without limitation the reasonable fees and expenses of its agents and counsel).
Notwithstanding anything herein to the contrary, the Bank shall only debit fees that remain unpaid for sixty (60) days or more to the extent the Issuer has excess cash flow from operations or has received funds with respect to such obligation which may be used to make such payment and which funds or excess cash flow are not required to pay when due any outstanding Obligations with respect to the Notes of the Issuer. Any amount which the Issuer does not pay pursuant to the operation of the preceding sentence shall not constitute a claim under the Bankruptcy Code against the Issuer for any such insufficiency unless and until the Issuer does have such excess cash flow or excess funds. The provisions of this Section 12 shall survive (i) the Bank’s resignation or removal as the issuing and paying agent hereunder and (ii) the termination of this Agreement.
Section 13.    Indemnification
The Issuer agrees that the Bank shall not be liable for any losses, damages, liabilities or costs suffered or incurred by the Issuer as a result of (a) the Bank's having executed Instructions, (b) the Bank's improperly executing or failing to execute any Instructions because of unclear Instructions, failure of communications media or systems or any other circumstances beyond the Bank's control, (c) the actions or inactions of DTC, any Agent or any broker, dealer, consignee or agent not selected by the Bank, or (d) any other acts or omissions of the Bank (or of any of its agents or correspondents) relating to this Agreement or the transactions or activities contemplated hereby except to the extent, if any, that such other acts or omissions constitute gross negligence or willful misconduct by the Bank. The Issuer, in the absence of gross negligence or willful misconduct by the Bank, agrees to indemnify the Bank and its directors, officers, employees and agents and hold the same harmless from and against (a) any and all actions, claims (groundless or otherwise), suits, losses, fines and penalties arising out of, in connection with or resulting from the Bank's having executed any Instructions or otherwise having performed any of its obligations or exercised any of its rights hereunder and (b) any damages, costs, expenses (including reasonable legal fees and disbursements), losses or liabilities relating to any such actions, claims, suits, losses fines or penalties or to any breach of this Agreement by the Issuer. This Section 13, Indemnification, shall survive any termination of this Agreement, resignation or removal of the Bank, and the issuance and payment of any Note Certificate(s).


Section 14.    Bank’s Rights and Duties
A.The Bank shall act solely as the agent of the Issuer and will not thereby assume any obligations toward or relationship of agency or trust for or with any of the owners of the Obligations other than as may be explicitly set forth herein
B.The Bank shall not be liable for any action taken, suffered, or omitted or for any error of judgment made by the Bank in the performance of the Bank's duties under this Agreement, except for its own willful misconduct or gross negligence, and the Bank shall not be liable for any action or inaction of any other party (or agent thereof) to this Agreement or any related document.
C.The Bank shall incur no liability in acting upon telephonic, facsimile or other electronic instructions which the Bank believes in good faith to have been given by an Authorized Person, including but not limited to Instructions received in connection with the issuance of Obligations. In addition, in the event that the Issuer or an Agent currently or in the future utilizes a trading system that produces issuance instructions that do not include signatures or initials, the Bank may conclusively rely upon such instructions absent such signatures or initials.
D.The Bank may conclusively rely and shall be fully protected in acting or refraining from acting upon any communication authorized by this Agreement and upon any written instruction, notice, confirmation, request, direction, consent, report, certificate or other instrument, paper or document authorized by this agreement and believed by the Bank to be genuine, and the Bank need not investigate any statement, representation or warranty or any fact or matter stated in any such document and may conclusively rely as to the truth of the statements and the correctness of the opinions expressed therein.
E.The Bank may perform its duties and exercise its rights under this Agreement either directly or by or through agents, custodians, nominees or attorneys and shall not be liable for the misconduct or negligence or for the supervision of such agents, custodians, nominees or attorneys appointed with due care.
F.The Bank undertakes to perform such duties and only such duties as are set forth in this Agreement and no implied covenants shall be read into this Agreement against the Bank.
G.The Bank, in its individual or any other capacity, may become the owner or pledgee of an Obligation with the same rights it would have if it were not acting hereunder.
H.Whenever in the administration of this Agreement, the Bank shall deem it necessary that a matter be proved or established prior to acting, suffering or omitting any action hereunder, the Bank may request and shall be entitled to receive a certificate of a Authorized Person and such matter shall be deemed to be conclusively proved and established by such certificate and such certificate shall be full warranty to the Bank for any action taken, suffered or omitted under the provisions of this Agreement in accordance herewith, unless another method is prescribed herein.
I.The Bank may consult with counsel or other professional advisors, and any advice or written opinion of such counsel or other professional advisors shall be full and complete authorization and protection in respect of any action taken, suffered or omitted to be taken by the Bank, in the absence of willful misconduct or gross negligence on its part, in reliance on such advice or opinion.
J.Any corporation or entity into which the Bank may be merged or with which the Bank may be consolidated, or any corporation or entity resulting from any merger or consolidation to which the Bank shall be a party, or any corporation or entity succeeding to its corporate trust business, shall succeed to all of its rights, obligations and immunities hereunder without the execution or filing of any document or any further act on the part of any of the parties hereto, anything herein to the contrary notwithstanding.
K.The Bank shall not be required to advance, expend or risk its own funds or otherwise incur or become exposed to liability (financial or otherwise) in the performance of its duties hereunder. Further, the Bank shall not be under any obligation to take any action hereunder which may tend to involve it in any expense or liability, the payment of which within a reasonable time is not in its reasonable opinion assured to it.
L.In no event shall the Bank be liable for special, indirect, punitive or consequential loss or damage of any kind whatsoever even if the Bank has been advised of the likelihood of such loss or damage and regardless of the form of action, except in connection with its willful misconduct or gross negligence.


M.Except as ordered by a court of competent jurisdiction or as required by law or applicable regulations or as instructed by the Issuer, the Bank shall deem and treat the bearer of each Obligation as the absolute owner thereof (whether or not such Obligation shall be overdue and notwithstanding any notice of ownership or writing thereon) for the purpose of making payments and for all other purposes.
N.On behalf of and at the written request and expense of the Issuer, the Bank shall cause to be delivered to DTC all notices required to be given by the Issuer to the holders of Obligations provided that the Issuer shall provide signed copies of such notices to the Bank not later than two (2) Business Days (or such longer period as the Bank shall reasonably require) prior to the date of delivery.
O.The Bank shall not have any duty or responsibility in respect of (i) any recording, filing, or depositing of this Agreement or any other agreement or instrument, monitoring or filing any financing statement or continuation statement evidencing a security interest, the maintenance of any such recording, filing or depositing or to any re-recording, re-filing or re-depositing of any thereof, or otherwise monitoring the perfection, continuation of perfection or the sufficiency or validity of any security interest in or related to any collateral, (ii) the acquisition or maintenance of any insurance or (iii) the payment or discharge of any tax, assessment, or other governmental charge or any lien or encumbrance of any kind owing with respect to, assessed or levied against, any part of any collateral.
P.The Bank makes no representation as to and shall have no responsibility for the correctness of any statement of another party contained in, or the validity or sufficiency of, this Agreement or any documents or instruments referred to in this Agreement or the sufficiency or effectiveness of any security afforded this Agreement or as to or for the validity or collectability of any obligation contemplated by this Agreement.
Q.The Bank shall not be liable for failing to comply with its obligations under this Agreement or any related document in so far as the performance of such obligations is dependent upon the timely receipt of instructions and/or other information from any party or person which are not received or not received by the time required.
R.Except as otherwise provided herein, nothing herein shall be construed to impose an obligation on the part of the Bank to recalculate, evaluate, verify or independently determine the accuracy of any report, certificate or other information received from any party or person.
S.In no event shall the Bank be liable for any failure or delay in the performance of its obligations under this Agreement or any related documents because of circumstances beyond the Bank’s control, including, but not limited to, a failure, termination, or suspension of, or limitations or restrictions in respect of post-payable adjustments through, a clearing house, securities depositary, settlement system or central payment system in any applicable part of the world or acts of God, flood, war (whether declared or undeclared), civil or military disturbances or hostilities, nuclear or natural catastrophes, political unrest, explosion, severe weather, epidemic, pandemic or accident, earthquake, terrorism, fire, riot, labor disturbances, strikes or work stoppages for any reason, embargo, government action, including any laws, ordinances, regulations or the like (whether domestic, federal, state, county or municipal or foreign) which delay, restrict or prohibit the providing of the services contemplated by this Agreement or any related documents, or the unavailability of communications or computer facilities, the failure of equipment or interruption of communications or computer facilities, or the unavailability of the Federal Reserve Bank wire or telex or other wire or communication facility, or any other causes beyond the Bank’s control whether or not of the same class or kind as specified in this Section 14(S); it being understood that the Bank shall use commercially reasonable efforts to resume performance of its obligations hereunder as soon as practicable under the circumstances.
T.In order to comply with the laws, rules, regulations and executive orders in effect from time to time applicable to banking institutions, including, without limitation, those relating to the funding of terrorist activities and money laundering including, Section 326 of the USA PATRIOT Act of the United States (“Applicable Law”), the Bank is required to obtain, verify, record and update certain information relating to individuals and entities which maintain a business relationship with the Bank. Accordingly, the Issuer agrees to provide to the Bank upon its request from time to time such identifying information and documentation as may be available for such party in order to enable the Bank to comply with Applicable Law.


Section 15.    Termination
This Agreement shall terminate on the date that is the earlier of (i) the date on which the Certificate Agreement is no longer in place for whatever reason and (ii) the date on which the Bank or the Issuer has terminated this Agreement in accordance with this Section 15.
Either the Bank or the Issuer may terminate this Agreement at any time by not less than thirty (30) days' prior written notice to the other. No such termination shall affect the rights and obligations of the Issuer and the Bank which have accrued under this Agreement prior to termination.
Section 16.    Addresses
Instructions hereunder shall be (a) mailed, (b) telephoned, (c) transmitted by facsimile device or electronic mail, to the Bank at the address, telephone number, and/or facsimile number specified below and shall be deemed delivered upon actual receipt by the Bank's money market instruments operations at the address, telephone number, and/or facsimile number specified below.
Deutsche Bank Trust Company Americas
Trust and Agency Services
1 Columbus Circle, 17th Floor
All notices, requests, demands and other communications hereunder (excluding Instructions) shall be in writing and shall be deemed to have been duly given (a) upon delivery by hand (against receipt), or (b) by United States Post Office registered mail (against receipt) or by regular mail (upon receipt) to the party and at the address set forth below or at such other address as either party may designate by written notice:
(a) ISSUER:
Avangrid, Inc.
One City Center, 5th Floor
Portland, ME 04101
(b) BANK:
Deutsche Bank Trust Company Americas
Trust and Agency Services
1 Columbus Circle, 17th Floor
Mail Stop: NYC01-1710
New York, NY 10019
USA
E-Signature
Facsimile, documents executed, scanned and transmitted electronically and electronic signatures, including those created or transmitted through a software platform or application, shall be deemed original signatures for purposes of this Agreement and all other related documents and all matters and agreements related thereto, with such facsimile, scanned and electronic signatures having the same legal effect as original signatures. The parties agree that this Agreement or any other related document or any instrument, agreement or document necessary for the consummation of the transactions contemplated by this Agreement or the other related documents or related hereto or thereto (including, without limitation, addendums, amendments, notices, instructions, communications with respect to the delivery of securities or the wire transfer of funds or other communications) (“Executed Documentation”) may be accepted, executed or agreed to through the use of an electronic signature in accordance with applicable laws, rules and regulations in effect from time to time applicable to the effectiveness and enforceability of electronic signatures.


Any Executed Documentation accepted, executed or agreed to in conformity with such laws, rules and regulations will be binding on all parties hereto to the same extent as if it were physically executed and each party hereby consents to the use of any third party electronic signature capture service providers as may be reasonably chosen by a signatory hereto or thereto. When the Bank acts on any Executed Documentation sent by electronic transmission, the Bank will not be responsible or liable for any losses, costs or expenses arising directly or indirectly from its reliance upon and compliance with such Executed Documentation, notwithstanding that such Executed Documentation (a) may not be an authorized or authentic communication of the party involved or in the form such party sent or intended to send (whether due to fraud, distortion or otherwise) or (b) may conflict with, or be inconsistent with, a subsequent written instruction or communication; it being understood and agreed that the Bank shall conclusively presume that Executed Documentation that purports to have been sent by an authorized officer of a Person has been sent by an authorized officer of such Person. The party providing Executed Documentation through electronic transmission or otherwise with electronic signatures agrees to assume all risks arising out of such electronic methods, including, without limitation, the risk of the Bank acting on unauthorized instructions and the risk of interception and misuse by third parties.
Section 17.    Miscellaneous
A.GOVERNING LAW. THIS AGREEMENT SHALL BE GOVERNED BY AND INTERPRETED IN ACCORDANCE WITH THE LAWS OF THE STATE OF NEW YORK AND AS APPLICABLE, OPERATING CIRCULARS OF THE FEDERAL RESERVE BANK, FEDERAL LAWS AND REGULATIONS AS AMENDED, NEW YORK CLEARING HOUSE RULES, THE DTC RULES, AND GENERAL COMMERCIAL BANK PRACTICES APPLICABLE TO COMMERCIAL PAPER AND CERTIFICATE OF DEPOSIT ISSUANCE AND PAYMENT, FUNDS TRANSFER AND RELATED ACTIVITIES.
B.SUBMISSION TO JURISDICTION. EACH OF THE PARTIES HERETO IRREVOCABLY SUBMITS TO THE JURISDICTION OF ANY FEDERAL OR STATE COURTS SITTING IN THE BOROUGH OF MANHATTAN IN RESPECT OF ANY ACTION OR PROCEEDING ARISING OUT OF OR IN CONNECTION WITH THIS AGREEMENT. EACH OF THE PARTIES HERETO IRREVOCABLY WAIVES, TO THE FULLEST EXTENT PERMITTED BY APPLICABLE LAW, ANY OBJECTION THAT IT MAY NOW OR HEREAFTER HAVE TO THE LAYING OF VENUE OF ANY SUCH PROCEEDINGS IN ANY SUCH COURT AND ANY CLAIM THAT ANY PROCEEDING BROUGHT IN ANY SUCH COURT HAS BEEN BROUGHT IN AN INCONVENIENT FORUM.
C.WAIVER OF JURY TRIAL. EACH OF THE PARTIES HERETO HEREBY WAIVES THE RIGHT IT MAY HAVE TO A TRIAL BY JURY ON ANY CLAIM, COUNTERCLAIM, SETOFF, DEMAND, ACTION OR CAUSE OF ACTION (A) ARISING OUT OF OR IN ANY WAY RELATED TO THIS AGREEMENT, OR (B) IN ANY WAY IN CONNECTION WITH OR PERTAINING TO OR RELATED TO OR INCIDENTAL TO ANY DEALINGS OF THE PARTIES WITH RESPECT TO THIS AGREEMENT OR IN CONNECTION WITH THIS AGREEMENT OR THE EXERCISE OF ANY PARTY’S RIGHTS AND REMEDIES UNDER THIS AGREEMENT OR OTHERWISE, OR THE CONDUCT OR THE RELATIONSHIP OF THE PARTIES HERETO, IN ALL OF THE FOREGOING CASES WHETHER NOW EXISTING OR HEREAFTER ARISING AND WHETHER IN CONTRACT, TORT OR OTHERWISE.
D.Assignment; Amendment. Neither this Agreement nor any right or obligation created hereunder may be transferred, assigned, pledged or hypothecated by Issuer, other than by operation of law or with the written consent of the Bank. This Agreement may not be modified, or amended or supplemented except by a writing or writings duly executed by the duly authorized representatives of the Issuer and the Bank. The Bank may, but shall not be obligated to, enter into any such amendment which adversely affects the Bank's own rights, duties, immunities or indemnities under this Agreement or any document contemplated hereby to which the Bank is a party. This Agreement shall inure to the benefit of and shall be binding upon the parties hereto and their respective successors and permitted assigns.


E.This Agreement contains the entire understanding and agreement between the parties with respect to the subject matter hereof. All prior agreements understandings, representations, statements, promises, inducements, negotiations and undertakings and all existing contracts previously executed between parties with respect to said subject matter are superseded hereby.
F.With respect to all references herein to nouns, insofar as the context requires, singular form shall be deemed to include the plural, and the plural form shall be deemed to include the singular.
G.Accounts. The various accounts referenced herein shall be segregated non-interest bearing trust accounts or non-interest bearing DDA Accounts.
H.Counterparts. This Agreement may be executed by each of the parties hereto in any number of counterparts, each of which counterpart, when so executed and delivered, shall be deemed to be an original and all such counterparts shall together constitute one and the same agreement. Delivery of a counterpart hereof by facsimile transmission, electronically, or by e-mail transmission of an Adobe portable document format file (also known as a “PDF” file) shall be effective as delivery of a manually executed counterpart hereof.
I.Severability. If any one or more of the covenants, agreements, provisions or terms of this Agreement shall be for any reason whatsoever held invalid, then such covenants, agreements, provisions or terms shall be deemed severable from the remaining covenants, agreements, provisions or terms of this Agreement and shall in no way affect the validity or enforceability of the other provisions of this Agreement.
J.Headings. Section and subsection headings in this Agreement are included herein for convenience of reference only and shall not constitute a part of this Agreement for any other purpose or be given any substantive effect.
[Signature Pages Follow]



Agreed to and Accepted by:

AVANGRID, INC., as Issuer
/s/ Scott Tremble   /s/ Howard Coon
Scott Tremble   Howard Coon
Senior Vice President - Controller Vice President - Treasurer
September 13, 2022 September 13, 2022

DEUTSCHE BANK TRUST COMPANY AMERICAS, as Bank
/s/ Rodney Gaughan   /s/ Lisa Karlsen
Rodney Gaughan   Lisa Karlsen
Vice President Vice President

EX-10.47 3 agr-ex1047x2023.htm EX-10.47 Document

Exhibit 10.47
EQUITY CAPITAL CONTRIBUTION AGREEMENT
between
Vineyard Wind Sponsor Partners 1 LLC
JPMorgan Chase Bank, N.A.,
Bank of America, N.A.
and
Wells Fargo Bank, N.A.
Dated as of October 24, 2023


TABLE OF CONTENTS
ARTICLE I DEFINITIONS 2
1.1 Definitions 2
1.2 Other Definitional Provisions 2
ARTICLE II CAPITAL CONTRIBUTIONS 3
2.1 Capital Contributions 3
2.2 Adjustments to Base Case Model; Capital Contributions; Escrow 6
2.3 Payment of Capital Contributions 10
2.4 Use of Proceeds; Release of Reserves; Refunds 10
2.5 Tax Reporting of Transaction 12
ARTICLE III REPRESENTATIONS AND WARRANTIES OF THE CLASS B EQUITY INVESTOR 12
3.1 Organization and Good Standing 12
3.2 Authority; Execution and Delivery; Enforceability 13
3.3 No Conflicts 13
3.4 Absence of Litigation 13
3.5 Ownership 14
3.6 Valid Interests 14
3.7 Financial Statements 15
3.8 Compliance With Laws 15
3.9 Environmental Matters 16
3.10 Applicable Permits 16
3.11 Insurance 17
3.12 Real Property 18
3.13 Indebtedness; Encumbrances 18
3.14 Employee Matters 18
3.15 Affiliate Transactions 19
3.16 Tax Matters 19
3.17 Material Project Agreements 21
3.18 Regulatory Status 22
3.19 Brokers 23
3.20 Disclosure 23
3.21 Payments of Amounts Due 24
3.22 Acknowledgment of Limited Nature of Representations and Warranties 24
3.23 Material Adverse Effect 24
3.24 No Casualty 24
3.25 No Condemnation 24
3.26 No Adverse Guarantor Event 25
3.27 Loan Documents 25
3.28 Turbine Injunction 25
ARTICLE IV REPRESENTATIONS AND WARRANTIES OF EACH CLASS A EQUITY INVESTOR 26
4.1 Organization and Good Standing 26
4.2 Authority 26
4.3 No Conflicts 26
4.4 Absence of Litigation 26


4.5 Investment Intent 26
4.6 Accredited Class A Equity Investor 27
4.7 No Registration 27
4.8 Forward-Looking Information 27
4.9 Acknowledgment of Limited Nature of Representations and Warranties 27
4.10 Brokers 28
4.11 Tax Status 28
ARTICLE V CONDITIONS TO ECCA EFFECTIVE DATE OBLIGATIONS 28
5.1 Class A Equity Investor ECCA Effective Date Conditions Precedent 28
5.2 Class B Equity Investor ECCA Effective Date Conditions Precedent 32
ARTICLE VI CONDITIONS TO OBLIGATIONS OF THE CLASS A EQUITY INVESTORS; CERTAIN CLASS B EQUITY INVESTOR COVENANTS 33
6.1 Initial Capital Contribution Date Conditions Precedent 33
6.2 Interim Capital Contribution Date Conditions Precedent 39
6.3 Final Capital Contribution Date Conditions Precedent 42
6.4 ALTA/NSPS Surveys 50
6.5 Mechanical Completion Notice 50
6.6 Placed in Service Notice 50
ARTICLE VII CONDITIONS TO OBLIGATIONS OF THE CLASS B EQUITY INVESTOR 51
7.1 Initial Capital Contribution Date Conditions Precedent 51
7.2 Interim Capital Contribution Date Conditions Precedent 52
7.3 Final Capital Contribution Date Conditions Precedent 52
ARTICLE VIII INDEMNIFICATION 53
8.1 Indemnification by the Class B Equity Investor 53
8.2 Limitations on Liability 54
8.3 Procedures for Indemnification With Respect to Third-Party Claims 57
8.4 Exclusivity 58
8.5 Payment of Indemnification Claims 58
8.6 No Duplication 59
ARTICLE IX TERMINATION; CLASS A WITHDRAWAL 59
9.1 Termination 59
9.2 Procedure and Effect of Termination 60
9.3 Class A Withdrawal 60
ARTICLE X GENERAL PROVISIONS 61
10.1 Notices 61
10.2 Transaction Expenses 63
10.3 Counterparts 63
10.4 Governing Law and Severability 63
10.5 Entire Agreement 64
10.6 Effect of Waiver or Consent 64
10.7 Amendments and Modifications 64
10.8 Disclosure Schedules 64
10.9 Binding Effect 65
10.10 Further Assurances 65
10.11 Assignability and Parties in Interest 65


10.12 Jurisdiction; Service of Process; WAIVER OF JURY TRIAL 65
10.13 Confidentiality; Public Announcements 66
10.14 Direct Pay 67
10.15 No Strict Construction 67
10.16 Certain Investor Consents 67



EQUITY CAPITAL CONTRIBUTION AGREEMENT
This EQUITY CAPITAL CONTRIBUTION AGREEMENT (this “Agreement”), dated as of October 24, 2023 (the “ECCA Effective Date”), is made and entered into among Vineyard Wind Sponsor Partners 1 LLC, a Delaware limited liability company (the “Class B Equity Investor”), JPMorgan Chase Bank, N.A. (“JPM”), Bank of America, N.A. (“BofA”) and Wells Fargo Bank, N.A. (“Wells” and together with JPM and BofA, the “Class A Equity Investors”, and together with the Class B Equity Investor, the “Parties”).
RECITALS
1.Vineyard Wind TE Partners 1 LLC, a Delaware limited liability company (the “Company”), was formed by virtue of its certificate of formation filed with the Secretary of State of the State of Delaware on April 25, 2019, and is governed by that certain Amended and Restated Limited Liability Company Operating Agreement of Vineyard Wind TE Partners 1 LLC, dated as of September 15, 2021 (the “Original LLC Agreement”);
2.Vineyard Wind 1 Pledgor LLC, a Delaware limited liability company (“Seller”) owns 100% of the Ownership Interests in Vineyard Wind 1 LLC, a Delaware limited liability company (the “Project Company”), which is developing an 800 MW wind generation facility in federal waters off the coast of Martha’s Vineyard, Massachusetts (the “Project”);
3.On the Initial Capital Contribution Date, (i) each of the Class A Equity Investors shall make a Capital Contribution to the Company, equal to the aggregate amount determined as provided in this Agreement in return for the issuance to the Class A Equity Investors (and in the case of BofA, BAL Investment & Advisory, LLC) of the Class A Membership Interests in the Company, on a pro rata basis corresponding to the percentage of the Class A Membership Interests in the Company shown opposite such Class A Equity Investor’s name in Annex B, (ii) the Class B Equity Investor shall make the Initial Class B Capital Contribution to the Company, (iii) the Class B Equity Investor shall retain the membership interests in the Company that it owns, and such membership interests shall convert into the Class B Membership Interests in the Company and (iv) each of JPM, Wells, BAL Investment & Advisory, LLC and the Class B Equity Investor shall amend and restate the Original LLC Agreement by entering into the Second Amended and Restated Limited Liability Company Agreement, by and among JPM, Wells, BAL Investment & Advisory, LLC and the Class B Equity Investor, in substantially the form attached hereto as Exhibit A (the “LLC Agreement”);
4.Pursuant to that certain Purchase and Sale Agreement between Seller and the Company, dated as of the date hereof (the “PSA”), Seller shall sell, and the Company shall use all or a portion of the proceeds from each Capital Contribution Date to purchase, 100% of the membership interests in the Project Company as of the Closing Date (as defined in the PSA), which shall be concurrent with the Initial Capital Contribution Date;
5.On each Interim Capital Contribution Date and the Final Capital Contribution Date, each of the Class A Equity Investors and, to the extent required by this Agreement, the Class B Equity Investor shall make Capital Contributions to the Company equal to the aggregate amount determined as provided in this Agreement; and
6.The Class B Equity Investor intends the investment made by the Class A Equity Investors pursuant to this Agreement and the LLC Agreement to meet the eligibility requirements set forth in “Avangrid’s Framework for Green Financing” and the Class B Equity Investor or its Affiliates will undertake to report the benefits attributable to this investment in its annual sustainability reporting.
AGREEMENT
NOW, THEREFORE, in consideration of the mutual covenants and agreements contained herein and other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the Parties hereto agree, notwithstanding any contrary provision of this Agreement, as of the ECCA Effective Date, that:


ARTICLE I
DEFINITIONS
1.1Definitions. Capitalized terms used but not otherwise defined herein will have the meanings given to such terms in Annex A hereto.
1.2Other Definitional Provisions.
(a)Construction. As used in this Agreement, singular shall include the plural, the masculine gender shall include the feminine and neuter, the feminine gender shall include the masculine and neuter and the neuter gender shall include the masculine and the feminine unless the context otherwise indicates.
(b)References. References to Articles and Sections are intended to refer to Articles and Sections of this Agreement, and all references to Exhibits, Schedules and Annexes are intended to refer to Exhibits, Schedules and Annexes attached to this Agreement, each of which is made a part of this Agreement for all purposes. The words “hereof”, “herein”, “hereunder” and words of similar import when used in this Agreement shall refer to this Agreement as a whole and not to any particular provision of this Agreement. The term “including” means “including, without limitation.” Any date specified for action that is not a Business Day shall mean the first Business Day after such date. Any reference to a Person shall be deemed to include such Person’s successors and permitted assigns. Any reference to any document, agreement, instrument or statute shall be deemed to refer to such document, agreement, instrument or statute as amended, modified or supplemented from time to time and includes (in the case of agreements or instruments) references to all attachments thereto and instruments incorporated therein. Notwithstanding the foregoing, any specific references to articles or sections of the LLC Agreement or terms defined therein shall refer to such sections, articles or defined terms set forth in the LLC Agreement.
(c)Accounting Terms. As used in this Agreement and in any certificate or other documents made or delivered pursuant hereto or thereto, accounting terms not defined in this Agreement or in any such certificate or other document, and accounting terms partly defined in this Agreement or in any such certificate or other document to the extent not defined, shall have the respective meanings given to them under GAAP. To the extent that the definitions of accounting terms in this Agreement or in any such certificate or other document are inconsistent with the meanings of such terms under GAAP, the definitions contained in this Agreement or in any such certificate or other document shall control.
ARTICLE II
CAPITAL CONTRIBUTIONS
2.1Capital Contributions.
(a)Initial Class A Capital Contribution. Subject to the satisfaction or waiver of the conditions set forth in Sections 6.1 and 7.1 (the date upon which all of the conditions set forth in Sections 6.1 and 7.1 have either been satisfied or waived by the applicable Party, the “Initial Capital Contribution Date”), the Class A Equity Investors shall make a Capital Contribution to the Company, on a pro rata basis corresponding to the percentage of the Class A Membership Interests in the Company shown opposite such Class A Equity Investor’s name in Annex B, in an amount equal to 20% of their aggregate anticipated Capital Contributions with respect to the portion of the Project that either (i) has achieved Mechanical Completion as of the Initial Capital Contribution Date based upon the Independent Engineer’s certificate delivered pursuant to Section 6.1(m)(ii)(A) or (ii) is expected to achieve Mechanical Completion by the end of such month based upon the Mechanical Completion Schedule delivered pursuant to Section 6.1(m)(ii)(B) (the “Initial Class A Capital Contribution”), as such Initial Class A Capital Contribution is set forth in the Base Case Model delivered to the Class A Equity Investors pursuant to Section 6.1(i), and the Class B Equity Investor shall make the Initial Class B Capital Contribution to the Company and cause the Company to issue the Class A Membership Interests described on Annex B to each of the Class A Equity Investors. For illustrative purposes only, Exhibit P includes a sample calculation of the Initial Class A Capital Contribution and the Initial Class B Capital Contribution. Payment by each Class A Equity Investor of its respective Initial Class A Capital Contribution and the issuance of the Class A Membership Interests to each such Class A Equity Investor will take place at the offices of Kirkland & Ellis LLP (or remotely via the electronic exchange of closing deliverables), on the Initial Capital Contribution Date. The Initial Class A Capital Contribution shall be used for the purposes and in the order as set forth in Section 2.4(a).


(b)Interim Class A Capital Contribution. Upon receipt of the Independent Engineer’s certificate delivered pursuant to Section 6.2(k) attaching an updated Mechanical Completion Schedule or confirming the reasonableness of the Mechanical Completion Schedule delivered on the Initial Capital Contribution Date or the applicable preceding Interim Capital Contribution Date, and subject to the satisfaction or waiver of the conditions set forth in Sections 6.2 and 7.2 (each date upon which all of the conditions set forth in Sections 6.2 and 7.2 have either been satisfied or waived in by the applicable Party, an “Interim Capital Contribution Date”), the Class A Equity Investors shall make a Capital Contribution to the Company, on a pro rata basis corresponding to the percentage of the Class A Membership Interests in the Company shown opposite such Class A Equity Investor’s name in Annex B, in an amount equal to 20% of their aggregate anticipated Capital Contributions pro rata with respect to the portion of the Project that either (i) achieved Mechanical Completion but was not reflected on a prior Mechanical Completion Schedule or (ii) is expected to achieve Mechanical Completion in such month (the “Interim Class A Capital Contribution”), as such Interim Class A Capital Contribution is set forth in the Base Case Model delivered to the Class A Equity Investors pursuant to Section 6.1(i) and the Class B Equity Investor shall make the applicable Interim Class B Capital Contribution (if any) to the Company. For illustrative purposes only, Exhibit P includes a sample calculation of each Interim Class A Capital Contribution and each Interim Class B Capital Contribution. Payment by each Class A Equity Investor of each Interim Class A Capital Contribution will take place at the offices of Kirkland & Ellis LLP (or remotely via the electronic exchange of closing deliverables), on the applicable Interim Capital Contribution Date. Each Interim Class A Capital Contribution shall be used for the purposes and in the order as set forth in Section 2.4(b).
(c)Final Class A Capital Contribution. Subject to the satisfaction or waiver of the conditions set forth in Sections 6.3 and 7.3 (the date upon which all of the conditions set forth in Sections 6.3 and 7.3 have either been satisfied or waived by the applicable Party, the “Final Capital Contribution Date”, and together with the Initial Capital Contribution Date and each Interim Capital Contribution Date, each, a “Capital Contribution Date” and collectively, “Capital Contribution Dates”), the Class A Equity Investors shall make a Capital Contribution to the Company, on a pro rata basis corresponding to the percentage of the Class A Membership Interests in the Company shown opposite such Class A Equity Investor’s name in Annex B, in an amount equal to the amount indicated in the Base Case Model delivered to the Class A Equity Investors pursuant to Section 6.3(i) (the “Final Class A Capital Contribution”) and, concurrently with or immediately following the Final Class A Capital Contribution, the Class B Equity Investor shall make the applicable Final Class B Capital Contribution (if any) to the Company. For illustrative purposes only, Exhibit P includes a sample calculation of the Final Class A Capital Contribution. Payment by each Class A Equity Investor of the Final Class A Capital Contribution will take place at the offices of Kirkland & Ellis LLP (or remotely via the electronic exchange of closing deliverables), on the Final Capital Contribution Date. The Final Class A Capital Contribution shall be used for the purposes and in the order as set forth in Section 2.4(c).
(d)LLC Agreement; Ownership Interests After Capital Contributions. On and effective as of the Initial Capital Contribution Date, (i) the Class B Equity Investor and each of JPM, Wells and BAL Investment & Advisory, LLC shall execute and deliver the LLC Agreement, (ii) the Class A Equity Investors (and in the case of BofA, BAL Investment & Advisory, LLC) shall each hold that number of Class A Units as described on Annex B, and (iii) the remaining interests in the Company shall be held by the Class B Equity Investor and shall be converted to that number of Class B Units as described on Annex B.


(e)Certain Funding Matters.
(i)Notwithstanding anything contained herein to the contrary, the failure of one or more of the Class A Equity Investors to make its share of the Capital Contributions on the Initial Capital Contribution Date, the Interim Capital Contribution Dates (if any) or the Final Capital Contribution Date, as applicable as set forth in Section 2.1(a), Section 2.1(b) or Section 2.1(c) shall not relieve the other Class A Equity Investors from their obligation to make their respective share of the Capital Contributions on such Capital Contribution Date and no Class A Membership Interests shall be assigned to any Class A Equity Investor that fails to make its entire share of the Capital Contributions on the Initial Capital Contribution Date.
(ii)Without limiting any rights or remedies available to any Party under the terms of this Agreement, in the event that any of the Class A Equity Investors breaches its obligation to make its share of the Initial Class A Capital Contribution under Section 2.1(a) (any such Class A Equity Investor, a “Non-Funding Class A Equity Investor”), each other Class A Equity Investor which has satisfied, or which has confirmed that it is prepared to satisfy, its respective obligation to make its respective share of the Initial Class A Capital Contribution under Section 2.1(a) (each such Class A Equity Investor, a “Funding Class A Equity Investor”) shall have five (5) Business Days from the date it is notified by the Class B Equity Investor in writing (such notice, a “Default Notice”) that a Non-Funding Class A Equity Investor exists, to elect, at its option, whether or not it (or its Affiliate, so long as such Affiliate either satisfies the criteria set forth in clauses (a) through (c) of the definition of “Approved Investor” in Annex A or provides a guaranty of its Capital Contribution obligations hereunder from a Person satisfies the criteria set forth in clauses (a) through (c) of the definition of “Approved Investor” in Annex A) will take all or a portion of such Non-Funding Class A Equity Investor’s rights and interests in this Agreement (the “Un-Funded Interests”). If the Funding Class A Equity Investors do not elect to take all of the Un-Funded Interests, each Funding Class A Equity Investor agrees to (x) work in good faith with the Class B Equity Investor and not unreasonably withhold, condition or delay any consent to permit the transfer of ITCs that would have been allocated to the Non-Funding Class A Equity Investor to a third party (and, for the avoidance of doubt, the Non-Funding Class A Equity Investor shall not have any consent right over any such transfer of ITCs) and (y) reasonably cooperate with the Class B Equity Investor to identify or designate one or more Approved Investors (including the Class B Equity Investor or an Affiliate of the Class B Equity Investor, if any such Person constitutes an Approved Investor) that agrees to be bound by this Agreement and the other Transaction Documents to the same extent and subject to the same terms and conditions as the Funding Class A Equity Investors (each, a “Replacement Class A Equity Investor”) to satisfy the obligations of the Non-Funding Class A Equity Investor to make its respective share of the Initial Class A Capital Contribution under Section 2.1(a) and to otherwise achieve the interests of the Class B Equity Investor and the Funding Class A Equity Investors hereunder; provided that, if the Class B Equity Investor or any of its Affiliates satisfies the obligations of the Non-Funding Class A Equity Investor to make its respective share of the Initial Class A Capital Contribution under Section 2.1(a), neither the Class B Equity Investor nor any Affiliate thereof shall have the voting or consent rights of a Class A Equity Investor or Class A Member in respect of such interests under any of the Transaction Documents (but, subject to and in accordance with Section 10.11 and Article XI of the LLC Agreement, any successor owner of such interests that is not the Class B Equity Investor or an Affiliate of the Class B Equity Investor shall have the voting and consent rights of a Class A Equity Investor in respect of such interests under the Transaction Documents).
(iii)For the avoidance of doubt, (1) in no event, however, shall the Funding Class A Equity Investor’s obligations set forth in this Section 2.1(e) continue beyond the Outside Date (other than the obligation set forth in Section 2.1(e)(ii)(x)) and (2) the existence of a Non-Funding Class A Equity Investor shall not, in and of itself, be considered a Material Adverse Effect.


(iv)Nothing in this Section 2.1(e) shall release any Non-Funding Class A Equity Investor from its liability to any of the Class B Equity Investor, the Company or the Project Company or any of their respective assignees for such Non-Funding Class A Equity Investor’s failure to make its Class A Capital Contributions as and when required pursuant to the terms of this Agreement.
2.2Adjustments to Base Case Model; Capital Contributions; Escrow.
(a)Adjustments to Base Case Model. On or before, (i) the Initial Capital Contribution Date, the Class B Equity Investor shall cause the Base Case Model to be rerun to incorporate updates to all changes in fact and Law (including, without limitation, the anticipated total Project costs, allocation of tax basis among Asset classes, the anticipated Hot Commissioning dates of each Turbine and the anticipated Placed in Service dates of all other ITC Eligible Property and any updates to the independent consultant reports) and (ii) the Final Capital Contribution Date, the Class B Equity Investor shall cause the Base Case Model to be re-run to incorporate updates to all changes in fact and Law (including, without limitation, the anticipated total Project costs, allocation of tax basis among Asset classes, the Hot Commissioning dates of each Turbine (and, for Additional Turbines, the anticipated Hot Commissioning dates) and the Placed in Service dates of all other ITC Eligible Property (provided however, if the Class B Equity Investor has not provided the Hot Commissioning Tax Confirmation to the Class A Equity Investors on or prior to December 1, 2023, then the Hot Commissioning dates for each Turbine and anticipated Hot Commissioning dates of each Additional Turbine shall not be incorporated into the rerun Base Case Model, and instead, the re-run Base Case Model will be adjusted to reflect the Placed in Service dates of each Turbine and the anticipated Placed in Service dates for each Additional Turbine) and any updates to the independent consultant reports); provided that (x) the Restricted Pricing Assumptions will be changed only as contemplated in Exhibit B attached hereto and (y) the re-run Base Case Model will not include any update for Project operating performance prior to the Final Capital Contribution Date (the “Adjusted Base Case Model”). For the avoidance of doubt, the Base Case Model shall not be re-run as of any Interim Capital Contribution Date.
(b)Adjustments to Capital Contributions. The amount of the Capital Contributions for such Capital Contribution Date shall be adjusted after such update to the Base Case Model in Section 2.2(a) to ensure that the Pricing Parameters have been satisfied.
(c)Escrow. If fewer than 100% of the Turbines have been Placed in Service as of the Final Capital Contribution Date:
(i)The Adjusted Base Case Model run in connection with the Final Capital Contribution Date shall reflect (A) the actual number of Turbines that have been Placed in Service as of the Final Capital Contribution Date and (B) the actual number of Turbines that have not been Placed in Service but which (x) the Class B Equity Investor reasonably expects to be Placed in Service by no later than the Outside Date and (y) the Independent Engineer has certified are reasonably expected to (I) satisfy the clauses (a) through (e) of the definition of Placed in Service and (II) achieve “Taking Over” (as defined in the TSA) in each case, prior to the Outside Date (such Turbines referred to in this subclause (B), the “Additional Turbines”).
(ii)A portion of the Final Class A Capital Contribution, calculated as the Additional Turbine Escrow Factor multiplied by the number of Additional Turbines, will be paid directly into an escrow account (the “Additional Turbine Escrow Account”) governed by the Escrow Agreement.


(iii)For the avoidance of doubt, and without limiting any other provision of this Agreement to the contrary, the Class B Equity Investor and its Affiliates shall use commercially reasonable efforts to cause such Additional Turbines to be Placed in Service by no later than the Outside Date. If the Class B Equity Investor fails to cause any of the Additional Turbines to be Placed in Service by the Outside Date, the Class B Equity Investor shall deliver an Additional Turbine Release Certificate to each of the Class A Equity Investors and the Escrow Agent and the portion of the Final Class A Capital Contribution placed into the Additional Turbine Escrow Account established pursuant to the Escrow Agreement with respect to such Additional Turbines shall be immediately returned to the Class A Equity Investors, together with interest at a rate per annum (based on a 360-day year of twelve 30-day months) equal to the Target IRR for the period commencing on the Final Capital Contribution Date and ending on the date such funds are returned to each Class A Equity Investor (it being understood that (x) interest shall not accrue on any portion of the Final Class A Capital Contribution placed into the Additional Turbine Escrow Account with respect to incomplete Additional Turbines to the extent such incomplete Additional Turbines become Completed Additional Turbines in accordance with clause (iv) below and (y) any portion of the Final Class A Capital Contribution placed into the Additional Turbine Escrow Account that is returned to any Class A Equity Investor pursuant to this Section 2.2(c)(iii), together with interest as calculated in accordance with this Section 2.2(c)(iii), shall be reflected in the “Target IRR Report” (as defined in the LLC Agreement)), and the Class B Equity Investor shall have no liability to any Class A Equity Investor for any loss of ITC or other tax benefits expected from such Turbines.
(iv)If the Class B Equity Investor causes any of such Additional Turbines to become a Completed Additional Turbine, the Class B Equity Investor shall deliver to the Class A Equity Investors a duly completed Additional Turbine Placed in Service Certificate with respect to such Completed Additional Turbine(s), which shall, in connection with the Type Certificate, include the Independent Engineer’s verification of each Major Component for each applicable Completed Additional Turbine, and, promptly following delivery of such Additional Turbine Placed in Service Certificate, the Class A Equity Investors shall instruct the Escrow Agent in writing to release the portion of the Final Class A Capital Contribution placed into the Additional Turbine Escrow Account that is allocable to such Completed Additional Turbine to be distributed to the Class B Equity Investor. Notwithstanding the foregoing, to the extent that any of the Major Components used for any of the applicable Completed Additional Turbines were not set forth on the Type Certificate, subject to all other conditions being satisfied or waived, the aforementioned release and distribution of funds from the Additional Turbine Escrow Account for the Completed Additional Turbines shall occur and Section 6.1(c)(i) of the LLC Agreement shall apply.
(v)If the Class B Equity Investor causes any of the Additional Turbines to become a Completed Additional Turbine then, no later than the earlier of (1) the date of the Additional Turbine Placed in Service Certificate with respect to the final Completed Additional Turbine to be Placed in Service and (2) the Outside Date, the Class B Equity Investor shall deliver to the Class A Equity Investors a Completed Additional Turbine Cost Segregation Report.
(d)Specified Tax Law Change; Capital Contributions in Excess of Commitment.


(i)Specified Tax Law Change. If either (A) there is a Change in Tax Law (without regard to clause (2) of the definition thereof) or (B) the Company obtains a favorable private letter ruling reasonably acceptable to the Class A Equity Investors that, in either case, permits the Project Company to claim an ITC on any or all of the export cable and the Project substation and transformer that are located on land (such change in the case of (A) or (B), a “Specified Tax Law Change”), then the Class B Equity Investor shall (x) re-run the Base Case Model to reflect the Specified Tax Law Change and, if applicable, a Specified TLC Election Notice (as defined in the PSA) while maintaining the Pricing Parameters and (y) obtain an updated Independent Appraisal reflecting updates to the discounted cash flow (DCF) value of the Project solely resulting from the Specified Tax Law Change (with all of the other variables related to the DCF held constant), and the Class A Equity Investors shall have the option (such option, the “Specified TLC Upsize Option”) to increase the Class A Equity Investors’ remaining Capital Contributions to the Company on the subsequent Capital Contribution Dates in an amount equal to the amounts determined by the re-run Base Case Model (the aggregate amount of the incremental payments attributable to the Specified Tax Law Change, the “Specified Capital Contributions”). Each of the Class A Equity Investors shall have a period of no less than 15 days following written notice from the Class B Equity Investor of the occurrence of a Specified Tax Law Change (which such written notice shall include the re-run Base Case Model and updated Independent Appraisal) to provide written notice (the “Specified TLC Upsize Acceptance Notice”) of its agreement to exercise the Specified TLC Upsize Option to the Class B Equity Investor and each other Class A Equity Investor; provided that any obligation of the Class A Equity Investors to make the Specified Capital Contributions shall be conditioned upon delivery of a Specified TLC Upsize Acceptance Notice from each other Class A Equity Investor and satisfaction of the Specified TLC Conditions on or prior to August 1, 2024. Upon delivery of a Specified TLC Upsize Acceptance Notice by all Class A Equity Investors, (x) the Class B Equity Investor shall make a payment of the “Specified Tax Law Change Upsize Fee” (as defined in the Fee Letter) to each Class A Equity Investor in accordance with the Fee Letter and (y) the individual Class A Capital Contribution Cap applicable to each Class A Equity Investor shall be increased by such Class A Equity Investor’s pro rata share of the amount of the Specified Capital Contributions. If any one or more of the Class A Equity Investors does not deliver a Specified TLC Upsize Acceptance Notice prior to the expiration of such 15-day period, then the Class A Equity Investors collectively shall be deemed to have rejected the Specified TLC Upsize Option and the Class B Members shall be permitted to direct the Managing Member to cause the Company to make a Class B ITC Transfer pursuant to Section 9.15(a)(y) of the Company LLC Agreement. Whether or not a Specified Tax Law Change occurs, the Class A Equity Investors will consider in good faith any proposals with respect to claiming the ITC on any or all of the export cable and the Project substation and transformer on land.
(ii)Except to the extent agreed in a Specified TLC Upsize Acceptance Notice as contemplated in Section 2.2(d)(i), in no event shall any Class A Equity Investor be obligated to make Capital Contributions in excess of the individual Class A Capital Contribution Cap applicable to such Class A Equity Investor.
(e)Class B Equity Investor Capital Contributions. On the Initial Capital Contribution Date, subject to the satisfaction or waiver of the conditions set forth in Section 7.1, the Class B Equity Investor shall make a Capital Contribution in cash equal to the Initial Class B Capital Contribution. On each Interim Capital Contribution Date, subject to the satisfaction or waiver of the conditions set forth in Section 7.2, the Class B Equity Investor shall make a Capital Contribution in cash equal to the applicable Interim Class B Capital Contribution; provided that no Interim Class B Capital Contribution will be required if, as of any Interim Capital Contribution Date, the “Cash Portion of the Purchase Price” (as defined in the PSA) has been paid in full (including after taking into account Capital Contributions made by the Class A Equity Investors on such Interim Capital Contribution Date). On the Final Capital Contribution Date, subject to the satisfaction or waiver of the conditions set forth in Section 7.3, the Class B Equity Investor shall make a Capital Contribution in cash in such amount (if any) as is necessary, after taking into account Capital Contributions made by the Class A Equity Investors on such date, to (i) repay the obligations under the Construction Loan Agreement and related Loan Documents in full and discharge any Encumbrances created under the Construction Loan Agreement and the related Loan Documents and otherwise satisfy each of the conditions to the “Effective Time” (as defined in the Construction Loan Payoff Letter), (ii) pay any remaining amount of the “Cash Portion of the Purchase Price” (as defined in the PSA) (including, for the avoidance of doubt, the amount of the Cash Portion of the Purchase Price allocable to any Additional Turbines), (iii) fund the Completion Reserve Account in an aggregate amount such that the balance on deposit therein (together with any Acceptable Guaranty or Acceptable Letter of Credit standing exclusively to the credit thereof) is equal to the Completion Reserve Amount, (iv) fund the Operating Reserve in an aggregate amount such that the balance on deposit therein is equal to the Operating Reserve Required Amount, (v) to fund other operating accounts of the Company such that the total amount on deposit in operating accounts of the Company (other than the Operating Reserve Account) is at least equal to the Minimum Balance Sheet Cash Amount, and (vi) pay the Transaction Expenses and all other amounts set forth in the Final Capital Contribution Date Flow of Funds Memorandum (the “Final Class B Capital Contribution”). For the avoidance of doubt, the Final Class B Capital Contribution may include any deemed fundings resulting from the conversion of the “Loans” (as defined under the Construction Loan Agreement) into the “Term Loans” (as defined in each of the Term Loan Agreements).


2.3Payment of Capital Contributions. The Capital Contributions provided for herein shall be made in immediately available funds by the Class A Equity Investors and the Class B Equity Investor to the Company with respect to each Capital Contribution according to the wire instructions and Flow of Funds Memorandum provided by the Class B Equity Investor to the applicable Capital Contribution Date in accordance with Section 6.1(u), Section 6.2(e) or Section 6.3(s), as applicable.
2.4Use of Proceeds; Release of Reserves; Refunds.
(a)Use of Proceeds on Initial Capital Contribution Date. On the Initial Capital Contribution Date, the Initial Class A Capital Contribution and the Initial Class B Capital Contribution shall be used by the Company to pay to Seller the “Initial Installment” under (and as defined in) the PSA.
(b)Use of Proceeds on each Interim Capital Contribution Date. On each Interim Capital Contribution Date, the applicable Interim Class A Capital Contribution and (if any) the Interim Class B Capital Contribution shall (i) be used by the Company to pay to Seller the applicable “Interim Installment” under (and as defined in) the PSA or (ii) to the extent that the “Cash Portion of the Purchase Price” (as defined in the PSA) has been paid in full as of such Interim Capital Contribution Date, be contributed by the Company to the Project Company as the “Supplemental Sponsor Equity Contribution” (as defined in the Construction Loan Agreement).
(c)Use of Proceeds on Final Capital Contribution Date. On the Final Capital Contribution Date, the Final Class A Capital Contribution and (if any) the Final Class B Capital Contribution shall be used by the Company as follows:
(i)to pay to Seller the “Final Installment” under (and as defined in) the PSA;
(ii)to repay the obligations under the Construction Loan Agreement and related Loan Documents in full and discharge any Encumbrances created under the Construction Loan Agreement and the related Loan Documents;
(iii)to the extent of any Additional Turbines, a portion of the Final Class A Capital Contribution will be deposited into the Additional Turbine Escrow Account in accordance with Section 2.2(c);
(iv)to fund the Completion Reserve Account so that the balance on deposit therein (together with any Acceptable Guaranty or Acceptable Letter of Credit standing exclusively to the credit thereof) is equal to the Completion Reserve Amount;
(v)to pay the Transaction Expenses and all other amounts set forth in the Final Capital Contribution Date Flow of Funds Memorandum; (vi) to fund the Operating Reserve so that the balance on deposit therein is equal to the Operating Reserve Required Amount; and


(vi)to fund other operating accounts of the Company such that the total amount on deposit in operating accounts of the Company (other than the Operating Reserve Account) is at least equal to the Minimum Balance Sheet Cash Amount.
(d)Release of Reserves.
(i)Amounts deposited into the Completion Reserve Account and the Operating Reserve Account shall be released in accordance with the LLC Agreement.
(ii)Amounts deposited into the Additional Turbine Escrow Account shall be released in accordance with clauses (iii) and (iv) of Section 2.2(c) and the Escrow Agreement; provided that any amounts that are paid into the Additional Turbine Escrow Account pursuant to the Escrow Agreement shall be released to the Class B Equity Investor to the extent that the Class B Equity Investor provides an Acceptable Letter of Credit or an Acceptable Guaranty.
(e)Refunds. Upon receipt by the Project Company or the Company of any refund in respect of Taxes or cash deposits, in either case paid by or on behalf of Project Company or the Company on or prior to the Final Capital Contribution Date, the amount so received shall be distributed to the Class B Equity Investor.
2.5Tax Reporting of Transaction. For federal income tax purposes, the Parties agree to report the Transaction as follows:
(a)Immediately prior to the Initial Capital Contribution Date, (i) the Project Company was disregarded as an entity separate from Seller, which is a partnership for federal income tax purposes, and (ii) the Company was disregarded as an entity separate from the Class B Equity Investor, which is a partnership for federal income tax purposes.
(b)The formation of the Company as a partnership for federal income tax purposes will be treated consistently with Revenue Ruling 99-5 (situation 2).
(c)The Parties shall allocate the fair market value among the assets comprising the Project in a manner consistent with the Cost Segregation Report.
(d)The purchase and sale of the Project Company will be treated as a sale of the Project on the Initial Capital Contribution Date for a total purchase price equal to the Purchase Price under, and as defined in, the PSA (not including the assumption of the Project Company’s obligation to fund the expected cost of completing the Project).
(e)To the extent that the Purchase Price under (and as defined in) the PSA is increased pursuant to a Specified TLC Election Notice (as defined in the PSA) and such increase is supported by an acceptable Independent Appraisal and Cost Segregation Report, any Specified Capital Contribution contributed to the Company pursuant to Section 2.2(d)(i) shall be treated as an adjustment to the Purchase Price under, and as defined in, the PSA, paid to the Seller.
ARTICLE III
REPRESENTATIONS AND WARRANTIES OF THE CLASS B EQUITY INVESTOR
The Class B Equity Investor represents and warrants to each Class A Equity Investor as follows, on and as of the ECCA Effective Date and each Capital Contribution Date (except where expressly limited to one of such Capital Contribution Dates or expressly limited to another date, which such representations and warranties are made as of such date(s)):
3.1Organization and Good Standing.
(a)Each of the Class B Equity Investor and the Company is a limited liability company, duly organized, validly existing and in good standing under the Laws of its state of organization. Each of the Class B Equity Investor and the Company has the power to carry on its business as now being conducted. Each Class A Equity Investor has been provided with true, correct and complete copies of the charter documents of the Class B Equity Investor as currently in effect.


(b)Each of the Project Company and Shareco is duly organized, validly existing and in good standing under the Laws of its state of organization. Each of the Project Company and Shareco is qualified to do business and is in good standing in the state in which the Project is located and each other jurisdiction where the character of its property or the nature of its business makes such qualification necessary. Each of the Project Company and Shareco has the power to carry on its business as now being conducted. Each Class A Equity Investor has been provided with true, correct and complete copies of the charter documents of each of the Project Company and Shareco as currently in effect.
3.2Authority; Execution and Delivery; Enforceability. The Class B Equity Investor has the power and authority to execute and deliver the Transaction Documents to which it is a party, to perform its obligations thereunder and to consummate the transactions contemplated therein. As of the ECCA Effective Date or the Initial Capital Contribution Date, as applicable, the execution and delivery by the Class B Equity Investor of the Transaction Documents to which it is a party, and the consummation by it of the transactions contemplated thereby have been duly authorized by all necessary limited liability company or other organizational, as applicable, action. As of the ECCA Effective Date or the Initial Capital Contribution Date, as applicable, the Class B Equity Investor has duly executed and delivered to the Class A Equity Investor the applicable Transaction Documents to which it is a party on such date, and such Transaction Documents, upon execution and delivery thereof, shall constitute its legal, valid and binding obligation, enforceable against it in accordance with its terms.
3.3No Conflicts. The execution and delivery by the Class B Equity Investor of the Transaction Documents to which it is a party and the performance of its obligations thereunder will not (a) violate in any material respect any constitution, statute, regulation, rule, injunction, order, decree, ruling, charge or other restriction of any Governmental Authority to which the Class B Equity Investor, any Project Entity or Shareco is subject, (b) conflict with or cause a breach of any provision in the certificate of formation, certificate of incorporation, limited liability company operating agreement, bylaws or other organizational document of the Class B Equity Investor, any Project Entity or Shareco, (c) cause a material breach of, constitute a default under, cause the acceleration of, create in any party the right to accelerate, terminate, modify or cancel, or require any authorization, consent, waiver or approval under any Contract, license, instrument, decree, judgment or other arrangement to which the Class B Equity Investor, any Project Entity or Shareco is a party or under which any of them is bound or to which any of their Assets are subject or require a consent or approval from, or that a filing or notice be provided to, any Governmental Authority or any other Person (other than any Permits consents, approvals, filings or notices which (i) have been obtained or made and are in full force and effect, (ii) are described in Schedule 3.3 or (iii) are described in Part II of Schedule 3.10) or (d) result in the creation of an Encumbrance on any Project Entity or Shareco or any of their respective Assets, other than Permitted Encumbrances and Permitted Liens.
3.4Absence of Litigation. (a) Except as set forth on Schedule 3.4, there are no actions, suits, proceedings, investigations or similar actions pending or threatened (in writing) against (x) any Sponsor Guarantor or any Governmental Authority with respect to the Project, any of the Assets of any Project Entity or any of the Permits or Departure Approvals set forth on Schedule 3.10 or (y) the Class B Equity Investor, Seller, any Project Entity, Shareco, except in each case such actions, suits, proceedings, investigations or similar actions that could not reasonably be expected to result in a Material Adverse Effect and (b) there are no actions, suits, proceedings, investigations or similar actions pending or threatened (in writing) against the Class B Equity Investor, any Project Entity, Shareco or any Sponsor Guarantor which seek to impair, restrain, prohibit or invalidate any of the Transaction Documents.
3.5Ownership.


(a)(i) The Class B Equity Investor owns of record and beneficially 100% of the Ownership Interests in the Company immediately prior to the Initial Capital Contribution Date and (ii) from and after the Closing Date (as defined in the PSA), the Company owns of record and beneficially 100% of the Ownership Interests in the Project Company. The Project Company owns of record and beneficially 20% of the Ownership Interests in Shareco. Other than Permitted Encumbrances and the PSA, neither the Class B Equity Investor nor the Company has any Contract, arrangement or commitment to issue, sell, transfer or otherwise dispose of any Ownership Interest or any other interest in any Project Entity or Shareco, or any securities or obligations convertible into or exchangeable for, or giving any Person any right to acquire from the Project Entity or Shareco, any such Ownership Interest or other interest in any Project Entity or Shareco, and no such securities or obligations are issued or outstanding other than as contemplated by this Agreement, the LLC Agreement and the Shareco LLC Agreement. Subject to Permitted Liens, the Project Company has good title to the personal property comprising a necessary part of the Project and good title to, or contractual rights to use, all the personal property currently used in connection with the Project as such personal property currently exists.
(b)Other than the Company and, after the Closing Date (as defined in the PSA) has occurred, the Project Company and Shareco, the Class B Equity Investor has no, and has never had any, subsidiaries. The Company has no, and has never had any, subsidiaries other than, after the Closing Date (as defined in the PSA) has occurred, the Project Company and Shareco. Other than Shareco, the Project Company has no, and has never had any, subsidiaries. Other than, after the Closing Date (as defined in the PSA) has occurred, the Assets and liabilities of the Project Company and Shareco, each of the Class B Equity Investor and the Company has never had any Assets or liabilities that do not arise from or otherwise relate to the ownership or operation of the Project, and the Project Company has never had any Assets or liabilities that do not arise from or otherwise relate to the ownership or operation of the Project. The Project Company has not conducted any business other than the development, financing, construction, operation, maintenance and ownership of the Project and activities necessary for, incidental to, related to or desirable in furtherance of the foregoing. The Class B Equity Investor has not conducted any business other than the ownership of the Company and the Company has not conducted any business other than, after the Closing Date (as defined in the PSA) has occurred, the ownership of the Project Company and activities necessary for, incidental to, related to or desirable in furtherance of the foregoing.
3.6Valid Interests. As of the Initial Capital Contribution Date, the Class A Units will be duly authorized, and upon payment of the Initial Class A Capital Contribution, the Class A Units will be validly issued and Class A Equity Investor will have good and valid title to the Class A Units, free and clear of all Encumbrances other than Permitted Encumbrances and those created or granted by the Class A Equity Investors.
3.7Financial Statements. As of the ECCA Effective Date, attached as Schedule 3.7 to this Agreement are the most recently available unaudited interim monthly balance sheet of each Project Entity and Shareco. Each of the interim balance sheets of the Project Entities and Shareco attached hereto as Schedule 3.7, and the interim balance sheets and financial statements delivered pursuant to Sections 6.1(k)(i) and 6.3(cc)(i), presents fairly and accurately, in all material respects, the Assets, liabilities and member(s)’ equity of the applicable Project Entity or Shareco as of the date of such financial statements and interim balance sheets in accordance with the assumptions set forth therein, and has been prepared in accordance with the Accounting Standard, subject, in the case of any unaudited financial statements and interim balance sheets to normal financial statement period-end adjustments in the ordinary course of business and the absence of footnotes. Other than as set forth in the interim balance sheets attached hereto as Schedule 3.7 and the financial statements and interim balance sheets delivered pursuant to Sections 6.1(k)(i) and 6.3(cc)(i), as of the date of such financial statements and interim balance sheets no Project Entity or Shareco has any material liabilities required to be reported in accordance with the Accounting Standard which would be necessary for its balance sheet to meet the standard in the preceding sentence.
3.8Compliance With Laws.


(a)Other than (i) Environmental Laws (which are covered exclusively by the representations made in Section 3.9 and Section 3.10) (ii) tax matters (which are covered exclusively by the representations made in Section 3.16) and (iii) Anti-Money Laundering Laws, Economic Sanctions Laws and Anti-Corruption Laws (which are covered exclusively by the representations made in Section 3.8(b) below), the Class B Equity Investor, each Project Entity and Shareco is in material compliance with all applicable Laws except as listed on Schedule 3.8 and, to the Class B Equity Investor’s Knowledge, there has been no material noncompliance with any applicable Laws by the Class B Equity Investor, any Project Entity or Shareco. Except as has been cured or otherwise resolved in all material respects, each of the Class B Equity Investor, each of the Project Entities and Shareco has been and has conducted the business and operations of the Project in material compliance with all applicable Laws, and has not received written notice from a Governmental Authority of an actual or potential violation of any such Laws, except as listed on Schedule 3.8, and except in each case for Environmental Laws (which are covered exclusively by the representations made in Section 3.9 and Section 3.10), tax matters (which are covered exclusively by the representations made in Section 3.16), and Anti-Money Laundering Laws, Economic Sanctions Laws and Anti-Corruption Laws (which are covered exclusively by the representations made in Sections 3.8(b) and 3.8(c) below).
(b)The Class B Equity Investor, each Project Entity, Shareco, the Sponsor Guarantors and their respective officers, directors, employees and agents (including any third party acting on their behalf), (i) are in compliance with Anti-Money Laundering Laws, Economic Sanctions Laws and Anti-Corruption Laws in all material respects,(ii) to the Class B Equity Investor’s Knowledge, are not under investigation by any Governmental Authority for an alleged violation of Anti-Money Laundering Laws, Economic Sanctions Laws or Anti-Corruption Laws, and (iii) are not Prohibited Persons. The Class B Equity Investor and the Company have implemented and maintain in effect and enforce policies and procedures designed to ensure compliance by the Class B Equity Investor, the Project Entities, Shareco and their respective directors, officers, employees and agents with Anti-Money Laundering Laws, Economic Sanctions Laws and Anti-Corruption Laws.
(c)No part of the proceeds from the funding used to pay the Capital Contributions: (i) will be used directly or indirectly, (A) in connection with any investment in, or any transactions or dealings with, any Prohibited Person or in any country, region or territory that is the subject of Economic Sanctions Laws, (B) for any purpose that would cause any Party hereto to be in violation of any Economic Sanctions Laws or (C) otherwise be in violation of any Economic Sanctions Laws; (ii) will be used, directly or indirectly, in violation of, or cause any party hereto to be in violation of, any applicable Anti-Money Laundering Laws; or (iii) will be used, directly or indirectly, for the purpose of making any improper payments, including bribes, or providing anything of value to any governmental official or commercial counterparty in order to obtain, retain or direct business or obtain any improper advantage, in each case which would be in violation of, or cause any party hereto to be in violation of, any applicable Anti-Money Laundering Law or Anti-Corruption Laws.
(d)The Class B Equity Investor, each Project Entity and Shareco is in material compliance with the Jones Act. Except as has been cured or otherwise resolved in all material respects, each of the Class B Equity Investor, each Project Entity and Shareco has been and has conducted the business and operations of the Project in compliance with the Jones Act, and has not received written notice from a Governmental Authority of an actual or potential violation of the Jones Act.
3.9Environmental Matters. Each Project Entity and Shareco is in compliance with all applicable Environmental Laws in all material respects, except as described on Part I of Schedule 3.9. Other than as listed on Part II of Schedule 3.9, (a) there are no locations or premises within the Project or Project Site or, to the Knowledge of the Class B Equity Investor, at any other location owned, operated, leased or controlled by any Project Entity or Shareco where a Release of a Hazardous Substance has occurred that (i) any Project Entity or Shareco could reasonably be expected to be obligated to investigate, remove, remediate or otherwise respond to because of any requirement of any applicable Environmental Law or any Material Project Agreement or (ii) has resulted in a pending material Claim, or could reasonably be expected to result in, a material Claim against or liability of any Project Entity or Shareco under any applicable Environmental Law, and (b) none of the Class B Equity Investor, any Project Entity or Shareco has received written notice from any Person of any Claim, or any written notice of any investigation, pending or threatened Claim, alleged liability, noncompliance or violation, or any written request for information, in each case, under any applicable Environmental Law and that is material. The representations in this Section 3.9 and Section 3.10 are the sole representations of the Class B Equity Investor as to environmental matters.


3.10Applicable Permits. Other than the Permits set forth in Schedule 3.18:
(a)There are no material Permits issued pursuant to or required under applicable Law (including applicable Environmental Laws) with respect to the Project, as the Project is currently designed and contemplated to be sited, constructed, owned, maintained and operated as contemplated by the Material Project Agreements, that are or will become Applicable Permits with respect to the Project, other than the Permits described in Schedule 3.10.
(b)Each Permit and Departure Approval listed in Part I of Schedule 3.10 has been issued to or made by the Company or the Project Company, or such other Person as allowed under applicable Law, for the benefit of the Project (including any Permits required to be obtained on behalf of the Project Company), is final, in full force and effect (with the exception of any Permits for which there are no further requirements or obligations thereunder and which are no longer required to be in full force and effect in accordance with all applicable Law) and the administrative and judicial periods to appeal such Permits have expired (other than, with respect to judicial periods only, under the Administrative Procedure Act or any citizen suit provision under applicable Law pursuant to which such Permit was issued). Other than as set forth in Schedule 3.4 (x) no judicial appeal has been filed with respect to such Permits or Departure Approvals or all such filed judicial appeals have been resolved, (y) each such Permit and Departure Approval is not subject to any legal proceeding that is pending or threatened in writing (including administrative or judicial appeal, Permit or Departure Approval renewals or modification) seeking injunction, material modification or revocation or (y) each such Permit and Departure Approval is not subject to any material unsatisfied condition required to be satisfied as of the date this representation and warranty is made.
(c)Each Permit listed in Part II of Schedule 3.10 has not yet been obtained because it is not required to be obtained until a future date and either (i) is expected to be obtained by such date and therefore before it becomes an Applicable Permit with respect to the Project or (ii) is of a type that is routinely granted on application, that is ministerial in nature and that would normally be obtained in the ordinary course of business on commercially reasonable terms and conditions prior to the time required by applicable Law.
(d)Each Project Entity and Shareco is in compliance in all material respects with all Applicable Permits and Departure Approvals that have been obtained as of the date of this representation.
(e)None of the Class B Equity Investor, any Project Entity or Shareco has received written notice from any Governmental Authority of an actual or potential material violation, or injunction, modification, revocation or termination, of any Applicable Permit or Departure Approval that has been obtained as of the date of this representation, nor, to the Knowledge of the Class B Equity Investor, has any event occurred and is continuing that constitutes, or after notice or lapse of time or both could reasonably be expected to constitute, a violation of any such Applicable Permit or Departure Approval, or could reasonably be expected to result in any injunction, material modification (including the imposition of any new compliance conditions), revocation or termination of, or any other material adverse change in, any such Applicable Permit or Departure Approval.
3.11Insurance. Attached as Schedule 3.11 to this Agreement is a list of all insurance maintained for the Company and the Project Company. Such Schedule lists all necessary insurance policies relating to the Project prescribed by the Insurance Consultant (unless any such insurance is not then available on commercially reasonable terms), such insurance policies are in full force and effect, and there are no unpaid claims or premiums for any such insurance, except as set forth on Schedule 3.11.
3.12Real Property.


(a)Other than as set forth in Part III of Schedule 3.12, the Project Company has leasehold, fee ownership or easement interests in the Real Property Interests that is the subject of the Key Real Property Documents (subject only to Permitted Liens) sufficient to enable it to construct, own, maintain and operate the Project upon the Project Site. True, complete and correct copies of each of the Real Property Documents for the Project have been Made Available to the Class A Equity Investors. Each of the Real Property Documents for the Project is in full force and effect and is binding on the Project Company, and as applicable, the Company, and to the Knowledge of the Class B Equity Investor, binding on the counterparties thereto. The Project Company and the Company are not, and to the Knowledge of the Class B Equity Investor, no owner of any such real property is, in breach of its material obligations with respect to the Key Real Property Documents, except as set forth in Part IV of Schedule 3.12. All premiums with respect to the Title Policy and all required endorsements have been or will be paid as of the applicable Capital Contribution Date, as and to the extent required in order for the Title Policy and such required endorsements to be valid as of such date.
(b)Other than as set forth in Part III of Schedule 3.12, the Project Company has not assigned or subleased (or sub-subleased if applicable) any of its interests in the Key Real Property Documents. The Real Property Interests held by the Project Company under the Real Property Documents is all the real property that the Project Company leases or has any interest in. To the Class B Equity Investor’s Knowledge, and except as disclosed on Schedule 3.4, the Project Site is not subject to any condemnation proceedings, lawsuits or administrative actions. To the Class B Equity Investor’s Knowledge, the Project Site is not subject to any conservation reserve program or other agricultural reserve program. Except as set forth on the Title Policy, the preliminary ALTA/NSPS survey or as otherwise disclosed in writing by the Class B Equity Investor to each Class A Equity Investor, to the Class B Equity Investor’s Knowledge, there are no unrecorded interests in any portion of the Onshore Project Site, including, without limitation, oil, gas or other mineral rights leases, easements, options, rights to purchase, tenancies, licenses, occupancies, rights of possession claims, encroachments or prescriptive easements.
3.13Indebtedness; Encumbrances. As of the ECCA Effective Date and each Capital Contribution Date, except for the Loan Documents and as disclosed in Part I of Schedule 3.13 or the unaudited interim balance sheets of the Project Entities and Shareco attached hereto as Schedule 3.7, none of the Project Entities or Shareco has any outstanding Indebtedness. The Assets of the Project Entities and Shareco, including the Real Property Interests for the Project, are owned free and clear of all Encumbrances other than Permitted Liens or as set forth in Part II of Schedule 3.13.
3.14Employee Matters. None of the Project Entities or Shareco has and at no point in the past has had any employees, nor maintained, sponsored, administered or participated in any employee benefit plan subject to ERISA. None of the Project Entities or Shareco has any liability in respect of any employees or employee benefit plan and has not incurred any liability by virtue of being a member of a controlled group of corporations or treated as a single employer under Section 4001 of ERISA or 414 of the Code.
3.15Affiliate Transactions. Other than the Material Project Agreements, the Loan Documents, and the Transaction Documents, and except for the Contracts disclosed in Schedule 3.15, there are no Contracts in existence between or among the Class B Equity Investor, the Company or any Affiliate thereof (excluding, for the avoidance of doubt, the Project Company and Shareco), on the one hand, and the Company, the Project Company or Shareco, on the other hand.
3.16Tax Matters.


(a)Each Project Entity and Shareco has timely filed, or caused to be filed on its behalf, all income Tax Returns and all material non-income Tax Returns required to be filed (after giving effect to any extensions that have been requested by and granted to such party by the applicable Governmental Authority, which extensions, if any, will be set forth in Part I of Schedule 3.16 delivered on the Initial Capital Contribution Date), and have timely paid, or caused to be paid on its behalf, all income Taxes and all material nonincome Taxes shown as due on such Tax Returns (other than those Taxes that it is contesting in good faith and by appropriate proceedings, which contests and/or proceedings, if any, are set forth in Part II of Schedule 3.16). All such Tax Returns of the Project Entities and Shareco are complete and accurate in all material respects, except that no representation is being made hereby as to the income Tax characteristics of the Project (including the depreciation allowances for the Project and whether the Project qualifies for the ITC, in each case other than as contained in this Agreement). None of the Project Entities or Shareco has executed (and is not subject to) any waiver currently in effect or agreed to any extension with respect to the statute of limitations for any Taxes or Tax Returns. No audit, examination or other administrative proceedings or court proceedings are presently ongoing, pending or have been threatened in writing with regard to any Taxes or Tax Returns of the Project Entities or Shareco. No written claim has been made by any Tax authority in a jurisdiction where the applicable Project Entity or Shareco does not file a Tax Return that the applicable Project Entity or Shareco is or may be subject to Tax in that jurisdiction. No power of attorney currently in force has been granted by any Project Entity or Shareco (or on such Project Entity’s or Shareco’s behalf) with respect to the Taxes of any such Project Entity or Shareco. Other than pursuant to the Material Project Agreements or the Transaction Documents, no material agreement as to indemnification for, contribution to or payment of Taxes exists between any Project Entity or Shareco and any other Person. Other than pursuant to the Material Project Agreements or the Transaction Documents, none of the Project Entities or Shareco have any liability for Taxes of any Person as a transferee or successor, by Contract or otherwise. None of the Project Entities or Shareco has applied to the IRS or any state tax authority for any Tax ruling with respect to the Project Entity, Shareco or the Project, other than to the extent related to a Specified Tax Law Change as provided by Section 2.2(d)(i), which ruling request has been made available to the Class A Equity Investors.
(b)Each of the Company (until the Initial Capital Contribution Date) and the Project Company is, and has since its formation been, treated as a disregarded entity for U.S. federal income tax purposes, and no elections have been filed with the IRS to treat the Company or Project Company as an association taxable as a corporation. Shareco is treated as a partnership for U.S. federal income tax purposes (and not a publicly traded partnership), Shareco has since its formation been either an entity disregarded as separate from its owner or a partnership for U.S. federal income tax purposes, and no elections have been filed with the IRS to treat Shareco as an association taxable as a corporation.
(c)No more than a de minimis amount of the property, materials or parts that comprise the fair market value of the ITC Eligible Property composing the Project consists of property, materials or parts used by any person other than the Project Company (other than in connection with the construction, start-up, testing and commissioning of the Project).
(d)The Class B Equity Investor is not a Disqualified Person.
(e)The Class B Equity Investor is a “United States person” not subject to withholding under Code Section 1445.
(f)No portion of the Project for which an ITC will be claimed was placed in service for U.S. federal income tax purposes on or prior to the Initial Capital Contribution Date.
(g)As of the Final Capital Contribution Date, (i) each date reflected as the date a Turbine achieved Hot Commissioning (and, for any ITC Eligible Property other than Turbines, the date each such item of ITC Eligible Property was Placed in Service) in the Base Case Model are not earlier than the actual date such Turbine achieved Hot Commissioning (and, for any ITC Eligible Property other than Turbines, the actual date such item of ITC Eligible Property was Placed in Service); provided, however, that no representation or warranty in this clause (i) is made with respect to any Additional Turbines; and (ii) the Hot Commissioning date for each Turbine is the placed in service date for such Turbine for U.S. federal income tax purposes; provided, however, that in the case of each of clause (i) and (ii), if the Class B Equity Investor has not provided the Hot Commissioning Tax Confirmation to the Class A Equity Investors on or prior to December 1, 2023, the references in this Section 3.16(g) to “Hot Commissioning” shall be deemed instead to be references to “Placed in Service”.


(h)As of the Final Capital Contribution Date, the Company’s tax basis in the Project will not be less than the amount provided in the updated Cost Segregation Report (as supported by the Independent Appraisal) delivered pursuant to Section 6.3(g) and reflected in the Base Case Model and the portion of such tax basis allocable to ITC Eligible Property will not be less than the amount allocated to ITC Eligible Property in the updated Cost Segregation Report delivered pursuant to Section 6.3(g) and reflected in the Base Case Model. To the extent that any Additional Turbines have become Completed Additional Turbines, then as of the date on which the last Additional Turbine Placed in Service Certificate is provided, the Company’s tax basis in the Project (including all Completed Additional Turbines) will not be less than the amount provided in the Completed Additional Turbine Cost Segregation Report delivered pursuant to Section 2.2(c)(v) and reflected in the Base Case Model and the portion of such tax basis allocable to ITC Eligible Property will not be less than the amount allocated to ITC Eligible Property in the Completed Additional Turbine Cost Segregation Report delivered pursuant to Section 2.2(c)(v) and reflected in the Base Case Model.
(i)As of the Initial Capital Contribution Date and the Final Capital Contribution Date, the Project “began construction” within the meaning of Code Section 48(a)(9)(B)(ii) and IRS Notice 2021-05 prior to January 29, 2023, and the Project is a “single Project” for purposes of determining whether construction began under Code Sections 45(b)(6)(B)(ii) and 48(a)(9)(B)(ii).
(j)No grant has been applied for under Section 1603 of the American Recovery and Reinvestment Act of 2009 with respect to any property that is part of the Project and as of the Initial Capital Contribution Date, no PTC, ITC or depreciation has been claimed in respect of the Project.
(k)No property included in the Project is “imported property” within the meaning of Code Section 168(g)(6).
(l)All portions of the Project are located in the United States or in the inland navigable waters of the United States or in the coastal waters of the United States.
(m)No bonds the interest of which is exempt from federal income tax were used to provide financing for any portion of the Project.
(n)As of the Final Capital Contribution Date, all Turbines composing the Project (other than Additional Turbines) have been Placed in Service.
(o)As of the date of each Additional Turbine Placed in Service Certificate, all Additional Turbines that are the subject of such Additional Turbine Placed in Service Certificate have been Placed in Service.
3.17Material Project Agreements.
(a)As of the ECCA Execution Date, the Initial Capital Contribution Date and the Final Capital Contribution Date:
(i)Part I of Schedule 3.17 lists all Material Project Agreements for the Project to which any Project Entity or Shareco is a party and, except for the Transaction Documents, Real Property Documents for the Project, Material Project Agreements and the other Contracts listed on Part II of Schedule 3.17 for the Project, none of the Project Entities or Shareco is a party to any other Contract, other than any Contract relating to the Project under which either the current and contingent liability of such Project Entity or Shareco, or the reduction in revenue of such Project Entity or Shareco, could not reasonably be expected to exceed $1,000,000 for such Contract.
(ii)The Material Project Agreements have not been amended, terminated or otherwise modified except as set forth in Schedule 3.17.


(b)The Material Project Agreements have been duly authorized, executed and delivered by the applicable Project Entity or Shareco, are in full force and effect and (i) binding on such Project Entity or Shareco, (ii) in respect of any Material Project Agreements that are between such Project Entity or Shareco, on the one hand, and an Affiliate of the Class B Equity Investor, on the other hand, binding on the other parties thereto and (iii) with respect to any other Material Project Agreement, to the Knowledge of the Class B Equity Investor, binding on the other parties thereto, except in each case as enforceability may be limited by applicable bankruptcy and similar Laws affecting the enforcement of creditors’ rights and general equitable principles.
(c)Except for any default that could not reasonably be expected to have a Material Adverse Effect, (i) none of the Project Entities or Shareco is in default under any Material Project Agreement, (ii) in respect of any Material Project Agreements for the Project that are between a Project Entity or Shareco, on the one hand, and an Affiliate of the Class B Equity Investor, on the other hand, no other party is in default under such Material Project Agreement, and (iii) with respect to any other Material Project Agreement, to the Knowledge of the Class B Equity Investor, no other party is in default under any Material Project Agreement.
(d)The Material Project Agreements listed in Part I of Schedule 3.17 and the other Contracts listed in Part II of Schedule 3.17, in the form Made Available to the Class A Equity Investors, include all material Contracts for services, materials or rights that are reasonably necessary to be obtained by the Project Entities in connection with the construction, ownership, operation and maintenance of the Project, other than those Contracts for services, materials or rights that are not required to be in place as of such date in accordance with Prudent Industry Practices but which the Class B Equity Investor reasonably believes will be obtained in due course and on commercially reasonable terms at or before the time when such services, materials and rights are needed to be in place in accordance with Prudent Industry Practices.
(e)There are no services, materials or rights required for the construction, operation or maintenance of the Project in accordance with the Material Project Agreements other than those (i) available or to be provided under the Material Project Agreements or (ii) that are reasonably expected to be commercially available on commercially reasonable terms at or before the time when such services, materials and rights are needed.
3.18Regulatory Status.
(a)As of the ECCA Effective Date, the Class B Equity Investor is not subject to regulation by FERC as a “public utility” as such term is defined in Section 201(e) of the FPA. None of the Class B Equity Investor or the Company is or, solely as a result of entering into this Agreement or performing its obligations under this Agreement will become, subject to regulation as a “public utility” as defined in Section 201(e) the FPA. As of the ECCA Effective Date, the Project Company is a “public utility” under the FPA with MBR Authority, which authority is in full force and effect.
(b)None of the Class B Equity Investor, the Project Entities or Shareco is subject to, or not exempt from, regulation under PUHCA, except that as of the ECCA Effective Date the Project Company is an EWG and is subject to regulation under PUHCA with respect to maintaining its EWG status. As of the date that the Project first generates electric energy for sale, each of the Company and the Class B Equity Investor will become a “holding company” under PUHCA solely with respect to direct or indirect ownership of an EWG and any regulation as a “subsidiary company” or an “affiliate” of a “holding company,” as such terms are defined in PUHCA, and shall be exempt from FERC regulation under PUHCA to the extent provided in 18 C.F.R. § 366.3(a).
(c)Except for the Permits set forth in Part II of Schedule 3.18, no filing with or consent, order or approval from FERC is required to be made or obtained in order for any Project Entity or Shareco to enter into, deliver or perform the Transaction Documents and the Material Project Agreements to which it is a party or for the ownership and operation of the Project, and the sale or transmission of electric energy, capacity and/or ancillary services therefrom or thereupon.


(d)The Class A Equity Investors will not, solely as a result of entry into or performance of the Transaction Documents or the consummation of the Transaction, including ownership and operation of the Project by the Project Company and the sale or transmission of electric energy, capacity and/or ancillary services therefrom by the Project Company, be subject to, or not exempt from, regulation as an “electric utility company”, a “public-utility company” or a “holding company” or an “affiliate” or “subsidiary company” as defined under PUHCA, or as a “public utility” under the FPA.
3.19Brokers. The Class B Equity Investor has not retained any broker, agent or finder or incurred any liability or obligation for any brokerage fees, commissions or finder fees with respect to this Agreement or the transactions contemplated hereby for which a Class A Equity Investor or any Project Entity or Shareco will be responsible.
3.20Disclosure. All materials and factual information pertaining to the Project or any Project Entity or Shareco, which were Made Available to the Class A Equity Investors or provided in writing by the Class B Equity Investor or its Affiliates to the Independent Appraiser, Cost Segregation Consultant, the Independent Engineer, the Environmental Consultant, the Insurance Consultant, the Transmission Consultant, Wind Consultant or any other expert or consultant relied on or utilized by, as contemplated in the Transaction Documents, the Class A Equity Investors for the purposes of evaluating the transactions contemplated by the Transaction Documents, when taken as a whole, were provided in good faith, did not contain as of the date made or furnished any untrue statement of a material fact or omit to state any material fact necessary to make the statements contained therein, taken as a whole, not misleading as of the date made or furnished in light of the circumstances in which made; provided, however, that no representation or warranty is made with respect to (a) any projections or other forward-looking statements provided by or on behalf of the Class B Equity Investor or its Affiliates (including the Base Case Model), except that such projections were made or prepared in good faith or (b) other than with respect to the specific representations and warranties contained herein, the tax consequences of an investment to the Class A Equity Investors.
3.21Payments of Amounts Due. As of the Final Capital Contribution Date, all amounts necessary to achieve Final Completion of the Project have been paid in full, other than those amounts required to be paid for punch list or similar items, which such amounts have been included in the Base Case Model and the calculation of the Completion Reserve Amount.
3.22Acknowledgment of Limited Nature of Representations and Warranties. The Class B Equity Investor acknowledges that, except with respect to the representations and warranties expressly made by the Class A Equity Investors in this Agreement and the other Transaction Documents or in any certificate, the Class A Equity Investors have not made any representation or warranty, including implied representations and warranties, under this Agreement or any of the other Transaction Documents or otherwise, nor has Class B Equity Investor relied on any representation or warranty not expressly made in this Agreement or the Transaction Documents or in any certificate.
3.23Material Adverse Effect. As of the ECCA Execution Date, since December 31, 2021, no Material Adverse Effect has occurred and is continuing.
3.24No Casualty.
(a)As of the ECCA Execution Date, the Initial Capital Contribution Date and each Interim Capital Contribution Date, no unrepaired casualty exists with respect to the Project that has or could reasonably be expected to have a Material Adverse Effect, unless such event has been remedied or is in the process of being remedied in accordance with a plan approved by the Independent Engineer and is reasonably expected to be remedied by no later than the Outside Date.


(b)As of the Final Capital Contribution Date, no unrepaired casualty exists with respect to the Project, except for any such casualty that (i) could not reasonably be expected to have a Material Adverse Effect or (ii) (A) has been remedied or is in the process of being remedied in accordance with a plan and budget approved by the Independent Engineer and is reasonably expected to be remedied by no later than the date that is 60 days prior to the Outside Date and (B) for which the Project Company has funded a reserve account in an amount greater than or equal to 125% of the aggregate amount that is estimated, as of the Final Capital Contribution Date, to be required to be paid after the Final Capital Contribution Date in connection with remedying such casualty event.
3.25No Condemnation.
(a)As of the ECCA Execution Date, the Initial Capital Contribution Date and each Interim Capital Contribution Date, no condemnation is pending or threatened in writing with respect to the Project that has or could reasonably be expected to have a Material Adverse Effect, unless such event has been remedied or is in the process of being remedied in accordance with a plan approved by the Independent Engineer and is reasonably expected to be remedied by no later than the Outside Date.
(b)As of the Final Capital Contribution Date, no condemnation is pending or threatened in writing with respect to the Project, except for any such condemnation event that (i) could not reasonably be expected to have a Material Adverse Effect or (ii) (A) has been remedied or is in the process of being remedied in accordance with a plan and budget approved by the Independent Engineer and is reasonably expected to be remedied by no later than the date that is 60 days prior to the Outside Date and (B) for which the Project Company has funded a reserve account in an amount greater than or equal to 125% of the aggregate amount that is estimated to be required to be paid after the Final Capital Contribution Date in connection with remedying such condemnation event.
3.26No Adverse Guarantor Event. No Adverse Guarantor Event has occurred since the ECCA Effective Date, unless an Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support reasonably acceptable to the Class A Equity Investors has been provided by the Class B Equity Investor to replace the Sponsor Guaranty for which the Adverse Guarantor Event applies.
3.27Loan Documents. As of the ECCA Execution Date and the Initial Capital Contribution Date, no “Event of Default” or material “Default” (in each case, as defined in the Construction Loan Agreement) has occurred and is continuing, except to the extent such material “Default” or “Event of Default” (in each case, as defined in the Construction Loan Agreement) will be cured by the funding of the Initial Class A Capital Contribution and the Initial Class B Capital Contribution (with respect to any material “Default” or “Event of Default” (in each case, as defined in the Construction Loan Agreement) that has occurred and is continuing as of the Initial Capital Contribution Date). As of each Interim Capital Contribution Date, no “Event of Default” (as defined in the Construction Loan Agreement) has occurred and is continuing, except to the extent such “Event of Default” (as defined in the Construction Loan Agreement) will be cured by the funding of the applicable Interim Class A Capital Contribution and Interim Class B Capital Contribution (with respect to any “Event of Default” (as defined in the Construction Loan Agreement) that has occurred and is continuing as of any Interim Capital Contribution Date). As of the Final Capital Contribution Date, no “Event of Default” or material “Default”(in each case, as defined in the Construction Loan Agreement) has occurred and is continuing, except to the extent such material “Default” or “Event of Default” (in each case, as defined in the Construction Loan Agreement) will be cured by the funding of the Final Class A Capital Contribution (with respect to any material “Default” or “Event of Default” (in each case, as defined in the Construction Loan Agreement) that has occurred and is continuing as of the Final Capital Contribution Date).
3.28Turbine Injunction. The Turbines comprising the Project will be or have been excluded from any injunction or similar order with respect to the manufacturing, installing, operating, repairing or replacing the Project in relation to Siemens Gamesa Renewable Energy A/S v. General Electric Co. et al, Case No. DMA-1:21-cv-10216 (D. Mass) or any subsequent proceedings related to the settlement of such proceedings.


ARTICLE IV
REPRESENTATIONS AND WARRANTIES OF EACH CLASS A EQUITY INVESTOR
Each Class A Equity Investor hereby represents and warrants, as to itself only, to the Class B Equity Investor as follows, on and as of the ECCA Effective Date and each Capital Contribution Date (except where expressly limited to one of such Capital Contribution Dates or expressly referencing another date) that:
4.1Organization and Good Standing. Such Class A Equity Investor is a corporation duly incorporated, validly existing and in good standing under the Laws of the jurisdiction of its formation, and it has the corporate power and authority to carry on its business as now being conducted. The Class B Equity Investor has been provided with true, correct and complete copies of the charter documents of such Class A Equity Investor as currently in effect.
4.2Authority. Such Class A Equity Investor has the corporate power and authority to execute and deliver the Transaction Documents to which it is a party, to perform its obligations thereunder, and to consummate the transactions contemplated therein.
4.3No Conflicts. The execution and delivery of the Transaction Documents to which such Class A Equity Investor is a party and the performance by such Class A Equity Investor of its obligations thereunder will not (a) violate in any material respect any constitution, statute, regulation, rule, injunction, order, decree, ruling, charge or other restriction of any Governmental Authority to which such Class A Equity Investor is subject, (b) conflict with or cause a breach of any provision in the charter, bylaws or other organizational documents of such Class A Equity Investor or (c) cause a material breach of, constitute a default under, cause the acceleration of, create in any party the right to accelerate, terminate, modify or cancel, or require any authorization, consent, waiver or approval under any Contract, license, instrument, decree, judgment or other arrangement to which such Class A Equity Investor is a party or under which it is bound or to which any of its Assets are subject (or result in the imposition of a security interest or Encumbrance upon any such Assets) or require a consent or approval from, or that notice be provided to, any Governmental Authority or any other Person (other than any consents, approvals or notices that are obtained or made prior to the applicable Capital Contribution Date).
4.4Absence of Litigation. Such Class A Equity Investor is not subject to any action, suit, proceeding, hearing or investigation of, in or before any Governmental Authority or before any arbitrator, or, to the knowledge of such Class A Equity Investor, is threatened with being made a party to any action, suit, proceeding, hearing or investigation of, in or before any Governmental Authority or before any arbitrator, that could affect its ability to complete the transactions contemplated in the Transaction Documents to which it is a party or materially adversely affect its ability to perform any of its respective obligations under the Transaction Documents to which it is a party.
4.5Investment Intent. Such Class A Equity Investor represents that it is acquiring the Class A Membership Interests for its own account and not for the account of any other Person and not with a view to distribution or resale to others in a manner that would violate any federal or state securities Laws; provided, however, each Class A Equity Investor may Transfer all or a portion of its Class A Membership Interests in accordance with the LLC Agreement.
4.6Accredited Class A Equity Investor. Such Class A Equity Investor is an “accredited investor” as such term is defined in Regulation D under the Securities Act. It has had a reasonable opportunity to ask questions of and receive answers from the Class B Equity Investor and the Project Entities concerning the Class B Equity Investor, the Class A Membership Interests and the Project Entities, and all such questions have been answered to the full satisfaction of such Class A Equity Investor. It has relied solely on its own legal, tax and financial advisors for its evaluation of an investment in the Class A Membership Interests and not on the advice of the Class B Equity Investor or the Project Entities or any of their respective legal, tax or financial advisors. Nothing in this Section 4.6 shall be construed as limiting a Class A Equity Investor’s reliance on the representations and warranties of the Class B Equity Investor set forth in this Agreement.
4.7No Registration. Such Class A Equity Investor understands that the Class A Membership Interests have not been registered under the Securities Act in reliance on an exemption therefrom, and that the Class A Membership Interests must be held indefinitely unless the sale thereof is registered under the Securities Act, or an exemption from registration is available thereunder, and that the Class B Equity Investor is under no obligation to register the Membership Interests under the Securities Act. Such Class A Equity Investor understands and agrees that it will not sell, hypothecate or otherwise transfer the Class A Membership Interests without registering or qualifying them under the Securities Act and applicable state securities Laws unless the transfer is exempted from registration or qualification under such Laws.


4.8Forward-Looking Information. Such Class A Equity Investor recognizes that investment in the Class A Membership Interests involves substantial risks. It acknowledges that any financial projections that may have been provided to it are based on assumptions of future operating results developed by the Class B Equity Investor’s and the Project Entities’ advisors and, therefore, represent an estimate of future results based on assumptions about certain events (many of which are beyond the control of the Class B Equity Investor or the Project Entities). It understands that no assurances or representations (other than those provided in Section 3.20(a)) can be given that the actual results of the operations of the Project Entities will conform to the projected results for any period.
4.9Acknowledgment of Limited Nature of Representations and Warranties. Such Class A Equity Investor acknowledges that, except with respect to the representations and warranties expressly made by the Class B Equity Investor in this Agreement (which shall be subject to the limitations herein) or any of the other Transaction Documents, or in any certificates delivered pursuant hereto or thereto, the Class B Equity Investor has not made any representation or warranty, including implied representations and warranties, under this Agreement or any of the other Transaction Documents, or in any certificates delivered pursuant hereto or thereto, and nor has such Class A Equity Investor relied on any representation or warranty not expressly made in this Agreement or any of the other Transaction Documents, or in any certificates delivered pursuant hereto or thereto. Such Class A Equity Investor specifically acknowledges that, other than as explicitly set forth in Section 3.20, no representation or warranty has been made and that such Class A Equity Investor has not relied on any representation or warranty regarding the accuracy of any projections or forward-looking statements made by the Class B Equity Investor or its respective Affiliates in the Base Case Model.
4.10Brokers. Such Class A Equity Investor has not retained any broker, agent or finder or incurred any liability or obligation for any brokerage fees, commissions or finder fees with respect to this Agreement or the transactions contemplated hereby for which the Class B Equity Investor or any Project Entity will be responsible.
4.11Tax Status. Such Class A Equity Investor is not a Disqualified Person. Such Class A Equity Investor (or if such Class A Equity Investor is a disregarded entity for U.S. federal income tax purposes, its regarded owner for such purpose) is a United States person within the meaning of Code Section 7701(a)(3) and is not subject to withholding under Code Section 1446. Such Class A Equity Investor is not related, within the meaning of Code Sections 267(b) and 707(b)(1), to any identified purchaser of electricity produced by the Project.
ARTICLE V
CONDITIONS TO ECCA EFFECTIVE DATE OBLIGATIONS
5.1Class A Equity Investor ECCA Effective Date Conditions Precedent. The effectiveness of this Agreement is subject to the satisfaction, or waiver by the Class A Equity Investors, of each of the conditions set forth in this Section 5.1. The execution and delivery to the Class B Equity Investor of this Agreement by the Class A Equity Investors evidences the satisfaction, or waiver by the Class A Equity Investors, of each such condition.
(a)Transaction Documents. The Class A Equity Investors shall have received fully executed, complete and correct copies of this Agreement, the PSA, the Fee Letter and the Investor Consents (Term Loan Agreements). Each of the Class B Equity Investor and the Project Entities shall have performed in all material respects its obligations under the Transaction Documents to which it is a party to be performed on or prior to the ECCA Effective Date.


(b)Representations and Warranties. Each of the representations and warranties of the Class B Equity Investor contained in Article III of this Agreement and of the Class B Equity Investor and its Affiliates in any other Transaction Document shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the ECCA Effective Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of such date).
(c)Material Project Agreements. Copies of all Material Project Agreements that have been executed and delivered on or prior to the ECCA Effective Date shall have been Made Available to the Class A Equity Investors. Each of the Material Project Agreements shall be in full force and effect.
(d)Permits. Copies of all Permits and Departure Approvals for the Project that were obtained on or prior to the ECCA Effective Date shall have been Made Available to the Class A Equity Investors. Each such Permit and Departure Approval shall have been validly issued or made.
(e)No Encumbrances. Except for Permitted Encumbrances and Permitted Liens, there shall be no Encumbrances against the Project, any Project Entity, Shareco or any Assets of a Project Entity or Shareco.
(f)No Condemnation. No condemnation shall be pending or threatened in writing with respect to the Project, unless such event has been remedied or is in the process of being remedied in accordance with a plan approved by the Independent Engineer and is reasonably expected to be remedied by no later than the Outside Date.
(g)No Action or Proceeding. (i) Except as set forth on Schedule 3.4, no actions, suits, proceedings, investigations or similar actions shall have been threatened or instituted in writing against (x) any Sponsor Guarantor or any Governmental Authority with respect to the Project, any of the Assets of any Project Entity or any of the Permits or Departure Approvals set forth on Schedule 3.10 or (y) the Class B Equity Investor, Seller, any Project Entity, Shareco, in each case, that has or could reasonably be expected to have a Material Adverse Effect and (ii) no actions, suits, proceedings, investigations or similar actions shall have been threatened or instituted in writing against the Class B Equity Investor, any Project Entity, Shareco or any Sponsor Guarantor which seek to impair, restrain, prohibit or invalidate any of the Transaction Documents.
(h)Base Case Model. The Base Case Model shall be acceptable to the Class A Equity Investors.
(i)Financial Statements. The Class A Equity Investors shall have received (i) the most recently available unaudited interim monthly balance sheets of the Project Entities and Shareco, (ii) the most recently available quarterly unaudited financial statements and annual audited financial statements of the Project Entities and (iii) the most recent annual audited financial statements and quarterly unaudited financial statements of the Sponsor Guarantors prepared in accordance with the Accounting Standard, together with a certificate from an authorized officer of the applicable Sponsor Guarantor that such financial statements present fairly in all material respects the financial position and results from operations of such Sponsor Guarantor and its consolidated subsidiaries as of the applicable date thereof and for the periods then ended, subject to, in the case of such unaudited interim financial statements, normal year-end audit adjustments and the absence of footnotes; provided that, if (X) any such entity files an annual report on Form 10-K (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable annual audited financial statements shall be deemed to have been received by the Class A Equity Investors for purposes of this clause (iii) and (Y) any such entity files a quarterly report on Form 10-Q (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable quarterly unaudited financial statements shall be deemed to have been received by the Class A Equity Investors for purposes of this clause (iii).


(j)Legal Opinions. The Class A Equity Investors shall have received copies of the following, each in form and substance reasonably acceptable to the Class A Equity Investors: (i) a legal opinion from Kirkland & Ellis LLP with respect to customary corporate matters (including due authorization, execution and delivery; no conflicts; no violation; and no further consents) and the enforceability of the Transaction Documents entered into on the ECCA Effective Date; (ii) a legal opinion from Kirkland & Ellis LLP with respect to federal energy regulatory matters with respect to the Project; (iii) a legal opinion from Foley Hoag LLP with respect to state and local permitting matters with respect to the Project; (iv) a legal opinion from Sidley Austin LLP with respect to federal environmental permitting matters with respect to the Project and (v) a legal memorandum from Plesner Advokatpartnerselskab with respect to certain corporate matters relating to the CI II Guarantors and CI III Guarantors.
(k)Tax Opinion. Class A Equity Investor shall have received an opinion from Milbank LLP in form and substance satisfactory to the Class A Equity Investors with respect to the federal income tax consequences of its investment.
(l)Officer’s Certificate. The Class A Equity Investors shall have received an omnibus certificate of an authorized officer of the Class B Equity Investor (i) certifying as to the matters set forth in Section 5.1(b) above and (ii) attaching true, accurate and complete copies of (A) the organizational documents of each of the Class B Equity Investor and the Project Entities, including formation documents and operating agreements or bylaws, as applicable, (B) the resolutions authorizing the execution of the Transaction Documents by each such Person to which it is a party, (C) a good standing certificate with respect to each such entity, and (D) an incumbency certificate from each of the Class B Equity Investor and the Project Entities.
(m)Consents and Approval. All consents, approvals and filings required to be obtained or made with any Governmental Authority or any other Person (except the Class A Equity Investors) in order for each party thereto to execute, deliver and perform the Transaction Documents to which such entity is a party shall have been obtained or made and shall be in full force and effect as of the ECCA Effective Date.
(n)Transmission Consultant’s Report. The Class A Equity Investors shall have received a copy of the Transmission Consultant’s Report (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors) with respect to the Project, in form and substance reasonably satisfactory to the Class A Equity Investors.
(o)Independent Engineer’s Report. The Class A Equity Investors shall have received a copy of the Independent Engineer’s Report (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors) with respect to the Project, in form and substance reasonably satisfactory to the Class A Equity Investors.
(p)Wind Consultant’s Report. The Class A Equity Investors shall have received a copy of the Wind Consultant’s Report (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors) with respect to the Project, in form and substance reasonably satisfactory to the Class A Equity Investors.
(q)Phase I Environmental Site Assessment Report. The Class A Equity Investors shall have received a copy of the Phase I Environmental Site Assessment Report (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors) with respect to the Project, in form and substance reasonably satisfactory to the Class A Equity Investors.
(r)Insurance Consultant’s Report. The Class A Equity Investors shall have received a copy of the report of the Insurance Consultant (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors) with respect to the Project, in form and substance reasonably satisfactory to the Class A Equity Investors.


(s)ALTA/NSPS Survey. The Class A Equity Investors shall have received copies of the pre-construction ALTA/NSPS surveys of the Onshore Project Site (other than the portion of the Onshore Project Site leased by the Project Company pursuant to the New Bedford Terminal Lease) that were delivered in connection with the “Closing Date” under (and as defined in) the Construction Loan Agreement.
(t)Title Insurance. The Class A Equity Investors shall have received (i) a copy of the Title Insurance Policy and (ii) a copy of the ALTA 33 Endorsement issued by the Title Company in connection with the most recent borrowing of a “Construction Loan” or “Construction Bridge Loan” (in each case, as defined in the Construction Loan Agreement).
(u)Cost Segregation Report. The Class A Equity Investors shall have received a copy of the preliminary Cost Segregation Report with respect to the Project, in form and substance reasonably acceptable to the Class A Equity Investors.
(v)Independent Appraisal. The Class A Equity Investors shall have received a copy of a draft of the Independent Appraisal with respect to the Project, in form and substance reasonably acceptable to the Class A Equity Investors.
(w)Beneficial Ownership Certification. (i) Each Class A Equity Investor shall have received documentation and information sufficient to complete “know your customer” or “know your partners” checks and analyses with respect to Sponsor Guarantors, the Class B Equity Investor and any of the Class B Equity Investor’s Affiliates, and the results of such checks and analyses shall have satisfied its institutional requirements and (ii) at least five (5) days prior to the ECCA Effective Date, Sponsor Guarantors and the Class B Equity Investor shall have delivered (A) a Beneficial Ownership Certification in relation to such entity and (B) a Legal Entity Controlling Ownership Questionnaire.
(x)Loan Documents. No “Event of Default” or material “Default” (in each case, as defined in the Construction Loan Agreement) shall have occurred and be continuing.
5.2Class B Equity Investor ECCA Effective Date Conditions Precedent. The effectiveness of this Agreement is subject to the satisfaction, or waiver by the Class B Equity Investor, of each of the conditions set forth in this Section 5.2. The execution and delivery to the Class A Equity Investors of this Agreement by the Class B Equity Investor evidences the satisfaction, or waiver by the Class B Equity Investor, of each such condition.
(a)Transaction Documents. The Class B Equity Investor shall have received fully executed, complete and correct copies of this Agreement, the PSA and the Investor Consents (Term Loan Agreements).
(b)Representations and Warranties. Each of the representations and warranties of each of the Class A Equity Investors contained in Article IV of this Agreement and of each of the Class A Equity Investors and their Affiliates in any other Transaction Document shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the ECCA Effective Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of such date).
(c)No Governmental Action. No action or proceeding has been threatened or instituted in writing by any Governmental Authority against any Class A Equity Investor, which seeks to impair, restrain, prohibit or invalidate any of the Transaction Documents.


(d)Base Case Model. The Base Case Model shall be acceptable to the Class B Equity Investor.
(e)Legal Opinion. The Class B Equity Investor shall have received a legal opinion from Milbank LLP with respect to enforceability of the Transaction Documents entered into on the ECCA Effective Date, in form and substance reasonably acceptable to the Class B Equity Investor.
(f)Officer’s Certificates. The Class B Equity Investor shall have received an omnibus certificate of an authorized officer of each Class A Equity Investor certifying as to (i) the matters set forth in Section 5.2(b) above and (ii) corporate matters of such Class A Equity Investor, in form and substance satisfactory to the Class B Equity Investor.
(g)Consents and Approval. All consents, approvals and filings required to be obtained or made with any Governmental Authority or any other Person (except the Class B Equity Investor or its Affiliates) in order for each party thereto to execute, deliver and perform the Transaction Documents to which such entity is a party shall have been obtained or made and shall be in full force and effect as of the ECCA Effective Date.


ARTICLE VI
CONDITIONS TO OBLIGATIONS OF THE CLASS A EQUITY INVESTORS;
CERTAIN CLASS B EQUITY INVESTOR COVENANTS
6.1Initial Capital Contribution Date Conditions Precedent. The obligations of the Class A Equity Investors to make the Initial Class A Capital Contribution on the Initial Capital Contribution Date shall be subject to the satisfaction of each of the conditions set forth below, any of which may be waived in writing, in whole or in part, by the Class A Equity Investors:
(a)Notice of Initial Capital Contribution Date. The Class A Equity Investors shall have received not less than four Business Days’ prior written notice from the Class B Equity Investor of the Initial Capital Contribution Date.
(b)Mechanical Completion. (i) Mechanical Completion for the “Electric Service Platform” (as defined in the ESP Supply Agreement), the “Offshore Export Cables” (as defined in the Export Cable Agreement), the “Onshore Substation” (as defined in the Onshore Substation Agreement), the “Onshore Cable Civil Works” (as defined in the Onshore Cable Agreement) and at least one full string of Turbines and the corresponding “Array Cables” (as defined in the Array Cable Agreement) has occurred, and (ii) no portion of the Project for which an ITC will be claimed has been Placed in Service.
(c)Transaction Documents. The LLC Agreement shall have been executed by the Class B Equity Investor and delivered to the Class A Equity Investors, and the Sponsor Guaranties shall have been executed by the applicable Sponsor Guarantors and wet ink, original signatures shall have been delivered to the Class A Equity Investors. Each of the Class B Equity Investor, the Seller, the Sponsor Guarantors and the Project Entities shall have performed in all material respects its obligations under the Transaction Documents to which it is a party to be performed on or prior to the Initial Capital Contribution Date.
(d)PSA Closing. Concurrently with the transactions contemplated on the Initial Capital Contribution Date, Seller shall have sold, and the Company shall have purchased, 100% of the Ownership Interests in the Project Company pursuant to the PSA.
(e)Representations and Warranties. Each of the representations and warranties of the Class B Equity Investor contained in Article III of this Agreement shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the Initial Capital Contribution Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of such date).
(f)Material Project Agreements. Copies of all Material Project Agreements that have been executed and delivered after the ECCA Effective Date but on or prior to the Initial Capital Contribution Date shall have been Made Available to the Class A Equity Investors and are reasonably satisfactory to the Class A Equity Investors. Each of the Material Project Agreements with respect to the Project shall be in full force and effect, and there shall exist no default that could reasonably be expected to result in termination of such Material Project Agreement. All material amendments to the Material Project Agreements that have been entered into since the ECCA Effective Date (other than amendments and change orders under the Construction Contracts for which the execution thereof would not constitute a “Fundamental Decision” or a “Major Decision” (in each case, as defined in the LLC Agreement)) shall be reasonably acceptable to the Class A Equity Investors.
(g)Cost Segregation Report. The Class A Equity Investors shall have received a copy of an updated draft of the Cost Segregation Report with respect to the Project, which shall have been incorporated into the Base Case Model, in form and substance reasonably acceptable to the Class A Equity Investors.


(h)Independent Appraisal. The Class A Equity Investors shall have received a copy of an updated draft of the Independent Appraisal with respect to the Project, which shall have been incorporated into the Base Case Model, in form and substance reasonably acceptable to the Class A Equity Investors.
(i)Base Case Model. The Base Case Model shall have been updated pursuant to Section 2.2(a), evidencing satisfaction of the Pricing Parameters to the reasonable satisfaction of the Class A Equity Investors, and delivered to the Class A Equity Investors together with an update to Schedule 13.2(e) of the LLC Agreement reasonably satisfactory to the Class A Equity Investors.
(j)Annual Operating Budget. The Class A Equity Investors shall have received an initial Annual Operating Budget for the Company and the Project that is consistent with the Base Case Model.
(k)Financial Statements. The Class A Equity Investors shall have received (i) the most recently available unaudited interim monthly balance sheets of each Project Entity and Shareco, (ii) the most recently available quarterly unaudited financial statements and annual audited financial statements of each Project Entity and (iii) the most recent annual audited financial statements and quarterly unaudited financial statements of the Sponsor Guarantors prepared in accordance with the Accounting Standard, together with a certificate from an authorized officer of the applicable Sponsor Guarantor that such financial statements present fairly in all material respects the financial position and results from operations of such Sponsor Guarantor and its consolidated subsidiaries as of the applicable date thereof and for the periods then ended, subject to, in the case of such unaudited interim financial statements, normal year-end audit adjustments and the absence of footnotes; provided that, if (X) any such entity files an annual report on Form 10-K (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable annual audited financial statements shall be deemed to have been received by the Class A Equity Investors for purposes of this clause (iii) and (Y) any such entity files a quarterly report on Form 10-Q (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable quarterly unaudited financial statements shall be deemed to have been received by the Class A Equity Investors for purposes of this clause (iii).
(l)Transmission Consultant’s Report. The Class A Equity Investors shall have received a copy of a bring-down of the Transmission Consultant’s Report delivered pursuant to Section 5.1(n) (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), in form and substance reasonably satisfactory to the Class A Equity Investors (including with respect to updates, if any, with respect to any Incremental Offtake Agreements).
(m)Independent Engineer’s Report; Independent Engineer’s Initial Capital Contribution Date Certificate; Mechanical Completion Schedule. The Class A Equity Investors shall have received (i) a copy of the construction supplement to the Independent Engineer’s Report delivered pursuant to Section 5.1(o) (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), which shall be in form and substance reasonably satisfactory to the Class A Equity Investors and (ii) a certificate from the Independent Engineer, substantially in the form of Exhibit D-1, (A) confirming that (1) Mechanical Completion for the “Electric Service Platform” (as defined in the ESP Supply Agreement), the “Offshore Export Cables” (as defined in the Export Cable Agreement), the “Onshore Substation” (as defined in the Onshore Substation Agreement), the “Onshore Cable Civil Works” (as defined in the Onshore Cable Agreement) and at least one full string of Turbines and the corresponding “Array Cables” (as defined in the Array Cable Agreement) has occurred and (2) at least 75% of the nameplate capacity of each of “Facility 1” and “Facility 2” (as such terms are defined in the PPAs) is reasonably expected to achieve Substantial Completion by the Outside Date and (B) attaching a schedule of (1) actual Mechanical Completion dates for each Turbine that has achieved Mechanical Completion on or before the Initial Capital Contribution Date and (2) projected Mechanical Completion dates for each of the Turbines (such schedule, as supplemented as of any Interim Capital Contribution Date, the “Mechanical Completion Schedule”).


(n)Wind Consultant’s Report. The Class A Equity Investors shall have received a copy of the bring-down of the Wind Consultant’s Report delivered pursuant to Section 5.1(p) (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), in form and substance reasonably satisfactory to the Class A Equity Investors; provided that the Class B Equity Investor shall not be required to deliver such bring-down report if none of the following have occurred, as confirmed in writing to the Class A Equity Investors by the Wind Consultant: (i) a change in the location of any Turbine in excess of 500 feet or any other material change to the Project layout, (ii) changes to the power curve if the Turbine Supplier has restated or adjusted the power curve for the Turbines (specifically for the Turbines in the Project) or (iii) known changes in the location of any Turbine in a neighboring wind farm accounted for in the Wind Consultant’s Report delivered pursuant to Section 5.1(p).
(o)Phase I Environmental Site Assessment Report. (i) If less than one year has elapsed since the date of the site visit, records review, lien search, environmental professional’s declaration, and owner/operator interviews performed for the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q) and either (x) more than 180 days have elapsed since the date of the site visit, records review, lien search, environmental professional’s declaration, and owner/operator interviews performed for the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q) or (y) to the Knowledge of the Class B Equity Investor, there have been changes to the Project that would materially impact the conclusions set forth in the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q), the Class A Equity Investors shall have received a copy of a bring-down of the applicable sections of the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q); or (ii) if one year or more has elapsed since the date of the site visit, records review, lien search, environmental professional’s declaration, and owner/operator interviews performed for the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q), the Class A Equity Investors shall have received a new Phase I Environmental Site Assessment, in each case, including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors and in form and substance reasonably satisfactory to the Class A Equity Investors.
(p)Insurance Consultant’s Report. The Class A Equity Investors shall have received a copy of a bring-down of the report of the Insurance Consultant for the Project delivered pursuant to Section 5.1(r) (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), in form and substance reasonably satisfactory to the Class A Equity Investors (including with respect to updates, if any, with respect to any Incremental Offtake Agreements).
(q)Insurance Certificates. The Class A Equity Investors shall have received copies of insurance certificates with respect to the insurance necessary for the Project, as prescribed by the Insurance Consultant and set forth in Schedule 3.11 of this Agreement.
(r)Estoppels. The Class A Equity Investors shall have received estoppels from the counterparties to the Construction Contracts who have substantially completed their work under the applicable Construction Contract on or before the Initial Capital Contribution Date (other than with respect to the HDD Agreement and the Material Project Credit Support Documents), in substantially the forms attached hereto as Exhibits E-1, E-2, E-3, E-4, E-5, E-6, E-7, E-8, E-9, E-10, E-11 and E-12, as applicable; provided that to the extent that an estoppel from a counterparty to a Construction Contract is not available despite the use of commercially reasonable efforts, then this Section 6.1(r) shall be deemed satisfied with respect to such estoppel(s) and Section 8.1(a)(ii) shall apply with respect to such estoppel(s).


(s)Legal Opinions. The Class A Equity Investors have received copies of the following, each in form and substance reasonably satisfactory to the Class A Equity Investors: (i) a legal opinion from Morris James LLP with respect to the enforceability of the LLC Agreement, substantially in the form attached hereto as Exhibit M-1; (ii) a legal opinion from Kirkland & Ellis LLP with respect to customary corporate matters of the Avangrid Guarantor and the enforceability of the Sponsor Guaranties, substantially in the form attached hereto as Exhibit M-2; (iii) a Danish legal opinion of Plesner Advokatpartnerselskab with respect to customary corporate matters of the CI II Guarantors, substantially in the form attached hereto as Exhibit M-3a; (iv) a Danish legal opinion of Plesner Advokatpartnerselskab with respect to customary corporate matters of the CI III Guarantors, substantially in the form attached hereto as Exhibit M-3b; (v) a bring-down of the legal opinion delivered by Kirkland & Ellis LLP pursuant to Section 5.1(j)(ii), substantially in the form attached hereto as Exhibit M-4; (vi) a bring-down of the legal opinion delivered by Foley Hoag LLP pursuant to Section 5.1(j)(iii), substantially in the form attached hereto as Exhibit M-5; and (vii) a bring-down of the legal opinion delivered by Sidley Austin LLP pursuant to Section 5.1(j)(iv), substantially in the form attached hereto as Exhibit M-6.
(t)Tax Opinion. The Class A Equity Investors shall have received a bringdown of the tax opinion delivered by Milbank LLP in connection with the ECCA Effective Date pursuant to Section 5.1(k) in form and substance satisfactory to the Class A Equity Investors, which opinion shall be limited to addressing any Change in Tax Law or other change in or update to material facts or the circumstances relevant to the tax opinion provided in connection with the ECCA Effective Date.
(u)Flow of Funds; Transaction Expenses. The flow of funds memorandum with respect to the Initial Capital Contribution Date (the “Initial Capital Contribution Date Flow of Funds Memorandum”), substantially in form attached hereto as Exhibit O- 1, shall have been delivered to the Class A Equity Investors, and provide that all Transaction Expenses incurred and invoiced through the Initial Capital Contribution Date have been paid or otherwise shall be paid on the Initial Capital Contribution Date in accordance with (and subject to the limitations in) Section 10.2.
(v)No Change in Tax Law. No Change in Tax Law or Proposed Change in Tax Law shall have occurred since the ECCA Effective Date that has not been reflected in the Adjusted Base Case Model for the Initial Class A Capital Contribution in a manner reasonably satisfactory to the Class A Equity Investors.
(w)Permits. Copies of all Applicable Permits and Departure Approvals for the Project that were obtained after the ECCA Effective Date, but on or prior to the Initial Capital Contribution Date, shall have been Made Available to the Class A Equity Investors. Each such Applicable Permit and Departure Approval shall have been validly issued or made and shall be in full force and effect.
(x)Non-Foreign Status. The Class A Equity Investors shall have received a duly executed IRS W-9 Form from the Class B Equity Investor.
(y)Officer’s Certificate. The Class A Equity Investors shall have received an omnibus certificate of an authorized officer of the Class B Equity Investor (i) certifying as to the matters set forth in Section 6.1(e) above and (ii) attaching a good standing certificate of the Class B Equity Investor and the Project Entities, each dated as of a recent date, from the applicable Secretary of State.
(z)No Condemnation. No condemnation shall be pending or threatened in writing with respect to the Project that has or could reasonably be expected to have a Material Adverse Effect, unless such event has been remedied or is in the process of being remedied in accordance with a plan approved by the Independent Engineer and is reasonably expected to be remedied by no later than the Outside Date.
(aa)No Casualty. No unrepaired casualty shall exist with respect to the Project that has or could reasonably be expected to have a Material Adverse Effect, unless such event has been remedied or is in the process of being remedied in accordance with a plan approved by the Independent Engineer and is reasonably expected to be remedied by no later than the Outside Date.


(ab)No Action or Proceeding. (i) Except as set forth on Schedule 3.4(in each case, as updated in accordance with Section 10.8), no action or proceeding shall have been threatened or instituted in writing against (x) any Sponsor Guarantor or any Governmental Authority with respect to the Project, any of the Assets of any Project Entity or any of the Permits or Departure Approvals set forth on Schedule 3.10 or (y) the Class B Equity Investor, Seller, any Project Entity, Shareco, in each case, that has or could reasonably be expected to have a Material Adverse Effect and (ii) no actions, suits, proceedings, investigations or similar actions shall have been threatened or instituted in writing against the Class B Equity Investor, any Project Entity, Shareco or any Sponsor Guarantor which seek to impair, restrain, prohibit or invalidate any of the Transaction Documents.
(ac)No Adverse Guarantor Event. No Adverse Guarantor Event shall have occurred since the ECCA Effective Date, unless an Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support reasonably acceptable to the Class A Equity Investors has been provided by the Class B Equity Investor to replace the Sponsor Guaranty for which the Adverse Guarantor Event applies; provided that (i) the obligations of the Person (or Persons) providing any such Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support shall be several and not joint with the other Sponsor Guarantors (provided that the obligations of each CI II Guarantor shall be joint and several with the other CI II Guarantors and the obligations of each CI III Guarantor shall be joint and several with the other CI III Guarantors) and (ii) any such Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support shall be in an amount not greater than the Sponsor Guaranty for which the Adverse Guarantor Event applies.
(ad)Title Policy. Concurrently with the Initial Capital Contribution Date, the Title Company shall have issued (or the Title Company shall have committed in writing to issue such Title Policy endorsement subject only to payment of the applicable premium, which such premium shall be paid on the Initial Capital Contribution Date pursuant to the Initial Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.1(u)) an ALTA 15.1-06 Non-Imputation-Additional Insured Endorsement to the Title Policy listing the Company and the Class A Equity Investors as additional insureds, an ALTA 40 Tax Credit-Owner’s Policy endorsement, and a date-down endorsement of the Title Policy.
(ae)Loan Documents. No “Event of Default” or material “Default” (in each case, as defined in the Construction Loan Agreement) has occurred and is continuing, except to the extent such material “Default” or “Event of Default” (in each case, as defined in the Construction Loan Agreement) will be cured by the funding of the Initial Class A Capital Contribution and the Initial Class B Capital Contribution.
(af)Initial Class B Capital Contribution. The Class A Equity Investors shall have received evidence that the Class B Equity Investor has paid to the Company the Initial Class B Capital Contribution in immediately available funds (or such Capital Contribution will be made on the Initial Capital Contribution Date pursuant to the Initial Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.1(u)).
(ag)Membership Interest Certificates. Each Class A Member shall have received a certificate of its Membership Interests in accordance with Section 2.9 of the LLC Agreement.
(ah)Incremental Offtake Agreements. (i) If any Incremental Offtake Agreements have been executed by the Project Company, the Class A Equity Investors shall have received copies of the Incremental Offtake Agreements, in form and substance satisfactory to the Class A Equity Investors and duly executed and delivered by the Project Company and the counterparty thereto and (ii) the Base Case Model delivered pursuant to Section 6.1(i) and the Independent Appraisal delivered pursuant to Section 6.1(h) shall each reflect (1) to the extent that any Incremental Offtake Agreements have been executed by the Project Company, the terms of the Incremental Offtake Agreements delivered pursuant to clause (i) and (2) to the extent that all or any portion of the Project’s 806 MW nameplate capacity is not the subject of a PPA or Incremental Offtake Agreement, merchant energy and REC sales for the uncontracted portion of Project nameplate capacity based on the ABB/Ventyx Fall 2022 report for NE-SEMA (or any more recently issued report by ABB/Ventyx for NE-SEMA).


(ai)Hurricane Preparedness Plan. The Class A Equity Investors shall have received a hurricane readiness procedure prepared by the Class B Equity Investor for the Project, in form and substance reasonably acceptable to the Class A Equity Investors and the Independent Engineer (the “Hurricane Preparedness Plan”).
(aj)Material Adverse Effect. Since the ECCA Execution Date, no Material Adverse Effect has occurred and is continuing.
6.2Interim Capital Contribution Date Conditions Precedent. The obligations of the Class A Equity Investors to make an Interim Class A Capital Contribution shall be subject to the satisfaction of each of the conditions set forth below, any of which may be waived in writing, in whole or in part, by the Class A Equity Investors:
(a)Outside Date. The Interim Capital Contribution Date shall not be later than the date that is one month prior to the Outside Date.
(b)Notice of Interim Capital Contribution Date. The Class A Equity Investors shall have received not less than three Business Days’ prior written notice from the Class B Equity Investor of such Interim Capital Contribution Date, which notice shall include (i) the anticipated amount of the Interim Class A Capital Contribution (ii) a certificate of the Independent Engineer referred to in Section 6.2(k) below.
(c)Representations and Warranties. Each of the representations and warranties of the Class B Equity Investor contained in Article III of this Agreement shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the Interim Capital Contribution Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of such date).
(d)Material Project Agreements. Copies of all Material Project Agreements that have been executed and delivered after the immediately preceding Capital Contribution Date but on or prior to such Interim Capital Contribution Date shall have been Made Available to the Class A Equity Investors. Each of the Material Project Agreements with respect to the Project shall be in full force and effect, and there shall exist no default that could reasonably be expected to result in termination of such Material Project Agreement. All material amendments to the Material Project Agreements that have been entered into since the immediately preceding Capital Contribution Date (other than amendments and change orders under the Construction Contracts for which the execution thereof would not constitute a “Fundamental Decision” or a “Major Decision” (in each case, as defined in the LLC Agreement)) shall be reasonably acceptable to the Class A Equity Investors.
(e)Flow of Funds; Transaction Expenses. The flow of funds memorandum with respect to the Interim Capital Contribution Date (the “Interim Capital Contribution Date Flow of Funds Memorandum”), substantially in the form attached hereto as Exhibit O-2, shall have been delivered to the Class A Equity Investors, and provide that all Transaction Expenses incurred and invoiced through the Interim Capital Contribution Date have been paid or shall be paid on the Interim Capital Contribution Date in accordance with (and subject to the limitations in) Section 10.2.
(f)Officer’s Certificate. The Class A Equity Investors shall have received an omnibus certificate of an authorized officer of the Class B Equity Investor certifying as to the matters set forth in Section 6.2(c) above.
(g)No Condemnation. No condemnation shall be pending or threatened in writing with respect to the Project that has or could reasonably be expected to have a Material Adverse Effect, unless such event has been remedied or is in the process of being remedied in accordance with a plan approved by the Independent Engineer and is reasonably expected to be remedied by no later than the Outside Date.


(h)No Casualty. No unrepaired casualty shall exist with respect to the Project that has or could reasonably be expected to have a Material Adverse Effect, unless such event has been remedied or is in the process of being remedied in accordance with a plan approved by the Independent Engineer and is reasonably expected to be remedied by no later than the Outside Date.
(i)No Action or Proceeding. (i) Except as set forth on Schedule 3.4 (in each case, as updated in accordance with Section 10.8), no action or proceeding shall have been threatened or instituted in writing against (x) any Sponsor Guarantor or any Governmental Authority with respect to the Project, any of the Assets of any Project Entity or any of the Permits or Departure Approvals set forth on Schedule 3.10 or (y) the Class B Equity Investor, Seller, any Project Entity, Shareco, in each case, that has or could reasonably be expected to have a Material Adverse Effect and (ii) no actions, suits, proceedings, investigations or similar actions shall have been threatened or instituted in writing against the Class B Equity Investor, any Project Entity, Shareco or any Sponsor Guarantor which seek to impair, restrain, prohibit or invalidate any of the Transaction Documents.
(j)No Adverse Guarantor Event. No Adverse Guarantor Event shall have occurred since the immediately prior Capital Contribution Date, unless an Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support reasonably acceptable to the Class A Equity Investors has been provided by the Class B Equity Investor to replace the Sponsor Guaranty for which the Adverse Guarantor Event applies; provided that (i) the obligations of the Person (or Persons) providing any such Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support shall be several and not joint with the other Sponsor Guarantors (provided that the obligations of each CI II Guarantor shall be joint and several with the other CI II Guarantors and the obligations of each CI III Guarantor shall be joint and several with the other CI III Guarantors) and (ii) any such Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support shall be in an amount not greater than the Sponsor Guaranty for which the Adverse Guarantor Event applies.
(k)Independent Engineer’s Interim Capital Contribution Date Certificate. The Class A Equity Investors have received a certificate from the Independent Engineer, substantially in the form of Exhibit D-2, which such certificate shall (1) include actual Mechanical Completion dates for each Turbine that has achieved Mechanical Completion on or before such Interim Capital Contribution Date and (2) either (x) confirm the reasonableness of the Mechanical Completion Schedule delivered on the Initial Capital Contribution Date or the immediately preceding Interim Capital Contribution Date, as applicable, or (y) attach an updated Mechanical Completion Schedule.
(l)Transaction Documents. Each of the Class B Equity Investor, the Seller, the Sponsor Guarantors and the Project Entities shall have performed in all material respects its obligations under the Transaction Documents to which it is a party to be performed on or prior to the Interim Capital Contribution Date.
(m)No Other Interim Capital Contribution Dates in such Calendar Month. There shall not have been an Interim Capital Contribution Date on any other Business Day during such calendar month.
(n)Loan Documents. No “Event of Default” (as defined in the Construction Loan Agreement) has occurred and is continuing, except to the extent such “Event of Default” (as defined in the Construction Loan Agreement) will be cured by the funding of the applicable Interim Class A Capital Contribution and Interim Class B Capital Contribution.
(o)Interim Class B Capital Contribution. The Class A Equity Investors shall have received evidence that the Class B Equity Investor has paid to the Company the Interim Class B Capital Contribution in immediately available funds (or such Capital Contribution will be made on such Interim Capital Contribution Date pursuant to the Interim Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.2(e)).


(p)Material Adverse Effect. Since the Initial Funding Date or, if applicable, the most recent Interim Funding Date, no Material Adverse Effect has occurred and is continuing.
6.3Final Capital Contribution Date Conditions Precedent. The obligations of the Class A Equity Investors to make the Final Class A Capital Contribution shall be subject to the satisfaction of each of the conditions set forth below, any of which may be waived, in whole or in part, by the Class A Equity Investors:
(a)Outside Date. The Final Capital Contribution Date shall not be later than the Outside Date.
(b)Notice of Final Capital Contribution Date. The Class A Equity Investors shall have received not less than five Business Days’ prior written notice from the Class B Equity Investor of the Final Capital Contribution Date.
(c)Substantial Completion; Commercial Operation Date; Placed in Service.
(i)Substantial Completion of the Project shall have occurred, other than delivery of the “Taking Over Certificates” with respect to any “WTGs” (as such terms are defined in the TSA) which constitute Additional Turbines.
(ii)The “Commercial Operation Date” (as defined in each PPA) shall have occurred under each PPA.
(iii)At least 75% of the Turbines for each of “Facility 1” and “Facility 2” (as such terms are defined in the PPAs) shall have been Placed in Service.
(d)Transaction Documents. Each of the Class B Equity Investor, the Seller, the Sponsor Guarantors and the Project Entities shall have performed in all material respects its obligations under the Transaction Documents to which it is a party to be performed on or prior to the Final Capital Contribution Date.
(e)Representations and Warranties. Each of the representations and warranties of the Class B Equity Investor contained in Article III of this Agreement shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the Final Capital Contribution Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of such date).
(f)Material Project Agreements. Copies of all Material Project Agreements that have been executed and delivered after the immediately preceding Capital Contribution Date but on or prior to the Final Capital Contribution Date shall have been Made Available to the Class A Equity Investors and shall be reasonably satisfactory to the Class A Equity Investors. Each of the Material Project Agreements with respect to the Project is in full force and effect, and there exists no default that could reasonably be expected to result in termination of such Material Project Agreement. All material amendments to the Material Project Agreements that have been entered into since the immediately preceding Capital Contribution Date (other than amendments and change orders under the Construction Contracts for which the execution thereof would not constitute a “Fundamental Decision” or a “Major Decision” (in each case, as defined in the LLC Agreement)) shall be reasonably acceptable to the Class A Equity Investors.
(g)Cost Segregation Report. The Class A Equity Investors shall have received a copy of the Cost Segregation Report with respect to the Project, which shall have been incorporated into the Base Case Model, with, to the extent not addressed to the Class A Equity Investors, a reliance letter (or its equivalent) with respect thereto for the benefit of the Class A Equity Investors, each in form and substance reasonably acceptable to the Class A Equity Investors.


(h)Independent Appraisal. The Class A Equity Investors shall have received a copy of the Independent Appraisal with respect to the Project, which shall have been incorporated into the Base Case Model, with, to the extent not addressed to the Class A Equity Investors, a reliance letter (or its equivalent) with respect thereto for the benefit of the Class A Equity Investors, each in form and substance reasonably acceptable to the Class A Equity Investors; provided that any changes to the draft Independent Appraisal delivered pursuant to Section 6.1(h) shall be limited in scope to reflect (i) actual costs incurred for construction of the Project, (ii) solely to the extent that a Specified Tax Law Change occurs, updates to the discounted cash flow (DCF) value of the Project solely resulting from the Specified Tax Law Change (with all of the other variables related to the DCF held constant) and (iii) the estimated fair market value of the Class A Membership Interests on each Purchase Option Closing Date (assuming that the Flip Date has occurred) for purposes of including such amount in an updated Schedule 10.3 to the LLC Agreement (with all other variables in the draft Independent Appraisal delivered pursuant to Section 6.1(h) held constant).
(i)Base Case Model. The Base Case Model shall have been updated pursuant to Section 2.2(a), evidencing satisfaction of the Pricing Parameters to the reasonable satisfaction of Class A Equity Investors and delivered to the Class A Equity Investors together with an update to Schedule 13.2(e) of the LLC Agreement reasonably satisfactory to the Class A Equity Investors.
(j)Transmission Consultant’s Report. The Class A Equity Investors shall have received a copy of a bring-down of the Transmission Consultant’s Report delivered pursuant to Section 5.1(n) or Section 6.1(l), as applicable (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), in form and substance reasonably satisfactory to the Class A Equity Investors (including with respect to updates, if any, with respect to any Incremental offtake Agreements).
(k)Independent Engineer’s Report; Independent Engineer’s Final Capital Contribution Date Certificate. The Class A Equity Investors shall have received (i) a copy of a bring-down of the construction supplement to the Independent Engineer’s Report delivered pursuant to Section 6.1(m) (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), which shall include the Independent Engineer’s review of the Type Certificate and, subject to Section 6.1(c)(i) of the LLC Agreement, verification of each Major Component for each Turbine (other than the Additional Turbines (if any)), and shall be in form and substance reasonably satisfactory to the Class A Equity Investors and (ii) a certificate from the Independent Engineer, substantially in the form of Exhibit D-3, which such certificate shall (1) attach a schedule identifying each Turbine that has been Placed in Service and has achieved “Taking Over” (as defined in the TSA) as of the Final Capital Contribution Date and (2) confirm that each Additional Turbine (if any) is reasonably expected to be Placed in Service and achieve “Taking Over” (as defined in the TSA) prior to the Outside Date.
(l)Wind Consultant’s Report. The Class A Equity Investors shall have received a copy of a bring-down of the Wind Consultant’s Report delivered pursuant to Section 5.1(p) or Section 6.1(n), as applicable (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), in form and substance reasonably satisfactory to the Class A Equity Investors; provided that such bring-down report shall be limited in scope to reflect the updated electrical loss assumption based on an as-built electrical study (with all other variables in the Wind Consultant’s Report delivered pursuant to Section 5.1(p) or Section 6.1(n), as applicable, held constant) so long as none of the following have occurred, as confirmed in writing to the Class A Equity Investors by the Wind Consultant: (i) a change in the location of any Turbine in excess of 500 feet or any other material change to the Project layout, (ii) changes to the power curve if the Turbine Supplier has restated or adjusted the power curve for the Turbines (specifically for the Turbines in the Project) or (iii) known changes in the location of any Turbine in a neighboring wind farm accounted for in the Wind Consultant’s Report delivered pursuant to Section 5.1(p) or Section 6.1(n), as applicable; provided further that if any of the events in sub-clauses (i) through (iii) in the immediately preceding proviso have occurred, then such bring-down report shall be limited in scope to reflect (x) the updated electrical loss assumption based on an as-built electrical study and (y) any of the applicable matters in sub-clauses (i) through (iii) in the immediately preceding proviso that have occurred (with all other variables in the Wind Consultant’s Report delivered pursuant to Section 5.1(p) or Section 6.1(n), as applicable, held constant).


(m)Phase I Environmental Site Assessment Report. (i) If less than one year has elapsed since the date of the site visit, records review, lien search, environmental professional’s declaration, and owner/operator interviews performed for the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q) or, if applicable, the bring-down or new Phase I environmental site assessment delivered pursuant to Section 6.1(o) and either (x) more than 180 days have elapsed since the date of the site visit, records review, lien search, environmental professional’s declaration, and owner/operator interviews performed for the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q) or, if applicable, the bring-down or new Phase I environmental site assessment delivered pursuant to Section 6.1(o), or (y) to the Knowledge of the Class B Equity Investor, there have been changes to the Project that would materially impact the conclusions set forth in the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q), the Class A Equity Investors shall have received a copy of a bring-down of the applicable sections of the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q) or, if applicable, the bringdown or new Phase I environmental site assessment delivered pursuant to Section 6.1(o), or (ii) if one year or more has elapsed since the date of the site visit, records review, lien search, environmental professional’s declaration, and owner/operator interviews performed for the Phase I Environmental Site Assessment Report delivered pursuant to Section 5.1(q) or, if applicable, the bring-down or new Phase I environmental site assessment delivered pursuant to Section 6.1(o), the Class A Equity Investors shall have received a new Phase I environmental site assessment, in each case, including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors and in form and substance reasonably satisfactory to the Class A Equity Investors.
(n)Insurance Consultant’s Report. The Class A Equity Investors shall have received a copy of a bring-down of the report of the Insurance Consultant delivered pursuant to Section 6.1(p) (including reasonably acceptable reliance provisions or a separate reliance letter addressed to the Class A Equity Investors), in form and substance reasonably satisfactory to the Class A Equity Investors (including with respect to updates, if any, with respect to any Incremental offtake Agreements).
(o)Insurance Certificates. The Class A Equity Investors shall have received copies of insurance certificates with respect to the insurance necessary for the Project, as prescribed by the Insurance Consultant and set forth in Schedule 3.11 of this Agreement.
(p)Estoppels. The Class A Equity Investors shall have received estoppels from (i) the Offtakers, the Asset Manager, the Management Services Provider, the Construction Manager, the Operator and the Turbine Supplier, in substantially the forms attached hereto as Exhibits E-1, E-13, E-14, E-15, E-16, and E-17, as applicable, and (ii) the counterparties to the Construction Contracts who have substantially completed their work under the applicable Construction Contract after the Initial Capital Contribution Date but on or before the Final Capital Contribution Date (other than with respect to the HDD Agreement and the Material Project Credit Support Documents), in substantially the forms attached hereto as Exhibits E-1, E-2, E-3, E-4, E-5, E-6, E-7, E-8, E-9, E-10, E-11, and E-12, as applicable; provided that to the extent that an estoppel from a counterparty to a Construction Contract is not available despite the use of commercially reasonable efforts, then this Section 6.3(p) shall be deemed satisfied with respect to such estoppel(s) and Section 8.1(a)(ii) shall apply with respect to such estoppel(s).
(q)Legal Opinions. The Class A Equity Investors shall have received copies of the following, each in form and substance reasonably satisfactory to the Class A Equity Investors: (i) if reasonably requested due to a material change in Law or the Project, a bring down of the legal opinion delivered by Kirkland & Ellis LLP pursuant to Sections 5.1(j)(i) and 6.1(s)(ii); (ii) a bring-down of the legal opinion delivered by Foley Hoag LLP pursuant to Section 6.1(s)(vi), substantially in the form attached as Exhibit N-1; and (iii) a bring-down of the legal opinion delivered by Sidley Austin LLP pursuant to Section 6.1(s)(vii), substantially in the form attached as Exhibit N-2.


(r)Tax Opinion. The Class A Equity Investors shall have received a bringdown of the tax opinion delivered by Milbank LLP in connection with the Initial Capital Contribution Date pursuant to Section 6.1(t) in form and substance satisfactory to the Class A Equity Investors, which opinion shall be limited to addressing any Change in Tax Law or other change in or update to material facts or the circumstances relevant to the tax opinion delivered by Milbank LLP in connection with the Initial Capital Contribution Date pursuant to Section 6.1(t).
(s)Flow of Funds; Transaction Expenses. The flow of funds memorandum with respect to the Final Capital Contribution Date (the “Final Capital Contribution Date Flow of Funds Memorandum”), substantially in the form attached hereto as Exhibit O-3, shall have been delivered to the Class A Equity Investors, and provide that all Transaction Expenses incurred and invoiced through the Final Capital Contribution Date have been paid or otherwise shall be paid on the Final Capital Contribution Date in accordance with (and subject to the limitations in) Section 10.2.
(t)No Change in Tax Law. No Change in Tax Law or Proposed Change in Tax Law shall have occurred since the Initial Capital Contribution Date that has not been reflected in the Adjusted Base Case Model in a manner reasonably satisfactory to the Class A Equity Investors.
(u)Permits. Copies of all Applicable Permits and Departure Approvals for the Project which were obtained after the Initial Capital Contribution Date, but on or prior to the Final Capital Contribution Date, shall have been Made Available to the Class A Equity Investors. Each such Applicable Permit and Departure Approval shall have been validly issued or made and shall be in full force and effect, except for those not yet required to be obtained as of the Final Capital Contribution Date.
(v)MBR Authority. The Project Company shall have received an order from FERC granting it MBR Authority (which may be in the form of a letter order accepting the Project Company’s application for MBR Authority for filing), and such order shall be final and in full force and effect.
(w)EWG Status. The Project Company shall have self-certified with FERC as an EWG, and such self-certification shall be in full force and effect.
(x)Officer’s Certificate. The Class A Equity Investors shall have received an omnibus certificate of an authorized officer of the Class B Equity Investor certifying as to the matters set forth in Section 6.3(e) above.
(y)No Condemnation. No condemnation shall be pending or threatened in writing with respect to the Project, unless (i) such event could not reasonably be expected to have a Material Adverse Effect or (ii) (A) such event has been remedied or is in the process of being remedied in accordance with a plan and budget approved by the Independent Engineer and is reasonably expected to be remedied by no later than the date that is 60 days prior to the Outside Date and (B) the Project Company has funded a reserve account in an amount greater than or equal to 125% of the aggregate amount that is estimated, as of the Final Capital Contribution Date, to be required to be paid after the Final Capital Contribution Date in connection with remedying such condemnation event.
(z)No Casualty. No unrepaired casualty shall exist with respect to the Project, unless (i) such event could not reasonably be expected to have a Material Adverse Effect or (ii) (A) such event has been remedied or is in the process of being remedied in accordance with a plan and budget approved by the Independent Engineer and is reasonably expected to be remedied by no later than the date that is 60 days prior to the Outside Date and (B) the Project Company has funded a reserve account in an amount greater than or equal to 125% of the aggregate amount that is estimated, as of the Final Capital Contribution Date, to be required to be paid after the Final Capital Contribution Date in connection with remedying such casualty event.


(aa)No Action or Proceeding. (i) Except as set forth on Schedule 3.4(in each case, as updated in accordance with Section 10.8), no action or proceeding shall have been threatened or instituted in writing against (x) any Sponsor Guarantor or any Governmental Authority with respect to the Project, any of the Assets of any Project Entity or any of the Permits or Departure Approvals set forth on Schedule 3.10 or (y) the Class B Equity Investor, Seller, any Project Entity, Shareco, in each case, that has or could reasonably be expected to have a Material Adverse Effect and (ii) no actions, suits, proceedings, investigations or similar actions shall have been threatened or instituted in writing against the Class B Equity Investor, any Project Entity, Shareco or any Sponsor Guarantor which seek to impair, restrain, prohibit or invalidate any of the Transaction Documents.
(ab)No Adverse Guarantor Event. No Adverse Guarantor Event shall have occurred since the immediately prior Capital Contribution Date, unless an Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support reasonably acceptable to the Class A Equity Investors has been provided by the Class B Equity Investor to replace the Sponsor Guaranty for which the Adverse Guarantor Event applies; provided that (i) the obligations of the Person (or Persons) providing any such Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support shall be several and not joint with the other Sponsor Guarantors (provided that the obligations of each CI II Guarantor shall be joint and several with the other CI II Guarantors and the obligations of each CI III Guarantor shall be joint and several with the other CI III Guarantors) and (ii) any such Acceptable Guaranty, Acceptable Letter of Credit or other alternative credit support shall be in an amount not greater than the Sponsor Guaranty for which the Adverse Guarantor Event applies.
(ac)Financial Statements. The Class A Equity Investors shall have received (i) the most recently available unaudited interim monthly balance sheets of each Project Entity and Shareco, (ii) the most recently available quarterly unaudited financial statements and annual audited financial statements of each Project Entity and (iii) the most recent annual audited financial statements and quarterly unaudited financial statements of the Sponsor Guarantors prepared in accordance with the Accounting Standard, together with a certificate from an authorized officer of the applicable Sponsor Guarantor that such financial statements present fairly in all material respects the financial position and results from operations of such Sponsor Guarantor and its consolidated subsidiaries as of the applicable date thereof and for the periods then ended, subject to, in the case of such unaudited interim financial statements, normal year-end audit adjustments and the absence of footnotes; provided that, if (X) any such entity files an annual report on Form 10-K (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable annual audited financial statements shall be deemed to have been received by the Class A Equity Investors for purposes of this clause (iii) and (Y) any such entity files a quarterly report on Form 10-Q (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable quarterly unaudited financial statements shall be deemed to have been received by the Class A Equity Investors for purposes of this clause (iii).
(ad)Title Policy. The Class A Equity Investors shall have received a date-down endorsement of the Title Policy (or the Title Company shall have committed in writing to issue the date-down endorsement subject only to payment of the applicable premium, which such premium shall be paid on the Final Capital Contribution Date pursuant to the Final Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.3(s)).
(ae)Construction Loan Payoff Letter; Release of Liens. The Class A Equity Investors shall have received (i) a payoff letter, substantially in the form of Exhibit K (the “Construction Loan Payoff Letter”), confirming that all Encumbrances granted to or held by any “Secured Party” (as defined in the Construction Loan Agreement) in the Project, the Project Entities, Shareco and all of their Assets shall be released on the Final Capital Contribution Date, and each of the conditions to the “Effective Time” (as defined in the Construction Loan Payoff Letter) shall have been satisfied or shall be satisfied concurrently with the Final Class A Capital Contribution in accordance with the Final Capital Contribution Date Flow of Funds Memorandum, and (ii) copies of the draft Uniform Commercial Code termination statements, as described in the Construction Loan Payoff Letter, which shall be filed by counsel to the Class B Equity Investor on the Final Capital Contribution Date.


(af)Lien Waivers. The Class B Equity Investor has Made Available copies of lien waivers in form and substance reasonably satisfactory to the Class A Equity Investors from the counterparties to the Construction Contracts that the Project Company has received in accordance with the applicable Construction Contract, in connection with all amounts previously paid or payable on the Final Capital Contribution Date by the Project Company, which lien waivers may be conditional in the case of any amounts then payable (but not yet due) on the Final Capital Contribution Date. For the avoidance of doubt, if a lien waiver is delivered substantially in the form attached to the applicable Construction Contract, it shall be deemed reasonably satisfactory to the Class A Equity Investors.
(ag)Completion Reserve Amount. Concurrently with the transactions contemplated on the Final Capital Contribution Date, the Completion Reserve Account shall have been funded such that the balance on deposit therein (together with any Acceptable Guaranty or Acceptable Letter of Credit standing exclusively to the credit thereof) is equal to the Completion Reserve Amount.
(ah)Type Certificate. The Class A Equity Investors shall have received, with respect to each Turbine (including each Additional Turbine), a copy of a “type certificate” from an accredited certification agent reasonably acceptable to the Class A Equity Investors (the “Type Certificate”).
(ai)Final Class B Capital Contribution. The Class A Equity Investors shall have received evidence that the Class B Equity Investor has paid to the Company the Final Class B Capital Contribution in immediately available funds (or such Capital Contribution will be made on such Final Capital Contribution Date pursuant to the Final Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.3(s)). For the avoidance of doubt, the Final Class B Capital Contribution may include any deemed fundings resulting from the conversion of the “Loans” (as defined under the Construction Loan Agreement) into the “Term Loans” (as defined in each of the Term Loan Agreements).
(aj)Incremental Offtake Agreements. (i) If any Incremental Offtake Agreements have been executed by the Project Company since the Initial Capital Contribution Date or if any Incremental Offtake Agreements that were executed prior to the Initial Capital Contribution Date have been amended, modified, supplemented or terminated, the Class A Equity Investors shall have received copies of the Incremental Offtake Agreements duly executed and delivered by the Project Company and the counterparty thereto or evidence of such amendment, modification, supplement or termination, as applicable, in each case in form and substance satisfactory to the Class A Equity Investors and (ii) the Base Case Model delivered pursuant to Section 6.3(i) shall reflect (1) the terms of the Incremental Offtake Agreements and amendments, supplements, modifications or terminations (in each case, if any) delivered pursuant to clause (i) and (2) to the extent that all or any portion of the Project’s 806 MW nameplate capacity is not the subject of a PPA or Incremental Offtake Agreement, merchant energy and REC sales for the uncontracted portion of Project nameplate capacity based on the ABB/Ventyx Fall 2022 report for NE-SEMA (or any more recently issued report by ABB/Ventyx for NE-SEMA).
(ak)Material Adverse Effect. Since the most recent Interim Funding Date, no Material Adverse Effect has occurred and is continuing.
(al)CI II and CI III Specified Casualty Event Contribution LCs. The Class A Members shall have received the CI II Specified Casualty Event Contribution LCs and the CI III Specified Casualty Event Contribution LCs, which shall be substantially in the form attached hereto as Exhibit Q-2b.
6.4ALTA/NSPS Surveys. On or before 120 days after the Final Capital Contribution Date, the Class B Equity Investor shall deliver to the Class A Equity Investors the final as-built ALTA/NSPS survey of the Onshore Project Site (other than the portion of the Onshore Project Site leased by the Project Company pursuant to the New Bedford Terminal Lease) showing the asbuilt locations of the Project’s improvements on such portion of the Onshore Project Site in form and substance reasonably satisfactory to the Class A Equity Investors (the “Final As-Built ALTA Survey”).


6.5Mechanical Completion Notice. Each month during the period commencing on the Initial Capital Contribution Date and ending on the earlier of (a) the date that the last such certificate is delivered with respect to the last Turbine included in the Project to achieve Mechanical Completion and (b) the Outside Date, the Class B Equity Investor shall deliver to the Class A Equity Investors a certificate substantially in the form of Exhibit L, signed by an authorized officer of the Class B Equity Investor, and countersigned by the Independent Engineer, identifying each Turbine (if any) that (x) actually achieved Mechanical Completion in the prior month (together with a reconciliation comparison to the Mechanical Completion Schedule delivered with respect to such prior month) or (y) is reasonably expected to achieve Mechanical Completion in the following month (a “Mechanical Completion Notice”).
6.6Placed in Service Notice. During the period commencing on the Initial Capital Contribution Date and ending on the earlier of (i) the date that the last Turbine included in the Project is Placed in Service and (ii) the Outside Date, the Class B Equity Investor agrees to deliver, or caused to be delivered to the Class A Equity Investors, the following notices at the times indicated below:
(a)Monthly, within three Business Days before the end of the month, the Class B Equity Investor shall provide the Class A Equity Investors with written notice of any Turbine included in the Project that is anticipated to be Placed in Service in the following month.
(b)During the first, second and third quarters of each Fiscal Year, the Class B Equity Investor shall promptly, but in no event later than three Business Days prior to the end of each such calendar quarter, provide the Class A Equity Investors with written notice of any Turbine included in the Project that has been Placed in Service.
(c)During each calendar month within the fourth quarter of each Fiscal Year, the Class B Equity Investor shall promptly, but in no event later than three Business Days prior to the end of each such calendar month, provide the Class A Equity Investors with written notice of any Turbine included in the Project that has been Placed in Service.
(d)Promptly following date on which the first Turbine (or Turbines) has achieved Hot Commissioning and, in any event, no later than December 1, 2023, the Class B Equity Investor shall seek written confirmation (the “Hot Commissioning Tax Confirmation”) from the Accounting Firm that the date of Hot Commissioning for such Turbine (or Turbines) is the correct placed in service date for U.S. federal income tax purposes for such Turbine (or Turbines). If the Class B Equity Investor has not provided the Hot Commissioning Tax Confirmation to the Class A Equity Investors on or prior to December 1, 2023, then the Class B Equity Investor shall update the Base Case Model to reflect the dates that Turbines have been Placed in Service rather than the dates that Turbines have achieved Hot Commissioning. The Class A Equity Investors acknowledge and agree that the written notices described in clauses (b) and (c) of this Section 6.6 may be included in the Construction Reports delivered to the Class A Equity Investors pursuant to Section 9.5(c)(i) of the LLC Agreement.
ARTICLE VII
CONDITIONS TO OBLIGATIONS OF THE CLASS B EQUITY INVESTOR
7.1Initial Capital Contribution Date Conditions Precedent. The obligations of the Class B Equity Investor to consummate the transactions on the Initial Capital Contribution Date shall be subject to the satisfaction or waiver by the Class B Equity Investor of each of the following conditions:
(a)Transaction Documents. The LLC Agreement and each of the Sponsor Guaranties have been executed by the Class A Equity Investors and delivered to the Class B Equity Investor.


(b)Representations and Warranties. Each of the representations and warranties of the Class A Equity Investors in this Agreement and of each of the Class A Equity Investors and their Affiliates in any other Transaction Document shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the Initial Capital Contribution Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect orany similar qualification or exception, which shall be true and correct in all respects) as of such date).
(c)No Governmental Action. No action or proceeding has been instituted in writing by any Governmental Authority against a Class A Equity Investor which seeks to impair, restrain, prohibit or invalidate the transactions contemplated by any of the Transaction Documents.
(d)Base Case Model. The Base Case Model shall have been updated pursuant to Section 2.2(a) to the reasonable satisfaction of the Class B Equity Investor.
(e)Initial Class A Capital Contribution. The Class B Equity Investor shall have received evidence that each of the Class A Equity Investors have paid to the Company the Initial Class A Capital Contribution in immediately available funds (or such Capital Contribution will be made on the Initial Capital Contribution Date pursuant to the Initial Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.1(u)).
7.2Interim Capital Contribution Date Conditions Precedent. The obligations of the Class B Equity Investor to consummate the transactions on each Interim Capital Contribution Date shall be subject to the satisfaction of each of the conditions set forth below, any of which may be waived, in whole or in part, by the Class B Equity Investor:
(a)Representations and Warranties. Each of the representations and warranties of the Class A Equity Investors in this Agreement and of each of the Class A Equity Investors and their Affiliates in any other Transaction Document shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the Interim Capital Contribution Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of such date).
(b)Interim Class A Capital Contribution. The Class B Equity Investor shall have received evidence that each of the Class A Equity Investors have paid to the Company the Interim Class A Capital Contribution in immediately available funds (or such Capital Contribution will be made on such Interim Capital Contribution Date pursuant to the Interim Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.2(e)).
7.3Final Capital Contribution Date Conditions Precedent. The obligations of the Class B Equity Investor to consummate the transactions on the Final Capital Contribution Date shall be subject to the satisfaction of each of the conditions set forth below, any of which may be waived, in whole or in part, by the Class B Equity Investor:
(a)Representations and Warranties. Each of the representations and warranties of the Class A Equity Investors in this Agreement and of each of the Class A Equity Investors and their Affiliates in any other Transaction Document shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of the Final Capital Contribution Date (except to the extent that any such representation or warranty is to be made or deemed made only as of another date, which shall be true and correct in all material respects (except for such representations and warranties that are qualified by materiality, Material Adverse Effect or any similar qualification or exception, which shall be true and correct in all respects) as of such date).


(b)No Governmental Action. No action or proceeding has been instituted in writing by any Governmental Authority against a Class A Equity Investor which seeks to impair, restrain, prohibit or invalidate the transactions contemplated by any of the Transaction Documents.
(c)Base Case Model. The Base Case Model shall have been updated pursuant to Section 2.2(a) to the reasonable satisfaction of the Class B Equity Investor.
(d)Final Class A Capital Contribution. The Class B Equity Investor shall have received evidence that each of the Class A Equity Investors have paid to the Company the Final Class A Capital Contribution in immediately available funds (or such Capital Contribution will be made on the Final Capital Contribution Date pursuant to the Final Capital Contribution Date Flow of Funds Memorandum provided pursuant to Section 6.3(s)).
ARTICLE VIII
INDEMNIFICATION
8.1Indemnification by the Class B Equity Investor.
(a)Subject to the terms and conditions of this Article VIII, without limiting any rights under the Sponsor Guaranties or any Qualified Replacement Sponsor Guaranty, the Class B Equity Investor shall indemnify, defend, reimburse and hold harmless each Class A Equity Investor and their respective parent or subsidiary companies, partners and other Affiliates, and their respective officers, directors, members, employees, attorneys, contractors and agents (collectively, the “Class A Equity Investor Indemnitees” and, individually, a “Class A Equity Investor Indemnitee”), from and against any and all Claims of any nature whatsoever (collectively, “Damages”), asserted against, resulting to, imposed upon, or incurred by a Class A Equity Investor Indemnitee, directly or indirectly, by reason of, arising out of or resulting from (i) any failure, breach or inaccuracy of any representations or warranties made by the Class B Equity Investor and any breach by the Class B Equity Investor of any covenant, obligation or agreement, in each case contained in this Agreement, the Fee Letter or any certificate delivered hereunder or thereunder (collectively, “Class A ECCA Claims”), (ii) any unpaid amounts or defaults under the applicable Construction Contract, the absence of which would have been confirmed by a counterparty in a Specified Estoppel, had such Specified Estoppel, in the form attached to this Agreement, been executed and delivered on the Initial Capital Contribution Date or Final Capital Contribution Date, as applicable (collectively, “Specified Estoppel Claims”), (iii) any action, suit or proceeding by or before any Governmental Authority that is pending as of the Final Capital Contribution Date challenging any federal Permit or Departure Approval of the Project, including that certain Notice of Approval of Construction and Operations Plan (COP) and Project Easement, dated as of July 15, 2021, in respect of the Project (collectively, “Specified COP Claims”) and (iv) the Specified LA Proceeding (collectively, “Specified ILA Claims” and together with the Class A ECCA Claims, Specified Estoppel Claims and Specified COP Claims, “Class A Equity Investor Claims”); provided that the Class B Equity Investor will not have any indemnification obligations for Damages for (x) Specified Estoppel Claims from and after the applicable Specified Estoppel Satisfaction Date, (y) Specified COP Claims (1) if no such action, suit or proceeding challenging any federal Permit or Departure Approval of the Project is pending as of the Final Capital Contribution Date or (2) in the event any such action, suit or proceeding challenging any federal Permit or Departure Approval of the Project is pending as of the Final Capital Contribution Date, from and after the date that all such actions, suits or proceedings have been finally determined with no further liability to the Project Company and (z) Specified ILA Claims (1) if the Specified ILA Proceeding is not pending as of the Final Capital Contribution Date or (2) in the event the Specified ILA Proceeding is pending as of the Final Capital Contribution Date, from and after the date that the Specified ILA Proceeding has been finally determined with no further liability to the Project Company.
(b)For the sole purpose of determining whether a failure, breach or inaccuracy of Section 3.24 (No Casualty) and Section 3.25 (No Condemnation) has occurred (and not for determining whether or not a condition precedent has been satisfied), the representations and warranties of Class B Equity Investor in Section 3.24 (No Casualty) and Section 3.25 (No Condemnation) in this Agreement shall be deemed to be qualified by materiality, rather than Material Adverse Effect.


8.2Limitations on Liability. The obligations of the Class B Equity Investor under Section 8.1 shall be subject to the following limitations:
(a)Threshold Amount. No claim for indemnification under this Article VIII may be made by any Class A Equity Investor Indemnitee (other than (i) those related to fraud, gross negligence or willful misconduct and (ii) Specified COP Claims) unless and until the aggregate amount of Damages subject to such claim for indemnification, together with all prior claims by such Class A Equity Investor Indemnitee and other members of such Class A Equity Investor Indemnitee group equals or exceeds $1,000,000 in the aggregate (the “Threshold”); provided that, for purposes of clarification, once the Threshold is crossed and any claim for indemnification is agreed or determined, the Class B Equity Investor shall be obligated to pay the Class A Equity Investor Indemnitees from the first Dollar of Damages.
(b)Duration of Representations and Warranties. All representations and warranties made by the Class B Equity Investor shall survive only for eighteen months from the earlier of the Final Capital Contribution Date or the Outside Date, except that representations and warranties (i) under Section 3.1 (Organization and Good Standing), Section 3.2 (Authority; Execution and Delivery; Enforceability), Section 3.5 (Ownership), Section 3.6 (Valid Interests) and Section 3.19 (Brokers) (the “Fundamental Reps”) shall survive indefinitely, (ii) under Section 3.16 (Tax Matters) shall survive until the date that is 60 days after the expiration of the statute of limitations on any IRS audit of the Company tax year for which such item is relevant and (iii) under Section 3.9 (Environmental Matters) shall survive for three years from the earlier of the Final Capital Contribution Date or the Outside Date.
(c)Submission of Claims. Any Claim by a Party for an indemnity or Damages based on a misrepresentation by another Party hereto must be made in writing within the respective survival periods set forth in Section 8.2(b) above. The Class A Equity Investor Indemnitees shall pursue recourse for Class A Equity Investor Claims under the Sponsor Guaranties concurrently with any claims on the Class B Equity Investor hereunder.
(d)No Punitive or Consequential Damages. Except to the extent constituting Third-Party Claims as set forth in Section 8.3, no Party or any of its respective officers, members, shareholders, partners, principals, Affiliates, agents, subcontractors, vendors or employees shall be liable for punitive, consequential or exemplary losses or damages of any nature (including damages for lost profits or revenues or the loss or use of such profits or anticipated revenue, cost of capital, loss of goodwill, damages to reputation or damages for lost opportunities, except to the extent that any of the foregoing constitutes direct damages), or any other special or incidental damages, regardless of whether said Claim is based upon contract, warranty, tort (including negligence and strict liability) or other theory of Law; provided that to the extent ITCs are reduced, recaptured, disallowed or lost as a result of representations and warranties made by the Class B Equity Investor being false in any respect when made or deemed made, or the breach of any covenant, obligation or agreement by the Class B Equity Investor, the value of such reduced, recaptured, disallowed or lost ITCs shall not constitute punitive, consequential or exemplary losses or damages.
(e)Overall Limitation on Liability. The total maximum liability of the Class B Equity Investor to all Class A Equity Investor Indemnitees under this Article VIII with respect to Damages for any Class A Equity Investor Claims (other than Class A Equity Investor Claims by reason of or resulting from any breach or inaccuracy of Fundamental Reps or from fraud, gross negligence or willful misconduct of the Class B Equity Investor)) shall not exceed in the aggregate (i) 100% of the aggregate amount of the Capital Contributions actually contributed by the Class A Equity Investors under this Agreement and the Class A Members under the LLC Agreement, less (ii) amounts previously paid with respect to indemnification obligations under any Transaction Document to the Class A Equity Investor Indemnitees.


(f)Capital Contribution Adjustment. Any indemnity payment or payment of Damages shall be “grossed up” for income taxes that the recipient will have to pay on the payment, taking into account the net present value of Tax benefits (calculated at a discount rate equal to the Target IRR, assuming the Highest Marginal Rate applies to the recipient) reasonably expected to be realized as a result of the payment (assuming that each recipient will have sufficient taxable income for U.S. federal income tax purposes to fully utilize on a current basis any such Tax benefits as a result of payment) and the amount of any tax required to be paid by the recipient on the receipt or accrual of the additional amount required to be added to such payment under this Article VIII, assuming the Highest Marginal Rate applies to the recipient; provided that any indemnity payment or payment of Damages shall be treated as a return of capital, and, accordingly, no “gross-up” shall be payable, if the Class B Equity Investor provides an opinion reasonably acceptable to the Class A Equity Investors at a “should” level or higher from a nationally recognized tax counsel mutually acceptable to both the Class A Equity Investors and the Class B Equity Investor that such indemnity payment or payment of Damages may be treated as a return of capital or basis. If the tax position supported by such tax opinion is subsequently disallowed by the IRS or another relevant taxing authority, the Class B Equity Investor shall promptly pay the gross-up amount described in the preceding sentence to the applicable Class A Equity Investor Indemnitees. This paragraph shall not be construed to require any indemnified party to make available its Tax Returns (or any other information relating to its Taxes that it deems confidential) to the indemnifying party or any other Person.
(g)Excluded Events. Notwithstanding the foregoing, in no event shall the Class B Equity Investor or any Class B Member be required to indemnify the Class A Equity Investors for any loss of any ITC or other Tax Benefits to the extent such loss is the result of: (i) a change in applicable Law (including any Change in Tax Law); (ii) the failure of any Fixed Tax Assumption to be true, except to the extent such Fixed Tax Assumption is inaccurate as a result of (1) the inaccuracy, failure or breach of any representation or warranty, or breach of any covenant, obligation or agreement, of a Class B Member or any Affiliate of a Class B Member in any Transaction Document or any other Contract between any Affiliate of a Class B Member and a Project Entity (except for any action taken at the direction of, or with the prior written consent of, the Class A Members) or (2) the filing of a federal income tax return that is inconsistent with any such Fixed Tax Assumption, unless such return is a Specified Inconsistent Return; or (iii) the failure, breach or inaccuracy of any representations or warranties made by the applicable Class A Equity Investor or any breach by the Class A Equity Investor of any covenant, obligation or agreement contained in this Agreement or in the LLC Agreement.
(h)Mitigation. A Class A Equity Investor Indemnitee shall mitigate its Damages relating to a Claim as required under applicable Law. Any insurance proceeds or other cash settlement or recovery amounts received by third parties as an offset against such Damages recovered in connection with such mitigation efforts (collectively, “Third-Party Recoveries”) shall reduce the amount of Damages required to be paid; provided that any such Third-Party Recoveries shall not prejudice any claim against the Class B Equity Investor, whether through subrogation or otherwise, by an insurer of a Class A Equity Investor Indemnitee for reimbursement of such amounts.
(i)Subsequent Recoveries. If, at any time subsequent to the Class B Equity Investor having made full payment of a Class A Equity Investor Claim under Section 8.1, the Class A Equity Investor Indemnitee shall, within fifteen days after receipt thereof, repay an amount equal to such Third-Party Recoveries less any out-of-pocket costs and expenses (including reasonable legal fees and expenses) incurred by such Class A Equity Investor Indemnitee in seeking such Third-Party Recoveries up to the aggregate amount of the payments made by the Class B Equity Investor to such Class A Equity Investor Indemnitee. If any portion of Damages to be reimbursed by the Class B Equity Investor have been covered, in whole or in part, by Third-Party Recoveries, the Class A Equity Investor Indemnitee shall promptly give notice thereof to the Class B Equity Investor.


(j)Contribution. Anything to the contrary herein notwithstanding, the Class B Equity Investor shall not have any right to seek contribution from any Project Entity or Shareco with respect to all or any part of its indemnification obligations under Section 8.1.
8.3Procedures for Indemnification With Respect to Third-Party Claims.
(a)Notice of Third-Party Claims. If any legal proceedings shall be instituted or any claim or demand shall be asserted by any third party (each, a “Third-Party Claim”) in respect of which indemnification may be sought by any Class A Equity Investor Indemnitee under this Article VIII, such Class A Equity Investor Indemnitee shall, as soon as practicable after the actual receipt thereof by a responsible officer, cause written notice of such legal proceedings or the assertion of such Third-Party Claim to be forwarded to the Class B Equity Investor, specifying the nature of such legal proceedings or Third-Party Claim and the amount or the estimated amount thereof to the extent then determinable, which estimate shall not be binding upon the Class A Equity Investor Indemnitee; provided that the failure of a Class A Equity Investor Indemnitee to give timely notice shall not affect its rights to indemnification under Section 8.1, except to the extent that the Class B Equity Investor has been actually prejudiced by such failure.
(b)Access to Counsel and Settlement. So long as the Class B Equity Investor has acknowledged in writing to the applicable Class A Equity Investor Indemnitees that it is liable for such Third-Party Claim, the Class B Equity Investor shall be entitled to participate in and unless (i) in the reasonable judgment of the applicable Class A Equity Investor Indemnitees a conflict of interest between it and the Class B Equity Investor exists or could be reasonably likely to exist in respect of such Third-Party Claim, (ii) such Third-Party Claim entails a risk of criminal penalties or civil fines or non-monetary sanctions being imposed on the applicable Class A Equity Investor Indemnitees or (iii) such Third-Party Claim involves any tax contest or dispute involving any Class A Equity Investor or any Affiliate thereof (which shall be governed by Section 9.8 of the LLC Agreement), assume, at its expense, the defense thereof with counsel reasonably satisfactory to such Class A Equity Investor Indemnitees. If the Class B Equity Investor (1) cannot assume the Claim as a result of the conditions set forth in clause (i), (ii) or (iii) above, (2) advises the applicable Class A Equity Investor Indemnitees that it will not assume the defense of such Third-Party Claim or (3) fails, within 30 days of receipt of notice of the Class A Claim or notice of the Third Party Claim, to notify, in writing, the applicable Class A Equity Investor Indemnitees of such assumption (or discontinues its defense at any time after it commences such defense), the applicable Class A Equity Investor Indemnitees will be entitled to assume the defense of such Third-Party Claim with counsel of its own choice, at the expense of the Class B Equity Investor. If the Third-Party Claim is asserted against both the Class B Equity Investor and the applicable Class A Equity Investor Indemnitees and (x) there is a conflict of interest which renders it inappropriate for the same counsel to represent both the Class B Equity Investor and the applicable Class A Equity Investor Indemnitees or (y) such Third-Party Claim could reasonably be expected to result in the imposition of criminal liability, the Class B Equity Investor will be responsible for paying for separate counsel for the applicable Class A Equity Investor Indemnitees; provided, however, that if there is more than one Class A Equity Investor Indemnitee, the Class B Equity Investor will not be responsible for paying for more than one separate firm of attorneys to represent the applicable Class A Equity Investor Indemnitees, regardless of the number of Class A Equity Investor Indemnitees, unless the nature of the Third-Party Claim presents a conflict of interest among the Class A Equity Investor Indemnities, which renders it inappropriate or impossible for the same counsel to represent each of the applicable Class A Indemnitees, in which case, each such Class A Indemnitee shall have the right to retain separate counsel at the expense of Class B Members. If the Class B Equity Investor elects to assume the defense of such Third-Party Claim, (A) no compromise or settlement thereof may be effected by the Class B Equity Investor without the applicable Class A Equity Investor Indemnitees’ prior written consent (which will not be unreasonably withheld) unless the sole relief provided is monetary damages that are paid in full by the Class B Equity Investor and (B) the Class B Equity Investor shall have no liability with respect to any compromise or settlement thereof effected without its written consent (which will not be unreasonably withheld).


(c)Payment Upon Final Judgment. After final judgment or award shall have been rendered by a court, arbitration board or administrative agency of competent jurisdiction and the expiration of the time in which to appeal therefrom (other than appeals to the United States Supreme Court), or a settlement shall have been consummated, or the applicable Class A Equity Investor Indemnitees and the Class B Equity Investor shall have arrived at a mutually binding agreement with respect to each separate matter indemnified by the Class B Equity Investor, the applicable Class A Equity Investor Indemnitees shall forward to the Class B Equity Investor notice of any sums due and owing by the Class B Equity Investor with respect to such matter, and such amount shall be paid as provided in Section 8.5.
(d)Assistance with Defense of Claims. If any claim is made by a third party against a Class A Equity Investor Indemnitee, the Class A Equity Investor Indemnitee shall use commercially reasonable efforts to make available to the Class B Equity Investor those partners, members, officers and employees whose assistance, testimony or presence is necessary to assist the Class B Equity Investor in evaluating and in defending such claims; provided that any such access shall be conducted in such a manner as not to interfere unreasonably with the operations of the business of the applicable Class A Equity Investor Indemnitees.
8.4Exclusivity. Without limiting any Class A Equity Investor Indemnitee’s rights under the Sponsor Guaranties or the other Transaction Documents or for any equitable remedy, the Parties hereto agree that, in relation to any breach, default or nonperformance of any representation, warranty, covenant or agreement made pursuant to this Agreement, the only relief and remedy available to the Class A Equity Investor Indemnitees for the recovery of monetary damages in respect of said breach, default or nonperformance shall be Damages, as limited pursuant to this Article VIII or otherwise hereunder.
8.5Payment of Indemnification Claims. All claims for indemnification (including the payment of Damages) shall be paid by the Class B Equity Investor in immediately available funds in Dollars. Payments for indemnification claims shall be made promptly after any final determination (that is not subject to appeal (other than appeals to the United States Supreme ourt)) of the amount of such claim is made by a court of competent jurisdiction (or by agreement of the Class B Equity Investor and the Class A Equity Investor Indemnitee involved).
8.6No Duplication. The Parties, for themselves, their Affiliates, successors and permitted assigns agree that, notwithstanding anything to the contrary herein or in any other agreement, any liability for indemnification under this Article VIII shall be without duplication of recovery of amounts payable under this Agreement, the LLC Agreement, the PSA or the Sponsor Guaranties.
ARTICLE IX
TERMINATION; CLASS A WITHDRAWAL
9.1Termination. Without limiting the ability of the Parties to exercise any right or remedy to which any of them is entitled hereunder or under any of the Transaction Documents, the Parties’ obligations under this Agreement may be terminated:
(a)by the mutual written consent of the Class B Equity Investor and the Class A Equity Investors;
(b)by either the Class B Equity Investor or the Class A Equity Investors, if the Final Capital Contribution Date has not been consummated by the close of business on the Outside Date; provided that such Party will not have the right to terminate this Agreement if the applicable conditions to the Final Capital Contribution Date have not been satisfied due to a breach by such Party of its representations, warranties and covenants under this Agreement;
(c)upon the occurrence of the Class A Withdrawal Date;


(d)by the Class B Equity Investor, upon ten days’ prior written notice to the Class A Equity Investors, in the event that one or more Class A Equity Investors are in breach of their respective obligations to make their respective Initial Class A Capital Contribution and such breach has not been cured (including by a Funding Class A Equity Investor in accordance with Section 2.1(e)(ii) or by a Replacement Class A Equity Investor) within such ten-day period, but only if the Class B Equity Investor is not in breach in any material respect of its covenants or agreements contained in this Agreement and subject to a return of all Capital Contributions made by any Funding Class A Equity Investor; and
(e)by either the Class B Equity Investor or the Class A Equity Investors, upon 30 days’ prior written notice to the other Parties, in the event the Class B Equity Investor or the Company (with respect to a termination by the Class A Equity Investors) or a Class A Equity Investor (with respect to a termination by the Class B Equity Investor) is in breach of a covenant or agreement contained in this Agreement (other than with respect to the making of Capital Contributions as described in clause (d) above), and such breach has not been cured during such 30-day period, or such longer period of time as is reasonably necessary to cure such breach; provided, however, that the Party seeking termination pursuant to this clause (e) must not be in breach in any material respect of its covenants or agreements contained in this Agreement.
9.2Procedure and Effect of Termination; Survival.
(a)The Party desiring to terminate this Agreement pursuant to Section 9.1(b), Section 9.1(d) or Section 9.1(e), shall give written notice of such termination to the other Parties in accordance with Section 10.1, specifying the provision hereof pursuant to which such termination is effected.
(b)If this Agreement is terminated pursuant to Section 9.1, then this Agreement shall become void and of no effect with no liability on the part of any Party to the extent of such termination, except that (i) the agreements contained in Article VIII, this Section 9.2(b), Section 9.3, Article X and the obligations of the Class B Equity Investor under the Fee Letter shall each survive the termination, and (ii) no such termination shall relieve any Party of any liability or Damages or affect the rights of the other Party to indemnification pursuant to Article VIII; provided that, with respect to clause (ii), if the Agreement is terminated prior to the Initial Capital Contribution Date, the Class B Equity Investor’s liability for any breach of this Agreement shall be limited to the payment of Transaction Expenses incurred by the Class A Equity Investors pursuant to (and subject to the limitations in) Section 10.2 through the effective date of such termination.
9.3Class A Withdrawal.
(a)If (i) the Initial Capital Contribution Date has occurred, (ii) the Final Capital Contribution Date has not occurred by the Outside Date and (iii) no string of Turbines has been Placed in Service by the Outside Date (a “Class A Withdrawal Trigger Event”), then the Class B Equity Investor shall purchase 100% of the Class A Membership Interests (the “Class A Withdrawal”) upon payment by the Class B Equity Investor in full to the Class A Equity Investors of an amount equal to the aggregate amount of the Capital Contributions actually contributed by the Class A Equity Investors under this Agreement, together with interest on such amount being returned at a rate per annum (based on a 360-day year of twelve 30-day months) equal to the Target IRR for the period commencing on the Initial Capital Contribution Date and ending on the date such funds are returned to each Class A Equity Investor (the “Class A Withdrawal Price”). The Class A Withdrawal will be consummated within 30 days after the Class A Withdrawal Trigger Event (such date on which the Class A Withdrawal is consummated, the “Class A Withdrawal Date”). (b) On the Class A Withdrawal Date, the Class B Equity Investor shall pay the Class A Withdrawal Price to the Class A Equity Investors to purchase the applicable Class A Membership Interests. To the extent the Class B Equity Investor does not pay the full Class A Withdrawal Price on the Class A Withdrawal Date, the Class A Equity Investors may elect to seek payment of any shortfall pursuant to the Sponsor Guaranties. (c) If (i) the Initial Capital Contribution Date has occurred, (ii) the Final Capital Contribution Date has not occurred by the Outside Date, (iii) at least one string of Turbines have been Placed in Service by the Outside Date and (iv) the Lenders have not elected remedies against the Project, the Project Company or the membership interests of the Project Company, then: (x) the Class A Equity Investors and the Class B Equity Investor will


negotiate in good faith to adjust the investment in the Company by the Class A Equity Investors; (y) the allocations and distributions in Articles IV and V of the LLC Agreement will be adjusted and incorporated into the Base Case Model and, if necessary, the Class B Equity Investor shall make a liquidated payment to the Class A Equity Investors, in each case to the extent necessary to reach, but not exceed, the Pricing Parameters (provided that any such adjustments will be mutually agreed upon by the Class A Equity Investors and the Class B Equity Investor); and (z) the LLC Agreement will be amended as necessary to incorporate any such changes agreed to by the Class A Equity Investors and the Class B Equity Investor as described in clause (y) above.
ARTICLE X
GENERAL PROVISIONS
10.1Notices. All notices and other communications given hereunder shall be in writing and be delivered to the intended recipient at the address of such Party listed in this Section 10.1 in person, by courier or certified mail, return receipt requested, or by e-mail. A notice shall be deemed delivered and effective on the earliest to occur of: (i) its actual receipt when delivered in person, (ii) the fifth Business Day following its deposit in registered or certified mail, with postage prepaid, and return receipt requested, (iii) the second Business Day following its deposit with a recognized overnight courier service, or (iv) immediately when transmitted via e-mail (without any “bounce-back” or similar error message) between 9:00 a.m. and 6:00 p.m. Eastern Time on any Business Day (or the immediately succeeding Business Day if transmitted outside of such hours).
If to the Class B Equity Investor or the Company, to:
c/o Vineyard Wind Management Company LLC
75 Arlington Street, 7th Floor
Boston, MA 02116
If to JPM, to:
JPMorgan Chase Bank, N.A.
Attention: Contract Administration
CIB-Tax Oriented Investments
10 South Dearborn, 7th Floor
Chicago, Illinois 60603
with a copy to (which shall not constitute notice):
JPMorgan Chase Bank, N.A.
480 Washington Blvd, Floor 23
Jersey City, NJ, 07310-2053, United States
If to BofA, to:
Bank of America, N.A.
555 California Street, 6th Floor
CA5-705-06-34
San Francisco, CA 94104
Attention: Contracts Administration


with an additional copy to:
Bank of America, N.A.
One Financial Plaza, 6th Floor,
RI1-537-06-05
Providence, RI 02903
If to Wells, to:
Wells Fargo Bank, N.A.
c/o Wells Fargo Commercial Banking
Attention: Renewable Energy Portfolio Management
MAC A0101-093
420 Montgomery Street, 9th Floor
San Francisco, CA 94104
With a copy to (which shall not constitute notice):
Wells Fargo Legal Group
Capital Markets Counsel
MAC J0161-245
150 E 42nd Street, 24th Floor
New York, NY 10017
Any Person may change the address or number to which notices are to be delivered to him, her or it by giving the other Persons named above notice of the change in the manner set forth above.


10.2Transaction Expenses.
(a)The Class B Equity Investor shall pay or cause to be paid (including through the application of funds available under the Loan Documents): (i) its own legal and financial advisory fees and expenses and (ii) the cost of the preparation and delivery of all consultant reports prepared in connection with the Transaction by the Independent Engineer, the Insurance Consultant, the Independent Appraiser, the Cost Segregation Consultant, the Wind Consultant, the Environmental Consultant and the Transmission Consultant. The Class B Equity Investor shall pay or cause to be paid (including through the application of funds available under the Loan Documents) the reasonable and documented fees and expenses of (x) Milbank LLP, the Class A Equity Investors’ lead legal counsel, which such fees will be subject to the terms separately agreed between Milbank LLP and the Project Company, (y) Nutter McClennen and Fish LLP, the Class A Equity Investors’ Massachusetts counsel, which such fees will be subject to the terms separately agreed between Nutter McClennen and Fish LLP and the Project Company and (z) Gorrissen Federspiel Advokatpartnerselskab, the Class A Equity Investors’ Danish counsel, which such fees will be subject to the terms separately agreed between Gorrissen Federspiel Advokatpartnerselskab and the Project Company, but shall not be required to pay any other fees and expenses of the Class A Equity Investors in connection with the achievement of the ECCA Effective Date or the Capital Contribution Dates (collectively, all fees and expenses described in this Section 10.2(a), the “Transaction Expenses”).
(b)The Class A Equity Investors shall directly engage DNV GL to assist with the Class A Equity Investors’ due diligence and will pay DNV GL’s fees and expenses directly, without impacting the Class A Equity Investors’ obligations hereunder or the Project construction schedule. The Class A Equity Investors acknowledge and agree that any energy production report prepared by DNV-GL is for informational purposes only and that the production estimates prepared by the Wind Consultant, shall be used in the Base Case Model for all purposes hereunder.
10.3Counterparts. This Agreement may be executed and delivered (including by facsimile transmission or portable document format (.pdf)) in one or more counterparts, each bearing the signatures of one or more Parties. Each such counterpart shall be considered an original and all of such counterparts shall constitute a single agreement binding all the Parties as if all had signed a single document. Signatures of the Parties transmitted by facsimile or portable document format (.pdf) shall be deemed to be their original signatures for all purposes of this Agreement.
10.4Governing Law and Severability. This Agreement shall be construed, interpreted and enforced in accordance with the internal Laws and decisions of the State of New York applicable to Contracts performed in that state. If any provision of this Agreement shall be contrary to any other applicable Law, at the present time or in the future, such provision shall be deemed null and void, but this shall not affect the legality of the remaining provisions of this Agreement. This Agreement shall be deemed to be modified and amended so as to be in compliance with applicable Law and this Agreement shall then be construed in such a way as will best serve the intention of the Parties at the time of the execution of this Agreement.
10.5Entire Agreement. This Agreement, including any Schedules, Annexes and Exhibits, together with the other Transaction Documents, constitutes the entire agreement among the Parties regarding the terms and conditions of the Transaction, except as amended in writing pursuant to the requirements of this Agreement, and supersedes all prior and contemporaneous agreements, statements, understandings and representations of the Parties.
10.6Effect of Waiver or Consent. A waiver or consent, express or implied, to or of any breach or default by any Person in the performance by that Person of its obligations under this Agreement, or any Transaction Document is not a consent or waiver to or of any other breach or default in the performance by that Person of the same or any other obligations of that Person under this Agreement, or any Transaction Document. Failure on the part of a Person to complain of any act of any Person or to declare any Person in default with respect to its obligations under this Agreement, or any Transaction Document, irrespective of how long that failure continues, does not constitute a waiver by that Person of its rights with respect to that default until the applicable statute of limitations period has run.


10.7Amendments and Modifications. Except as otherwise provided herein and subject to Section 9.15(a)(iv) of the LLC Agreement, this Agreement may be amended or modified from time to time only by a written instrument executed by all Parties hereto.
10.8Disclosure Schedules.
(a)Updates to Disclosure Schedules. After the ECCA Effective Date and immediately prior to each Capital Contribution Date by written notice to the Class A Equity Investors, the Class B Equity Investor shall supplement and amend the Disclosure Schedules (each, an “Update”) as may be required to make the representations of the Class B Equity Investor set forth herein not materially false or incorrect; provided that delivery of any change or addition hereunder shall not be evidence of the materiality or non-materiality of such change or addition. Subject to Section 10.8(b), any matter disclosed in any section of the Disclosure Schedules shall be deemed disclosed for all purposes and all sections of the Disclosure Schedules to the extent it is readily apparent from a reading of the disclosure that such disclosure is applicable to such other sections.
(b)Effect of Updates. For all purposes of this Agreement, including for purposes of determining whether the conditions in Sections 6.1, 6.2 and 6.3 have been fulfilled, the Disclosure Schedules shall be deemed to include all information contained therein on the ECCA Effective Date and shall be deemed to exclude all information contained in any Update; provided that any Updates to the Disclosure Schedules provided pursuant to Section 10.8(a) shall automatically update the representations and warranties for the sole purpose of determining the satisfaction of the conditions precedent set forth in Sections 6.1(e), 6.2(c) and 6.3(e) (but, for the avoidance of doubt, not the underlying representations and warranties in Article III or the conditions precedent in Sections 5.1(g), 6.6(bb), 6.2(i) or 6.3(aa) unless either (x) the Class A Equity Investors have provided their prior written consent or (y) the Update (i) is limited to a matter that would not constitute a “Fundamental Decision” or a “Major Decision” (in each case, as defined in the LLC Agreement), (ii) such Update could not reasonably be expected to affect any assumptions made in the Base Case Model that have not otherwise been updated for such Update on the Initial Capital Contribution Date or the Final Capital Contribution Date, as applicable, and (iii) such Update could not reasonably be expected to have a Material Adverse Effect) except to the extent that the failure of such representations or warranties to be true and correct, or the matter disclosed in such Updates, in either case, has or could reasonably be expected to have a Material Adverse Effect, in which case, such Updates shall be subject to the prior written approval of the Class A Equity Investors, acting reasonably.
10.9Binding Effect. Subject to the restrictions set forth in this Agreement, this Agreement is binding on and inures to the benefit of the Parties hereto and their respective legal representatives, permitted successors and permitted assigns and inures to the benefit of the Class A Equity Investor Indemnitees (solely with respect their right to indemnities in Article VIII, as it may be amended and modified in accordance with this Agreement).
10.10Further Assurances. In connection with this Agreement and the Transaction, each Party shall execute and deliver or cause to be executed and delivered any additional documents, certificates, consents, waivers and instruments and perform any additional acts that may be necessary or appropriate to effectuate and perform the provisions of this Agreement and the Transaction.
10.11Assignability and Parties in Interest.
(a)Other than as permitted pursuant to Section 10.11(b) and (c), this Agreement and the rights, interests or obligations hereunder may not be assigned by any of the Parties hereto without the prior written consent of the other Parties hereto. Except as provided in Section 10.9, nothing in this Agreement shall confer upon any Person not a Party to this Agreement, or the legal representatives of such Person, any rights or remedies of any nature or kind whatsoever under or by reason of this Agreement.
(b)Any assignment by a Class A Equity Investor of this Agreement shall be permitted solely in connection with a Transfer of its Class A Membership Interest pursuant to and in accordance with Article IX of the LLC Agreement (assuming, for assignments prior to the Initial Capital Contribution Date, that the LLC Agreement is in effect).


(c)Nothing herein shall restrict the Class B Equity Investor from collaterally assigning its interest in this Agreement or the Class B Membership Interests, or restrict the Company from collaterally assigning the membership interests in the Project Company, in each case to the Collateral Agent, pursuant to the Construction Loan Agreement and related Loan Documents, solely for the period ending on the Final Capital Contribution Date.
10.12Jurisdiction; Service of Process; WAIVER OF JURY TRIAL. Each Party hereby irrevocably consents to the exclusive jurisdiction of the courts of the State of New York and of any federal court located in the Southern District of New York, each sitting in New York County, in connection with any suit, action or other proceeding arising out of or relating to this Agreement or the Transaction; agrees to waive any objection to venue in the County of New York, State of New York; and agrees that, to the extent permitted by Law, service of process in connection with any such proceeding may be effected by mailing in the same manner provided in Section 10.1 hereof. EACH PARTY IRREVOCABLY AND UNCONDITIONALLY WAIVES THE RIGHT TO TRIAL BY JURY IN ANY ACTION, SUIT OR PROCEEDING RELATING TO A DISPUTE HEREUNDER AND ANY COUNTERCLAIMS WITH RESPECT HERETO.
10.13Confidentiality; Public Announcements.
(a)Confidentiality. Each Class A Equity Investor, except to the extent necessary for the exercise of its rights and remedies and the performance of its obligations under this Agreement, shall not itself use or intentionally disclose (and shall not permit the use or disclosure by any of its Affiliates or its advisors, counsel and public accountants (collectively, “Advisors”)) of, directly or indirectly, any of the Material Project Agreements or information furnished thereunder, or this Agreement or information furnished hereunder, and shall use all reasonable efforts to have all such information kept confidential (consistent with the terms of such Material Project Agreements and its own practices) and not used in any way known to such Class A Equity Investor to be detrimental to the Class B Equity Investor or the Project Entities; provided, that (i) such Class A Equity Investor and its Advisors may use, retain and disclose any such information to its special counsel and public accountants or any Governmental Authority, (ii) such Class A Equity Investor and its Advisors may use, retain and disclose any such information that (A) has been publicly disclosed (other than by such Class A Equity Investor or any Affiliate thereof or any of its Advisors in breach of this Section 10.13), (B) has rightfully come into the possession of such Class A Equity Investor or any Affiliate thereof or any of its Advisors other than from another Party hereto or a Person acting on such other Party’s behalf or (C) has been independently developed by such Class A Equity Investor or its Affiliates or Advisors, (iii) to the extent that such Class A Equity Investor or any Affiliate thereof or its Advisors may have received a subpoena or other written demand under color of legal right for such information, such Class A Equity Investor or such Affiliate or Advisor may disclose such information, but such Class A Equity Investor shall first, as soon as practicable upon receipt of such demand, furnish a copy thereof to the other Parties and, if practicable so long as such Class A Equity Investor shall not be in violation of such subpoena or demand or likely to become liable to any penalty or sanctions thereunder, afford the other Parties reasonable opportunity, at any other Party’s cost and expense, to obtain a protective order or other reasonably satisfactory assurance of confidential treatment for the information required to be disclosed, (iv) disclosures to lenders, potential lenders, equity investors, potential equity investors, actual or potential ITC Transferees or other Persons providing direct or indirect financing to any Project Entity, any member in the Company or to their respective representatives and advisors and potential purchasers of direct or indirect equity interests in the Company, if such Persons have agreed to abide by the terms of this Section 10.13 or have otherwise entered into an agreement with restrictions on disclosure substantially similar to the terms of this Section 10.13 (or in the case of advisors, are otherwise bound by professional or legal obligations of confidentiality) and (v) such Class A Equity Investor and its Advisors may disclose any such information, and make such filings, as may be required by this Agreement or the Material Project Agreements. Notwithstanding anything herein to the contrary, each Class A Equity Investor may disclose information to its Affiliates and other Advisors in accordance with this Agreement if such Persons have agreed to the terms of this Section 10.13.


(b)Each Party agrees that no adequate remedy at law exists for a breach or threatened breach of any of the provisions of this Section 10.13, the continuation of which unremedied will cause the other Party to suffer irreparable harm. Accordingly, each Party agrees that the other Party shall be entitled, in addition to other remedies that may be available to it, to immediate injunctive relief from any breach of any of the provisions of this Section 10.13 and to specific performance of its rights hereunder, as well as to any other remedies available at law or in equity.
(c)Notwithstanding anything to the contrary, the foregoing obligations shall not apply to the tax treatment or tax structure of the Transaction and each Party hereto (and any employee, representative, or agent of any Party) may disclose to any and all Persons, without limitation of any kind, the tax treatment and tax structure of the Transaction and all other materials of any kind (including opinions or other tax analyses) that are provided to any Party hereto to the extent relating to such tax treatment and tax structure. However, any such information relating to such tax treatment and tax structure is required to be kept confidential to the extent necessary to comply with any applicable securities Laws. The preceding sentences are intended to cause the Transaction not to be treated as having been offered under conditions of confidentiality for purposes of Sections 1.6011-4(b)(3) and 301.6111-2(a)(2)(ii) (or any successor provision) of the Treasury Regulations and shall be construed in a manner consistent with such purpose.
(d)Public Announcements. The Parties shall consult with one another before issuing any press releases or otherwise making any public statements with respect to this Agreement and the Transaction and shall not issue any such press release or make any such public statement without the consent of the other Parties, unless such action is required by Law.
10.14Direct Pay. Should legislation relating to “direct pay” (or any similar mechanic in respect of ITCs relating to the Project) be enacted prior to the Initial Capital Contribution Date, the Parties agree to consider in good faith a proposed restructuring of the Transaction to substitute the “direct pay” (or any similar mechanic in respect of ITCs relating to the Project) option for the ITC; provided that no such circumstance shall result in any unilateral right to terminate this Agreement.
10.15No Strict Construction. The Transaction Documents are the result of negotiations among, and have been reviewed by, the Class A Equity Investors, the Class B Equity Investor and their respective counsel. Accordingly, the Transaction Documents shall be deemed to be the product of all Parties thereto, and no ambiguity shall be construed in favor of or against the Class A Equity Investors or the Class B Equity Investor.
10.16Certain Investor Consents. Promptly following any request therefor by the Class B Equity Investor, each of the Class A Equity Investors shall (a) enter into the Investor Consent (ECCA), (b) consent to the entry into the Investor Consent (PSA) by the Company and (c) request that Milbank LLP provide an opinion with respect to enforceability of the Investor Consent (ECCA), in form and substance reasonably acceptable to the Class B Equity Investor.
[SIGNATURE PAGE FOLLOWS]


IN WITNESS WHEREOF, the Parties hereto have caused this Agreement to be executed by their duly authorized representatives as of the date first written above.
CLASS B EQUITY INVESTOR:
VINEYARD WIND SPONSOR PARTNERS 1 LLC
s/ Klaus Skoust Moeller
Name: Klaus Skoust Moeller
Title: Chief Executive Officer
s/ Miguel Sanchez Calero
Name: Miguel Sanchez Calero
Title: Deputy Chief Executive Officer





































[Signature Page to Equity Capital Contribution Agreement (Vineyard Wind 1)]


JPM: JPMORGAN CHASE BANK, N.A.
s/ Joel Spenadel
Name: Joel Spenadel
Title: Executive Director
BofA: BOFA SECURITIES, INC.
s/ Jung Westover
Name: Jung Westover
Title: Vice President
Wells: WELLS FARGO BANK, N.A.
s/ Andrew Kho
Name: Andrew Kho
Title: Managing Director

EX-10.48 4 agr-ex1048x2023.htm EX-10.48 Document

Exhibit 10.48
Performance Stock Unit Award Agreement
This Performance Stock Unit Award Agreement (this “Agreement”) is made and entered into as of _____________ (the “Grant Date”) by and between Avangrid, Inc., a New York corporation (the “Company”), and _____________ (the “Grantee”) under the Avangrid Inc. Amended and Restated Omnibus Incentive Plan, as such plan may be amended from time to time (the “Plan”).
1.Grant of Performance Stock Units. Pursuant to Section 7 of the Plan, the Company hereby grants to the Grantee an Award for a maximum number of _____________ performance stock units (the “Maximum Award”) subject to certain performance-based vesting conditions and other restrictions as set forth in this Agreement (“Performance Stock Units” or “PSUs”). Each PSU represents the right to receive one share of Common Stock, subject to the terms and conditions set forth in this Agreement and the Plan. The number of PSUs that the Grantee actually earns for the Performance Period (up to a maximum of _____________) will be determined by the level of achievement of the Performance Goals in accordance with Exhibit I attached hereto. Capitalized terms that are used but not defined herein have the meanings ascribed to them in the Plan.
2.Performance Period. For purposes of this Agreement, the term “Performance Period” shall be the period commencing on January 1, 2023 and ending on December 31, 2025.
3.Performance Goals.
a.The number of PSUs earned by the Grantee for the Performance Period will be determined at the end of the Performance Period based on the level of achievement of the Performance Goals in accordance with Exhibit I. All determinations of whether Performance Goals have been achieved, the number of PSUs earned by the Grantee, and all other matters related to this Section 3 shall be made by the Administrator in its sole discretion.
b.Promptly following completion of the Performance Period, the Administrator will review and certify in writing (i) whether, and to what extent, the Performance Goal(s) for the Performance Period have been achieved, and (ii) the number of PSUs that the Grantee shall earn, if any, subject to compliance with the requirements of Section 4 of this Agreement. Such certification shall be final, conclusive and binding on the Grantee, and on all other persons, to the maximum extent permitted by law.
4.Vesting of PSUs. The PSUs are subject to forfeiture until they vest. Except as otherwise provided herein, the PSUs will vest and become nonforfeitable, subject to (a) the Grantee’s satisfactory individual performance, as determined by the Administrator, and the achievement of the minimum threshold of performance for the payouts set forth in Exhibit I, and (b) the Grantee’s continued status as a Service Provider from the Grant Date through the vesting date as defined in Section 7 of this Agreement. The number of PSUs that vest and become payable under this Agreement shall be determined by the Administrator based on the level of achievement of the Performance Goals set forth in Exhibit I and shall be rounded to the nearest whole PSU.
5.Termination of Service Provider Status.
a.Except as otherwise expressly provided in this Agreement or in Grantee’s then-current employment agreement with the Company or any of its subsidiaries, if the Grantee’s status as a Service Provider terminates for any reason at any time before all of his or her PSUs have vested and been paid pursuant to Section 7 of this Agreement (the “Payment Period”), the Grantee’s unvested PSUs shall be automatically forfeited upon such termination of the Grantee’s Service Provider status and neither the Company nor any Affiliate shall have any further obligations to the Grantee under this Agreement. For purposes of this Section 5(a) and the extent not otherwise prohibited by Grantee’s then-current employment agreement with the Company or any of its subsidiaries, the Administrator may determine that a Grantee’s status as a Service Provider has been terminated by Grantee and all unvested PSUs shall be automatically forfeited upon such termination if Grantee resigns from Grantee’s status as a Service Provider at the Company or an affiliate and accepts a Service Provider position at the Company or an affiliate representing a material, adverse change in the Grantee’s duties, responsibilities, authority, title, status or reporting structure.


b.Notwithstanding Section 5(a) of this Agreement, if the Grantee’s Service Provider status terminates during the Performance Period or during the Payment Period as a result of the Grantee’s death, Disability, Retirement, Resignation for Good Reason, resignation to serve as a Service Provider and continued service with an Affiliate of the Company, or by the Corporation without Cause, a pro rata portion of the total PSUs granted hereunder will forfeit on such termination date, which shall be calculated by multiplying such number of total PSUs awarded or earned based upon actual achievement of the Performance Goals set forth on Exhibit I by a fraction, the numerator of which equals the number of days that the Grantee was employed during the Performance Period and the denominator of which equals the total number of days in the Performance Period and subtracting the pro rata portion from the number of total PSUs awarded or earned. Notwithstanding Section 4 of this Agreement, such number of PSUs will be payable in shares of Common Stock in accordance with Section 7 of this Agreement as if the Grantee’s Service Provider status had not been terminated.
6.Effect of a Change in Control.
a.If a Change in Control occurs during the Performance Period and the Grantee’s Service Provider status is terminated after the effective date of the Change in Control but before the end of the Performance Period as a result of the Grantee’s death, Disability, Retirement or resignation for Good Reason or by the Corporation without Cause, then a pro rata portion of the total PSUs granted hereunder will vest on the effective date of the Change in Control, which shall be calculated by multiplying (i) the sum of (A) the number of PSUs earned based upon actual achievement of the Performance Goals through the effective date of the Change in Control and (B) the number of PSUs earned during the period of time commencing on the date after the effective date of the Change of Control and ending on the date the Grantee’s Service Provider Status is terminated calculated based upon performance at the 50% level by (ii) a fraction, the numerator of which equals the number of days in the Performance Period before the date the Grantee’s Service Provider Status is terminated and the denominator of which equals Seven Hundred Thirty (730). All such PSUs shall be payable in accordance with Section 7 of this Agreement.
b.Notwithstanding anything contained in this Agreement to the contrary, if there is a Change in Control during the Payment Period that constitutes a “change in control event” as defined in Treasury Regulation Section 1.409A-3(i)(5)(i), then all outstanding PSUs shall vest based on the actual performance levels achieved at the end of the Performance Period and payment of shares of Common Stock in respect of such PSUs will be accelerated and pay out as soon as administratively feasible, but no longer than 60 days following the effective date of the Change in Control.
7.Payment of PSUs.
a.Payment in respect of the PSUs earned for the Performance Period shall be made in shares of Common Stock and shall be issued to the Grantee in three equal installments as follows (each, a “Payment Date”):
i.the first installment shall vest on March 31, 2026 and be issued and delivered by May 1, 2026;
ii.the second installment shall vest on March 1, 2027 and be issued and delivered by April 2, 2027; and
iii.the third installment shall vest on February 28, 2028 and be issued and delivered by March 31, 2028.
b.Prior to each vesting date, each installment and its corresponding issuance must be agreed by the Administrator, following a report from the Company. In this sense, during the years 2027 and 2028 and on the occasion of each vesting of shares, it will be assessed whether it is appropriate to confirm or cancel, totally or partially, the issuance corresponding to each year and, in addition, where appropriate, claim a full refund or partial, of the shares already delivered (or their amount in cash) in the event of a material restatement of the financial statements on which the Administrator based the evaluation of the degree of performance, provided that said restatement is confirmed by the external auditors and does not respond to a modification of the accounting regulations, and further provided that the aforementioned reformulation results in the delivery of a lower number of shares than the one initially provided or no delivery of shares at all.


c.Any adjustment or cancellation of all or a portion of one or more installments by the Administrator may reduce the amount of an installment (including reduction to zero), but may not change the timing of a payment, or shift the amount of a payment, to another calendar year.
d.The Company shall (i) issue and deliver to the Grantee the number of shares of Common Stock equal to the number of vested PSUs as set forth above in subsection (a), and (ii) enter the Grantee’s name on the books of the Company as the shareholder of record with respect to the shares of Common Stock delivered to the Grantee.
8.Transferability. Subject to any exceptions set forth in this Agreement or the Plan, the PSUs or the rights relating thereto may not be assigned, alienated, pledged, attached, sold or otherwise transferred or encumbered by the Grantee, except by will or the laws of descent and distribution, and upon any such transfer by will or the laws of descent and distribution, the transferee shall hold such PSUs subject to all of the terms and conditions that were applicable to the Grantee immediately prior to such transfer.
9.Rights as Shareholder.
a.The Grantee shall not have any rights of a shareholder with respect to the shares of Common Stock underlying the PSUs, including, but not limited to, voting rights and the right to receive or accrue dividends or dividend equivalents.
a.Upon and following the vesting of the PSUs and the issuance of shares, the Grantee shall be the record owner of the shares of Common Stock underlying the PSUs unless and until such shares are sold or otherwise disposed of, and as record owner shall be entitled to all rights of a shareholder of the Company (including voting and dividend rights).
10.No Right to Continued Service. Neither the Plan nor this Agreement shall confer upon the Grantee any right to be retained in any position, as an Employee, Consultant or Director of the Company. Further, nothing in the Plan or this Agreement shall be construed to limit the discretion of the Company to terminate the Grantee’s status as a Service Provider at any time, with or without cause.
11.Adjustments. If any change is made to the outstanding Common Stock or the capital structure of the Company, if required, the PSUs shall be adjusted or terminated in any manner as contemplated by Section 8 of the Plan.
12.Tax Liability and Withholding.
a.The Grantee shall be required to pay to the Company, and the Company shall have the right to deduct from any compensation paid to the Grantee pursuant to the Plan, the amount of any required withholding taxes in respect of the PSUs and to take all such other action as the Administrator deems necessary to satisfy all obligations for the payment of such withholding taxes. The Administrator may permit the Grantee to satisfy any federal, state or local tax withholding obligation by any of the following means, or by a combination of such means:
i.tendering a cash payment;
ii.authorizing the Company to withhold from any amounts that are (or may become) payable to Grantee or to withhold shares of Common Stock from the shares of Common Stock otherwise issuable or deliverable to the Grantee as a result of the vesting of the PSUs; provided, however, that no shares of Common Stock shall be withheld with a value exceeding the minimum amount of tax required to be withheld by law; or
iii.delivering to the Company previously owned and unencumbered shares of Common Stock.
b.Notwithstanding any action the Company takes with respect to any or all income tax, social insurance, payroll tax, or other tax-related withholding (“Tax-Related Items”), the ultimate liability for all Tax-Related Items is and remains the Grantee’s responsibility and the Company (i) makes no representation or undertakings regarding the treatment of any Tax-Related Items in connection with the grant, vesting or settlement of the PSUs or the subsequent sale of any shares, and (ii) does not commit to structure the PSUs to reduce or eliminate the Grantee’s liability for Tax-Related Items.


13.Definitions. The following words and phrases will have the following meanings:
a.“Affiliate” means a corporation or other entity that, directly or through one or more intermediaries, controls, is controlled by or is under common control with, the Company.
b.“Cause” means: (1) if the Grantee is a party to an employment or service agreement with the Company or its Affiliates and such agreement provides for a definition of Cause, the definition contained therein; or (2) if no such agreement exists, or if such agreement does not define Cause: (i) the commission of, or plea of guilty or no contest to, a felony or a crime involving moral turpitude or the commission of any other act involving willful malfeasance or material fiduciary breach with respect to the Company or an Affiliate; (ii) conduct that results in or is reasonably likely to result in harm to the reputation or business of the Company or any of its Affiliates; (iii) gross negligence or willful misconduct with respect to the Company or an Affiliate; or (iv) material violation of state or federal securities laws. The Administrator, in its absolute discretion, shall determine the effect of all matters and questions relating to whether a Grantee has been discharged for Cause.
c.“Good Reason” means (1) if the Grantee is a party to an employment or service agreement with the Company or its Affiliates and such agreement provides for a definition of Good Reason, the definition contained therein; or (2) if no such agreement exists or if such agreement does not define Good Reason, the occurrence of one or more of the following without the Grantee’s express written consent, which circumstances are not remedied by the Company within thirty (30) days of its receipt of a written notice from the Grantee describing the applicable circumstances (which notice must be provided by the Grantee within ninety (90) days of the Grantee’s knowledge of the applicable circumstances): (i) any material, adverse change in the Grantee’s duties, responsibilities, authority, title, status or reporting structure; or (ii) a material reduction in the Grantee’s base salary or bonus opportunity; or (iii) a geographical relocation of the Grantee’s principal office location by more than one hundred (100) miles.
d.“Retirement” means the termination of the Grantee’s employment from the Company or its Affiliates after attaining age fifty-five (55) and completing ten (10) years of continuous service with the Company or its Affiliates.
14.Compliance with Law. The issuance and transfer of shares of Common Stock in connection with the PSUs shall be subject to compliance by the Company and the Grantee with all applicable requirements of federal and state securities laws and with all applicable requirements of any stock exchange on which the Company’s shares of Common Stock may be listed. No shares of Common Stock shall be issued or transferred unless and until any then applicable requirements of state and federal laws and regulatory agencies have been fully complied with to the satisfaction of the Company and its counsel.
15.Notices. Any notice required to be delivered to the Company under this Agreement shall be in writing and addressed to the Senior Vice President – General Counsel and Corporate Secretary of the Company at the Company’s principal corporate offices. Any notice required to be delivered to the Grantee under this Agreement shall be in writing and addressed to the Grantee at the Grantee’s address as shown in the records of the Company. Either party may designate another address in writing (or by such other method approved by the Company) from time to time, including without limitation electronic addresses and electronic methods of communication.
16.Governing Law; Waiver of Jury Trial. This Agreement will be construed and interpreted in accordance with the laws of the State of New York without regard to conflict of law principles. The Company and Grantee hereby waive, to the fullest extent permitted by applicable law, any right they may have to a trial by jury in any legal proceeding directly or indirectly arising out of or relating to this Agreement or the transactions contemplated hereunder (whether based on contract, tort or any other theory).


17.Interpretation. Any dispute regarding the interpretation of this Agreement shall be submitted by the Grantee or the Company to the Administrator for review. The resolution of such dispute by the Administrator shall be final and binding on the Grantee and the Company.
18.PSUs Subject to Plan. This Agreement is subject to the Plan as approved by the Company’s shareholders. The terms and provisions of the Plan as it may be amended from time to time are hereby incorporated herein by reference. In the event of a conflict between any term or provision contained herein and a term or provision of the Plan, the applicable terms and provisions of the Plan will govern and prevail.
19.Successors and Assigns; No Third-Party Beneficiaries. The Company may assign any of its rights under this Agreement. This Agreement will be binding upon and inure to the benefit of the successors and assigns of the Company. Subject to the restrictions on transfer set forth herein, this Agreement will be binding upon the Grantee and the Grantee’s beneficiaries, executors, administrators and the person(s) to whom the PSUs may be transferred by will or the laws of descent or distribution. Nothing in this Agreement, expressed or implied, is intended to confer on any person other than the Company and the Participant, and their respective heirs, successors, legal representatives and permitted assigns, any rights, remedies, obligations or liabilities under or by reason of this Agreement.
20.Severability. The invalidity or unenforceability of any provision of the Plan or this Agreement shall not affect the validity or enforceability of any other provision of the Plan or this Agreement, and each provision of the Plan and this Agreement shall be severable and enforceable to the extent permitted by law.
21.Discretionary Nature of Plan. The Plan is discretionary and may be amended, cancelled or terminated by the Company at any time, in its discretion. The grant of the PSUs in this Agreement does not create any contractual right or other right to receive any PSUs or other Awards in the future. Future Awards, if any, will be at the sole discretion of the Company. Any amendment, modification, or termination of the Plan shall not constitute a change or impairment of the terms and conditions of the Grantee’s employment with the Company.
22.Amendment. The Administrator has the right to amend, alter, suspend, discontinue or cancel the PSUs, prospectively or retroactively; provided, that, no such amendment shall adversely affect the Grantee’s material rights under this Agreement without the Grantee’s consent.
23.Section 409A. This Agreement is intended to comply with Section 409A or an exemption thereunder and shall be construed and interpreted in a manner that is consistent with the requirements for avoiding additional taxes or penalties under Section 409A. Notwithstanding the foregoing, the Company makes no representations that the payments and benefits provided under this Agreement comply with Section 409A and in no event shall the Company be liable for all or any portion of any taxes, penalties, interest or other expenses that may be incurred by the Grantee on account of non-compliance with Section 409A.
24.No Impact on Other Benefits. The value of the Grantee’s PSUs is not part of his or her normal or expected compensation for purposes of calculating any severance, retirement, welfare, insurance or similar employee benefit.
25.Counterparts. This Agreement may be executed in counterparts, each of which shall be deemed an original but all of which together will constitute one and the same instrument. Counterpart signature pages to this Agreement transmitted by facsimile transmission, by electronic mail in portable document format (.pdf), or by any other electronic means intended to preserve the original graphic and pictorial appearance of a document, will have the same effect as physical delivery of the paper document bearing an original signature.
26.Acceptance. The Grantee hereby acknowledges receipt of a copy of the Plan and this Agreement. The Grantee has read and understands the terms and provisions thereof, and accepts the PSUs subject to all of the terms and conditions of the Plan and this Agreement. The Grantee acknowledges that there may be adverse tax consequences upon the vesting or settlement of the PSUs or disposition of the underlying shares and that the Grantee has been advised to consult a tax advisor prior to such vesting, settlement or disposition.

[Signature Page Follows]


IN WITNESS WHEREOF, the parties hereto have executed this Agreement as of the date first above written.
AVANGRID, INC. PARTICIPANT
By: ______________________________________   By: ______________________________________
Print Name:   Print Name:
Title: Title:


Exhibit I
1.PERFORMANCE GOALS
The vesting of the PSUs is tied to achievement of the following strategic goals (the “Performance Goals”) during the Performance Period and satisfactory individual performance:
a.Adjusted Net Income
b.Total Shareholder Return (TSR)
c.Investment Grade Credit Ratings
d.Sustainability
Calculations methodology, weighting, and levels of achievement of each of the Performance Goals to which the Award is tied are outlined below.
imagea.jpg
2.OPERATION OF THE PLAN
The number of shares of Common Stock to be delivered to Grantee shall be the result of multiplying Grantee’s number of Maximum Award by the value of the weighted ratio of achievement of each of the Performance Goals, in accordance with the formula set forth below.
image1a.jpg

EX-10.49 5 agr-ex1049x2023.htm EX-10.49 Document

Exhibit 10.49
SECOND AMENDMENT TO GUARANTY
THIS SECOND AMENDMENT TO GUARANTY (this “Amendment”), effective as of October 24, 2023 (the “Amendment Effective Date”), is entered into by and among Avangrid, Inc., a New York Corporation (the “Guarantor”) and U.S. Bank Trust Company, N.A., in its capacity as Collateral Agent (the “Guaranteed Party”).
W I T N E S S E T H
WHEREAS, reference is made herein to that certain Equity Contribution Agreement, dated as of September 15, 2021 (as amended, restated, amended and restated, supplemented or otherwise modified prior to the date hereof, the “Equity Contribution Agreement”), among VINEYARD WIND 1 LLC, a Delaware limited liability company (the “Borrower”), BANCO SANTANDER, S.A., NEW YORK BRANCH, as Administrative Agent (the “Administrative Agent”), AVANGRID VINEYARD WIND, LLC (“Avangrid Member”), CI-II ALICE HOLDING LLC (“CI II Member”), CI III ALICE HOLDING LLC (“CI III Member” and together with Avangrid Member and CI II Member, the “Members”), VINEYARD WIND CI PARTNERS 1 LLC (“CIP Partner”), VINEYARD WIND SPONSOR PARTNERS 1 LLC (“Sponsor Partner”), VINEYARD WIND TE PARTNERS 1 LLC (“TE Partners”), VINEYARD WIND 1 PLEDGOR LLC (“Construction Pledgor”), and the Guaranteed Party (together with the Borrower, the Administrative Agent, the Members, the CIP Partner, the Sponsor Partner, TE Partners, the Construction Pledgor and the Collateral Agent, the “ECA Parties” and each, an “ECA Party”)
WHEREAS, reference is made to that certain Guaranty, dated as of September 15, 2021 (as amended by that certain First Amendment to Guaranty, dated as of February 24, 2023, the “Guaranty”), made by the Guarantor in favor of the Guaranteed Party;
WHEREAS, concurrently with the execution herewith, the ECA Parties will enter into and execute that certain Second Amendment to Equity Contribution Agreement (the “ECA Amendment”), pursuant to which the Equity Contribution Amount (as defined therein) shall be increased; and
WHEREAS, in connection with the proposed amendments to the ECA Amendment, the Guarantor and the Guaranteed Party signatory hereto have agreed to make certain amendments to the Guaranty pursuant to and in accordance with Section 8 of the Guaranty.
NOW, THEREFORE, in consideration of the premises contained herein and for other good and valuable consideration, the receipt and sufficiency of which are hereby acknowledged, the parties hereto, intending to be legally bound hereby, agree as follows:
a.Definitions.
Unless otherwise defined in this Amendment, each capitalized term used in this Amendment has the meaning assigned to such term in the Guaranty or the Equity Contribution Agreement, as applicable.
a.Amendments to the Guaranty. Effective as of the Amendment Effective Date, each of the Guarantor and the Guaranteed Party hereby agree to amend the Guaranty as follows:
i.Section 1(B) of the Guaranty is hereby amended by replacing “eight hundred fifty five million twenty eight thousand four hundred twenty and 49/100 U.S. Dollars ($855,028,420.49) (the “Maximum Guaranteed Amount”)” with “Eight Hundred Eighty Six Million Five Hundred Fifty Five Thousand Nine Hundred Eleven and 74/100 United States Dollars ($886,555,911.74) (the “Maximum Guaranteed Amount”)”.
b.Effectiveness of Amendment. This Amendment shall become effective on the Amendment Effective Date, which shall be the date on which the Guaranteed Party receives an executed counterparty of this Amendment executed by the Guarantor and the Guaranteed Party.
c.Governing Law; Submission to Jurisdiction; Waiver of Right to Trial by Jury. This Amendment shall be governed by and construed in accordance with the law of the State of New York without giving effect to principles of conflicts of laws. The other provisions of Sections 12 and 16 of the Guaranty are hereby incorporated by reference in this Amendment as if fully set forth in this Amendment mutatis mutandis.
d.Successors and Assigns. This Amendment is binding upon and shall inure to the benefit of the parties hereto and their respective successors and assigns permitted by the Guaranty.


e.Counterparts. This Amendment may be executed in one or more counterparts, each of which when executed shall constitute one and the same instrument. Delivery of a signed signature page to this Amendment by facsimile transmission or in portable document format (.pdf) shall be effective as, and shall constitute physical delivery of, a signed original counterpart of this Amendment.
f.Severability. If one or more provisions of this Amendment shall for any reason or to any extent be determined invalid or unenforceable, all other provisions shall nevertheless remain in full force and effect.
(Signature Pages Follow)

IN WITNESS WHEREOF, the parties hereto have caused this Amendment to be duly executed by their respective authorized officers as of the day and year first above written.
AVANGRID, INC., a New York corporation
By: /s/ Justin Lagasse Name: Justin Lagasse Title: Authorized Representative
By: /s/ Alvaro Ortega Name: Alvaro Ortega Title: Authorized Representative


U.S. Bank Trust Company, N.A., as Collateral Agent By: /s/ Anjum Sarwar
Name: Anjum Sarwar Title: Authorized Signer


EX-10.50 6 agr-ex1050x2023.htm EX-10.50 Document

Exhibit 10.50
GUARANTY
THIS GUARANTY, dated as of December 13, 2023 (this “Guaranty”), is issued by Avangrid, Inc., a New York corporation (“Guarantor”) in favor of (x) Bank of America, N.A. (together with its successors and permitted assigns, “BofA”), JPMorgan Chase Bank, N.A. (together with its successors and permitted assigns, “JPM”) and Wells Fargo Bank, N.A. (together with its successors and permitted assigns, “Wells”, and together with BofA and JPM, collectively, the “Class A Equity Investors”, and individually, a “Class A Equity Investor”) and (y) solely with respect to the PSA Obligations (as defined below), Vineyard Wind TE Partners 1 LLC, a Delaware limited liability company (the “Company” and together with the Class A Equity Investors, the “Guaranteed Parties” and each individually a “Guaranteed Party”).
RECITALS
A.Avangrid Vineyard Wind, LLC, a Delaware limited liability company (“Avangrid”), is a wholly owned indirect subsidiary of Guarantor.
B.Avangrid and Vineyard Wind CI Partners 1 LLC, a Delaware limited liability company, jointly own Vineyard Wind Sponsor Partners 1 LLC, a Delaware limited liability company (together with its successors and permitted assigns, the “Class B Equity Investor”) and Vineyard Wind 1 Pledgor LLC, a Delaware limited liability company (together with its successors and permitted assigns, “Seller” and together with the Class B Equity Investor, the “Obligors” and each individually an “Obligor”).
C.The Class B Equity Investor and each Class A Equity Investor are party to (i) that certain Equity Capital Contribution Agreement, dated as of October 24, 2023 (as amended, amended and restated, supplemented or otherwise modified from time to time, the “ECCA”) and (ii) that certain Fee Letter, dated as of October 24, 2023 (as amended, amended and restated, supplemented or otherwise modified from time to time, the “Fee Letter”).
D.Pursuant to the ECCA, the Class B Equity Investor and the Class A Equity Investors (and, in the case of BofA, BAL Investment & Advisory, LLC) have entered into that certain Second Amended and Restated Limited Liability Company Agreement of the Company, dated as of the date hereof (as amended, amended and restated, supplemented or otherwise modified from time to time, the “LLC Agreement”).
E.The Company and Seller are a party to that certain Purchase and Sale Agreement, dated as of October 24, 2023 (as amended, amended and restated, supplemented or otherwise modified from time to time, the “PSA” and, together with the ECCA, the Fee Letter and the LLC Agreement, the “Guaranteed Agreements”).
F.This Guaranty is delivered by the Guarantor (a) in satisfaction of the condition precedent to the Initial Capital Contribution Date as set forth in Section 6.1(c) of the ECCA and (b) in satisfaction of the condition precedent to the “Closing Date” (as defined in the PSA) as set forth in Section 5.2(j)(v) of the PSA.
AGREEMENT
1.Definitions. Unless the context hereof shall otherwise require, capitalized terms used in this Guaranty, including in the foregoing recitals, and not otherwise defined below or elsewhere in this Guaranty shall have the respective meanings specified in Section 1.1 of the ECCA. The general rules of interpretation of Section 1.2 of the ECCA apply, mutatis mutandis, to this Guaranty including the terms used herein.
“Avangrid” has the meaning ascribed to such term in the recitals.
“BofA” has the meaning ascribed to such term in the introductory paragraph.
“Company” has the meaning ascribed to such term in the introductory paragraph.
“Completion Covenant” has the meaning ascribed to such term in the PSA.
“Completion Covenant Cap” has the meaning ascribed to such term in the PSA.
“ECCA” has the meaning ascribed to such term in the recitals.


“ECCA/LLCA Obligations” means all payment obligations of the Class B Equity Investor in accordance with (and subject to the limitations in) Article VIII of the LLC Agreement and in accordance with (and subject to the limitations in) Article VIII of the ECCA.
“Fee Letter” has the meaning ascribed to such term in the recitals.
“Fee Letter Obligations” means all payment obligations of the Class B Equity Investor in accordance with (and subject to the limitations in) the Fee Letter.
“Guaranteed Agreements” has the meaning ascribed to such term in the recitals.
“Guaranteed Party” has the meaning ascribed to such term in the introductory paragraph.
“Guaranty” has the meaning ascribed to such term in the introductory paragraph.
“Guaranty Cap” means: (x) prior to the exercise of the “Class B Control Option” (as defined in the LLC Agreement), an amount equal to 50% of the Maximum Liability and (y) from and after the exercise of the “Class B Control Option” (as defined in the LLC Agreement), an amount equal to 50.000005% of the Maximum Liability.
“Investment Grade Rating” has the meaning ascribed to such term in Section 8.
“JPM” has the meaning ascribed to such term in the introductory paragraph.
“LLC Agreement” has the meaning ascribed to such term in the recitals.
“Maximum Liability” means:
(x)    until the Final Capital Contribution Date:
(i)with respect to liability for any breach of the Completion Covenant, an amount equal to (A) the Completion Covenant Cap less (B) amounts actually received, directly or indirectly (including as a distribution by the Company), by any Class A Equity Investor Indemnitee or any “Class A Indemnitee” (as defined in the LLC Agreement) with respect to ECCA/LLCA Obligations (other than any ECCA/LLCA Obligations that constitute Fee Letter Obligations) and PSA Obligations (including, for the avoidance of doubt, any cash escrow distribution to the Class A Equity Investors from the Tax Equity Escrow Accounts (as defined in the Investor Consent (ECCA)) following the date that such Investor Consent (ECCA) is entered into) less (C) an amount equal to the aggregate liability limit set forth in each guaranty entered into by Guarantor pursuant to Section 22 hereof; and
(ii)with respect to liability for any other ECCA/LLCA Obligations, Fee Letter Obligations and PSA Obligations (other than liability for any breach of the Completion Covenant), an amount equal to (A) 100% of the sum of (1) the aggregate amount of the Capital Contributions actually contributed by the Guaranteed Parties under the ECCA and the LLC Agreement plus (2) the aggregate amount of the “Fees” (as defined in the Fee Letter) that have actually accrued under the Fee Letter less (B) amounts actually received, directly or indirectly (including as a distribution by the Company), by any Class A Equity Investor Indemnitee or any “Class A Indemnitee” (as defined in the LLC Agreement) with respect to ECCA/LLCA Obligations, PSA Obligations and Fee Letter Obligations (including, for the avoidance of doubt, any cash escrow distribution to the Class A Equity Investors from the Tax Equity Escrow Accounts (as defined in the Investor Consent (ECCA)) following the date that such Investor Consent (ECCA) is entered into) less (C) an amount equal to the aggregate liability limit set forth in each guaranty entered into by Guarantor pursuant to Section 22 hereof;
(y)    from the Final Capital Contribution Date until the Step Down Date, an amount equal to (i) 100% of the aggregate amount of the Capital Contributions actually contributed by the Guaranteed Parties under the ECCA and the LLC Agreement less (ii) amounts actually received, directly or indirectly (including as a distribution by the Company), by any Class A Equity Investor Indemnitee or any “Class A Indemnitee” (as defined in the LLC Agreement) with respect to ECCA/LLCA Obligations (other than any ECCA/LLCA Obligations that constitute Fee Letter Obligations) and PSA Obligations less (iii) an amount equal to the aggregate liability limit set forth in each guaranty entered into by Guarantor pursuant to Section 22 hereof; and


(z)    from and after the Step Down Date, an amount equal to (i) 25% of the aggregate amount of the Capital Contributions actually contributed by the Guaranteed Parties under the ECCA and the LLC Agreement less (ii) amounts actually received, directly or indirectly (including as a distribution by the Company), by any Class A Equity Investor Indemnitee or any “Class A Indemnitee” (as defined in the LLC Agreement) with respect to ECCA/LLCA Obligations (other than any ECCA/LLCA Obligations that constitute Fee Letter Obligations) and PSA Obligations less (iii) an amount equal to the aggregate liability limit set forth in each guaranty entered into by Guarantor pursuant to Section 22 hereof.
For the avoidance of doubt, the Class A Equity Investors and the Class B Equity Investors shall not be deemed to be Affiliates.
“Moody’s” has the meaning ascribed to such term in Section 8.
“Obligations” means: (x) prior to any foreclosure upon (or transfer in lieu of foreclosure) any of the Obligors by a Secured Party (as defined in the Construction Loan Agreement) or other secured party pursuant to an Investor Consent, collectively, the ECCA/LLCA Obligations and the PSA Obligations and (x) after any such foreclosure or transfer, the PSA Obligations; provided, however, that Guarantor shall remain liable for any of the ECCA/LLCA Obligations arising in respect of action, failure to take an action or other events, in each case, arising prior to any such foreclosure or transfer in lieu of foreclosure.
“Obligors” has the meaning ascribed to such term in the recitals.
“PSA” has the meaning ascribed to such term in the recitals.
“PSA Obligations” means all payment obligations of the Seller in accordance with (and subject to the limitations in) Article 7 of the PSA.
“Qualified Replacement Sponsor Guaranty” has the meaning ascribed to such term in the LLC Agreement.
“S&P” has the meaning ascribed to such term in Section 8.
“Seller” has the meaning ascribed to such term in the recitals.
“Step Down Date” means the date that is 60 days after the expiration of the statute of limitations on any IRS audit of the Company tax year in which the last Turbine included in the Project is Placed in Service.
“Termination Date” has the meaning ascribed to such term in Section 5.
“Wells” has the meaning ascribed to such term in the introductory paragraph.
2.Guaranty.
A.Guaranty of Obligations Under the Guaranteed Agreements. For value received, Guarantor hereby absolutely, unconditionally and irrevocably, subject to the express terms hereof, guarantees, as primary obligor and not merely as a surety (i) in favor of the Class A Equity Investors, the payment when due of the Guarantor’s pro rata share of all ECCA/LLCA Obligations and Fee Letter Obligations and (ii) in favor of the Guaranteed Parties, the payment when due of the Guarantor’s pro rata share of all PSA Obligations. This Guaranty is one of payment and not of collection and shall apply regardless of whether recovery of all such Obligations may be or become discharged or uncollectible in any bankruptcy, insolvency or other similar proceeding, or otherwise unenforceable.
B.Maximum Guaranteed Amount.
(i)Notwithstanding anything to the contrary herein, Guarantor’s aggregate obligation to the Guaranteed Parties hereunder is limited to the Guaranty Cap (it being understood for purposes of calculating the Guaranty Cap hereunder that any payment by Guarantor either directly or indirectly to any Guaranteed Party, pursuant to a demand made upon Guarantor by any Guaranteed Party or otherwise made by Guarantor pursuant to its obligations under this Guaranty including any indemnification obligations, shall reduce Guarantor’s maximum aggregate liability hereunder on a dollar-for-dollar basis), and shall not either individually or in the aggregate be greater or different in character or extent than the obligations of the applicable Obligors under the terms of the Guaranteed Agreements. The Guarantor and the Guaranteed Parties each acknowledge and agree that (x) with respect to the Obligations, the obligations of Guarantor hereunder are several and not joint with the obligations of each other Sponsor Guarantor under the Sponsor Guaranty to which it is a party and (y) amounts payable by Guarantor under this Guaranty shall be without duplication of amounts paid by any other Sponsor Guarantor under any Sponsor Guaranty.


(ii)Section 8.2(d) (No Consequential or Punitive Damages) of the ECCA is hereby incorporated, mutatis mutandis, into this Guaranty.
3.Payment; Currency. All sums payable by Guarantor hereunder shall be made in freely transferable and immediately available funds and shall be made in the currency in which the Obligations were due. If an Obligor fails to pay any Obligation when due, the Guarantor will pay its pro rata share of that Obligation directly to the applicable Guaranteed Parties within twelve (12) days after written notice to Guarantor by such Guaranteed Parties; provided, that, no such notice or other demand shall be required in the event that such Guaranteed Parties are restrained from making such demand pursuant to any applicable bankruptcy, insolvency or other laws affecting creditors’ rights generally. The written notice (if any) shall provide the amount of the Obligation.
4.Waiver of Defenses. Except as set forth above, Guarantor hereby waives notice of acceptance of this Guaranty and of the Obligations and any action taken with regard thereto, and waives presentment, demand for payment, protest, notice of dishonor or non-payment of the Obligations, suit, or the taking of and failing to take other action by the Guaranteed Parties against the applicable Obligor, Guarantor or others and waives any defense of a surety, waives any defense under or based on any change in ownership of any Obligor or any change in the Guarantor’s relationship to any Obligor and (except as expressly set forth herein) any other circumstances which might otherwise constitute a legal or equitable discharge or defense of a guarantor, other than payment in full of the Obligations. Without limitation, the Guaranteed Parties may at any time and from time to time without notice to or consent of Guarantor and without impairing or releasing the obligations of Guarantor hereunder: (a) together with the applicable Obligor, make any change to the terms of the Obligations; (b) take or fail to take any action of any kind in respect of any security for the Obligations; (c) exercise or refrain from exercising any rights against the applicable Obligor or others in respect of the Obligations or (d) compromise or subordinate the Obligations, including any security therefor. Notwithstanding the foregoing, Guarantor does not waive the right to assert that amounts are not due and payable under the Guaranteed Agreements in accordance with their respective terms and Guarantor shall be entitled to assert rights, setoffs, counterclaims and other defenses which the applicable Obligor may have under the terms of the Guaranteed Agreements to performance of any of the Obligations, other than defenses based upon lack of authority of the applicable Obligor to enter into and/or perform its obligations under the Guaranteed Agreements or any insolvency, bankruptcy, reorganization, arrangement, composition, liquidation, dissolution or similar proceeding with respect to the applicable Obligor.


5.Term. This Guaranty shall continue in full force and effect until the earliest of the following (such date, the “Termination Date”): (a) provided that the Guarantor’s pro rata share of all Obligations then due and payable have been paid in full in Dollars at such time, the latest to occur of the termination of the LLC Agreement, the termination of the ECCA, the termination of the Fee Letter or the termination of the PSA in accordance with its respective terms, (b) the occurrence of the Flip Date and (c) the date that (i) this Guaranty is replaced by (A) a Qualified Replacement Sponsor Guaranty in connection with a Transfer in accordance with Section 10.1(c)(ii), Section 10.1(e) or Section 10.1(f) of the LLC Agreement (but only to the extent that such Qualified Replacement Sponsor Guaranty guarantees all of the Guarantor’s pro rata share of the ECCA/LLCA Obligations and Fee Letter Obligations, including those arising with respect to matters that predate the applicable Transfer) and (B) if the Final Capital Contribution Date has occurred and the Person providing the Qualified Replacement Sponsor Guaranty in clause (c)(i)(A) does not have a senior unsecured debt rating of at least “BBB” from S&P or “Baa2” from Moody’s, an Acceptable Letter of Credit with a stated amount at least equal to such replacement guarantor’s pro rata share of the then-applicable Specified Casualty Event Contribution Cap and (ii) solely to the extent that (X) the “Final Installment Date” (as defined in the PSA) has not occurred and (Y) the Seller’s liability under Section 7.2(b) of the PSA has not been reduced to zero, (A) an Acceptable Guaranty (but only to the extent that such Acceptable Guaranty guarantees all of the Guarantor’s pro rata share of the PSA Obligations, including those arising with respect to matters that predate the Termination Date) which, for the avoidance of doubt but subject to the requirements set forth in the PSA, may be the same instrument as the Qualified Replacement Sponsor Guaranty referred to in clause (c)(i) and (B) if the Person providing the Acceptable Guaranty in clause (c)(ii)(A) does not have a credit rating of at least the “Required Rating” (as defined in the PSA), an Acceptable Letter of Credit with a stated amount equal to the “Maximum Sponsor Guarantor Exposure” (as defined in the PSA) of the Guarantor has been provided by or on behalf of the Seller to the Guaranteed Parties, which such Acceptable Guaranty and (if required) Acceptable Letter of Credit referred to in this clause (c)(ii) shall be limited to a guaranty of the Seller’s liability for any breach of the Completion Covenant; provided that notwithstanding anything to the contrary herein or in any Transaction Document, the Guarantor’s liability in respect of its pro rata share of the Fee Letter Obligations and the PSA Obligations shall terminate on the earlier of the Final Capital Contribution Date and the Termination Date. Subject to the next sentence and the proviso to this sentence, upon termination of this Guaranty pursuant to this Section 5, the Guarantor shall have no further liability hereunder; provided, however, that in the event any Guaranteed Party shall have given notice to the Guarantor of any claim hereunder prior to the date on which this Guaranty would otherwise terminate under this Section 5, this Guaranty shall remain in effect until the satisfaction of such claim for purposes of such claim. Guarantor further agrees that this Guaranty shall continue to be effective or be reinstated, as the case may be, if at any time payment, or any part thereof, of any Obligation is rescinded or must otherwise be restored or returned due to reorganization, bankruptcy or insolvency laws or otherwise, all as though such payment had not been made.
6.Subrogation. Until the later of (x) the date when all obligations under this Guaranty and the Obligations are indefeasibly performed in full and (y) the “Termination Date”, as such term is defined in each applicable Loan Agreement, has occurred pursuant to each Loan Agreement, Guarantor hereby waives all rights of subrogation, reimbursement, contribution and indemnity from the applicable Obligors with respect to this Guaranty and any collateral held therefor, and Guarantor hereby subordinates all rights under any debts owing from the applicable Obligors to Guarantor, whether now existing or hereafter arising, to the prior payment of the Obligations. This Section 6 shall expressly survive termination of this Guaranty until the later of (x) the date when all Obligations are fully and finally paid and discharged, expired or terminated and (y) the “Termination Date”, as such term is defined in each applicable Loan Agreement, has occurred pursuant to each Loan Agreement.
7.Expenses. Whether or not legal action is instituted, Guarantor agrees to reimburse the Guaranteed Parties on written demand for all reasonable attorneys’ fees and all other reasonable costs and expenses incurred by the Guaranteed Parties in enforcing their rights under this Guaranty. Notwithstanding the foregoing, the Guarantor shall have no obligation to pay any such costs or expenses if, in any action or proceeding brought by the Guaranteed Parties giving rise to a demand for payment of such costs or expenses, it is finally adjudicated that the Guarantor is not liable to make payment under Section 3 hereof.
8.Assignment. Guarantor may not assign its rights or delegate its obligations under this Guaranty in whole or part without written consent of the Guaranteed Parties, provided, however, that Guarantor may assign its rights and delegate its obligations under this Guaranty without the consent of the Guaranteed Parties if such assignment and delegation is pursuant to the assignment and delegation of all of Guarantor’s rights and obligations hereunder, in whatever form Guarantor determines may be appropriate, to a partnership, limited liability company, corporation, trust or other organization in whatever form that succeeds to all or substantially all of Guarantor’s assets and business and that assumes such obligations by contract, operation of law or otherwise, provided, such entity has an Investment Grade Rating by Moody’s Investors Service, Inc. (“Moody’s”) and Standard & Poor’s Ratings Group, a division of McGraw-Hill, Inc. (“S&P”). For purposes of this Section 8, “Investment Grade Rating” means a minimum credit rating for senior unsecured debt or corporate credit rating of at least BBB- or better by S&P and at least Baa3 or better by Moody’s. Upon any such delegation and assumption of all of Guarantor’s rights and obligations hereunder (including obligations that arose before such assumption) and, if required, the written consent of the Guaranteed Parties (which consent shall not be unreasonably withheld, conditioned or delayed), Guarantor shall be relieved of and fully discharged from such obligations hereunder, whether such obligations arose before or after such delegation and assumption. The Guaranteed Parties may not assign their rights hereunder except in connection with, and together with, a permitted assignment of the applicable Guaranteed Agreements in accordance with the terms thereof. This Guaranty shall be binding upon Guarantor and its successors and permitted assigns and shall inure to the benefit of, and shall be enforceable by, the Guaranteed Parties and each of their successors and permitted assigns.


9.Non-Waiver. The failure of the Guaranteed Parties to enforce any provisions of this Guaranty at any time or for any period of time shall not be construed to be a waiver of any such provision or the right thereafter to enforce same. All remedies of the Guaranteed Parties under this Guaranty shall be cumulative and shall be in addition to any other remedy now or hereafter existing at law or in equity. The terms and provisions hereof may not be waived, altered, modified or amended except in a writing executed by Guarantor and the Guaranteed Parties.
10.Entire Agreement. This Guaranty and the Guaranteed Agreements are the entire and only agreements between Guarantor and the Guaranteed Parties with respect to the guaranty of the Obligations of the Obligors by Guarantor. All agreements or undertakings heretofore or contemporaneously made, which are not set forth herein, are superseded hereby.
11.Notice. Any demand for payment, notice, request, instruction, correspondence or other document to be given hereunder by Guarantor or by the Guaranteed Parties shall be in writing and shall be deemed received (a) if given personally, when received, (b) if mailed by certified mail (postage prepaid and return receipt requested), five days after deposit in the U.S. mails, (c) if given by facsimile, when transmitted with confirmed transmission, (d) if given by email, upon transmission thereof or (e) if given via overnight express courier service, when received or personally delivered, in each case with charges prepaid and addressed as follows (or such other address as either Guarantor or the Guaranteed Parties shall specify in a notice delivered to the other in accordance with this Section 11):
If to Guarantor:
Avangrid, Inc.
2701 NW Vaughn St., Suite 300
Portland, Oregon 97210
If to the Guaranteed Parties:
Bank of America, N.A.
555 California Street, 6th Floor
CA5-705-06-34
San Francisco, CA 94104
with an additional copy to:
Bank of America, N.A.
One Financial Plaza, 6th Floor,
RI1-537-06-05
Providence, RI 02903
Attn: BAL Renewable Energy Finance Portfolio Manager


and
JPMorgan Chase Bank, N.A. 10 South Dearborn Street, 7th Floor
Chicago, IL 60603-2300
Attention: Head of Energy Asset Management
Reference: Vineyard Wind
with a copy to:
JPMorgan Chase Bank, N.A.
480 Washington Blvd, Floor 23
Jersey City, NJ, 07310-2053, United States
and
Wells Fargo Bank, N.A. c/o Wells Fargo Commercial Capital
Attention: Renewable Energy Portfolio Management
MAC A0101-093
420 Montgomery Street, 9th Floor
San Francisco, CA 94104
With a copy to (which shall not constitute notice):
Wells Fargo Legal Group
Capital Markets Counsel
MAC J0161-245
150 E 42nd Street, 24th Floor
New York, NY 10017
If to the Company:
Vineyard Wind TE Partners 1 LLC
75 Arlington Street, 7th Floor,
Boston, MA 02116
12.Counterparts. This Guaranty may be executed in counterparts, each of which when executed and delivered shall constitute one and the same instrument. Delivery of a signed signature page to this Guaranty by facsimile transmission or in portable document format (.pdf) shall be effective as, and shall constitute physical delivery of, a signed original counterpart of this Guaranty.
13.Governing Law; Jurisdiction. This Guaranty shall be governed by and construed in accordance with the laws of the state of New York without giving effect to principles of conflicts of law. Guarantor and the Guaranteed Parties agree to the non-exclusive jurisdiction of the courts of the State of New York and of any federal district court located therein over any disputes arising or relating to this Guaranty.
14.Further Assurances. Guarantor shall cause to be promptly and duly taken, executed and acknowledged and delivered, such further documents and instruments as the Guaranteed Parties may from time to time reasonably request in order to carry out the intent and purposes of this Guaranty.


15.Limitation on Liability. Except as specifically provided in this Guaranty, the Guaranteed Parties shall have no claim, remedy or right to proceed against Guarantor or against any past, present or future stockholder, partner, member, director or officer thereof for the payment of any of the Obligations, as the case may be, or any claim arising out of any agreement, certificate, representation, covenant or warranty made by any Obligor in the Guaranteed Agreements.
16.Representations and Warranties. The Guarantor represents and warrants to the Guaranteed Parties as of each Capital Contribution Date and each “Installment Date” (as defined in the PSA) that:
(a)it is a corporation duly organized and validly existing under the laws of its jurisdiction of incorporation and has the corporate power and authority to execute, deliver and carry out the terms and provisions of this Guaranty;
(b)no authorization, approval, consent or order of, or registration or filing with, any court or other governmental body having jurisdiction over Guarantor is required on the part of Guarantor for the execution and delivery of this Guaranty, other than those which have been obtained on or prior to the date hereof and remain in full force and effect;
(c)this Guaranty, when executed and delivered by the Guarantor, will constitute a valid and legally binding agreement of the Guarantor, enforceable against the Guarantor in accordance with the terms hereof, except as such enforceability may be limited by applicable bankruptcy, insolvency, moratorium, reorganization or other similar laws affecting the enforcement of creditors’ rights and subject to general equitable principles;
(d)the execution and delivery of this Guaranty by Guarantor and the performance of its obligations hereunder will not result in a violation of any applicable Laws applicable to Guarantor;
(e)there are no pending or, to Guarantor’s knowledge, threatened actions or proceedings of any kind, including actions or proceedings of or before any Governmental Authority, to which Guarantor is a party or is subject, or by which it or any of its properties is bound that, if adversely determined to or against Guarantor, could reasonably be expected to have a material and adverse effect on Guarantor’s ability to perform its obligations under this Guaranty; and
(f)each of the financial statements of the Guarantor delivered pursuant to Sections 6.1(k)(ii) and 6.3(cc)(ii) of the ECCA, as applicable, presents fairly and accurately, in all material respects, the Assets, liabilities and member(s)’ equity of the Guarantor as of the date of such financial statements in accordance with the assumptions set forth therein, and has been prepared in accordance with the Accounting Standard, subject, in the case of any unaudited financial statements to normal financial statement period-end adjustments in the ordinary course of business and the absence of footnotes. Other than as set forth in the financial statements of the Guarantor delivered pursuant to Sections 6.1(k)(ii) and 6.3(cc)(ii) of the ECCA, as applicable, as of the date of such financial statements the Guarantor does not have any material liabilities required to be reported in accordance with the Accounting Standard which would be necessary for its balance sheet to meet the standard in the preceding sentence.
17.Financial Statements. Guarantor shall deliver, or cause to be delivered, to each of the Class A Equity Investors, (i) annually, within 150 days after the end of each Fiscal Year (beginning with the first such annual reporting date occurring after the date hereof), consolidated financial statements and reports of Guarantor, audited by an Accounting Firm, prepared in accordance with the Accounting Standard effective as of the end of the immediately-preceding year; provided that, if Guarantor files an annual report on Form 10-K (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable annual audited financial statements shall be deemed to have been delivered to the Class A Equity Investors for purposes of this clause (i) and (ii) quarterly, within 90 days after the end of the first, second and third quarters of each Fiscal Year (beginning with the first such quarterly reporting date occurring after the date hereof), unaudited consolidated financial statements of Guarantor for such quarter prepared in accordance with the Accounting Standard, subject to normal year-end audit adjustments and the absence of footnotes; provided that, if Guarantor files a quarterly report on Form 10-Q (or any similar or successor forms) with the United States Securities and Exchange Commission (or any successor entity), the applicable quarterly unaudited financial statements shall be deemed to have been delivered to the Class A Equity Investors for purposes of this clause (ii).


18.Waiver of Jury Trial. EACH OF THE PARTIES HERETO IRREVOCABLY WAIVES ITS RIGHT TO A TRIAL BY JURY IN ANY PROCEEDING RELATING TO OR ARISING OUT OF THIS GUARANTY.
19.Severability. If one or more provisions of this Guaranty shall for any reason or to any extent be determined invalid or unenforceable, all other provisions shall nevertheless remain in full force and effect.
20.Third Party Beneficiaries. The obligations of the Guarantor contained herein are undertaken solely and exclusively for the benefit of Guaranteed Parties and their permitted successors and assigns, and no other Person shall have any standing to enforce such obligations or be deemed to be beneficiaries of such obligations.
21.No Marshalling. Except to the extent required by applicable Law, no Guaranteed Party will be required to marshal any collateral securing, or any guarantees of, the Obligations, or to resort to any item of collateral or any guarantee in any particular order, and the Guaranteed Parties’ rights with respect to any collateral and guarantees will be cumulative and in addition to all other rights, however existing or arising. To the extent permitted by applicable Law, the Guarantor irrevocably waives, and agrees that it will not invoke or assert, any law requiring or relating to the marshaling of collateral or guarantees or any other law which might cause a delay in or impede the enforcement of any Guaranteed Party’s rights under this Guaranty or other agreement.
22.Class A Tax Credit Purchase Agreement Guaranty. Promptly following any request therefor by any Class A Equity Investor, the Guarantor shall enter into one or more guaranties in accordance with Section 9.15(b)(iii) of the LLC Agreement, which such guaranties shall be in a form substantially similar to this Guaranty. The Beneficiaries agree that, to the extent Obligations exceed the Maximum Liability, any reduction of Maximum Liability following the entry of any such guaranty under this Agreement shall first reduce any recoveries brought by any such directing Class A Member under the LLC Agreement, to preserve, to the maximum extent feasible, the recoveries of the non-directing Class A Members.
[SIGNATURE PAGE FOLLOWS]


IN WITNESS WHEREOF, the Guarantor has executed and delivered this Guaranty as of the date first set forth above.
AVANGRID, INC.,
a New York corporation
s/ Annette Sturgill
Name: Annette Sturgill
Title: Authorized Representative
s/ Richard Piazza
Name: Richard Piazza
Title: Authorized Representative


Acknowledged and agreed:
JPMORGAN CHASE BANK, N.A.,
s/ Joel Spenadel
Name: Joel Spenadel
Title: Executive Director


Acknowledged and agreed:
WELLS FARGO BANK, N.A.
s/ Andrew Kho
Name: Andrew Kho
Title: Managing Director


Acknowledged and agreed:
VINEYARD WIND TE PARTNERS 1 LLC,
a Delaware limited liability company
s/ Klaus Skoust Moeller
Name: Klaus Skoust Moeller
Title: Chief Executive Officer
s/ Miguel Sanchez Calero
Name: Miguel Sanchez Calero
Title: Deputy Chief Executive Officer


EX-21.1 7 agr-ex211_2023.htm EX-21.1 Document

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 8 agr-ex231_2023.htm EX-23.1 Document

EXHIBIT 23.1
Consent of Independent Registered Public Accounting Firm
 
We consent to the incorporation by reference in the registration statements (No. 333-212616 and No. 333-208571) on Form S-8 and (No. 333-270658) on Form S-3 of our reports dated February 22, 2024, 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 22, 2024

EX-31.1 9 agr-ex311_2023.htm EX-31.1 Document

EXHIBIT 31.1
CERTIFICATION
 
I, Pedro Azagra Blázquez, 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 22, 2024
   /s/ Pedro Azagra Blázquez
    Pedro Azagra Blázquez
    Director and Chief Executive Officer

EX-31.2 10 agr-ex312_2023.htm EX-31.2 Document

EXHIBIT 31.2
CERTIFICATION

I, Justin B. Lagasse, 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 22, 2024
 /s/ Justin B. Lagasse
Justin B. Lagasse
Senior Vice President - Chief Financial Officer and Controller

EX-32 11 agr-ex32_2023.htm EX-32 Document

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, Pedro Azagra Blázquez and Justin B. Lagasse, 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/ Pedro Azagra Blázquez    
Pedro Azagra Blázquez    
Director and Chief Executive Officer    
Avangrid, Inc.    
February 22, 2024    
 
/s/ Justin B. Lagasse    
Justin B. Lagasse    
Senior Vice President - Chief Financial Officer and Controller    
Avangrid, Inc.    
February 22, 2024    

EX-97.1 12 agr-ex971x2023.htm EX-97.1 Document

Exhibit 97.1
Executive Compensation Recovery Policy
October 18, 2023
The Board of Directors of Avangrid, Inc. (“Avangrid”) oversees the management of Avangrid and its business with a view to enhance the long-term value of Avangrid. Avangrid is a member of the group of companies controlled by Iberdrola, S.A. The Board of Directors of Avangrid (the “Board of Directors”) has adopted this Executive Compensation Recovery Policy (this “Policy”) to assist in exercising its responsibilities to Avangrid and its shareholders. This Policy is subject to periodic review and modification by the Board of Directors from time to time. This Policy and Avangrid’s certificate of incorporation, by-laws, corporate governance guidelines and other policies pertaining to corporate governance and regulatory compliance, risk, sustainable development, and social responsibility (collectively, the “Governance and Sustainability System”) form the framework of governance of Avangrid and its subsidiaries (collectively, the “Avangrid Group”). Avangrid’s Governance and Sustainability System is inspired by and based on a commitment to ethical principles, transparency and leadership in the application of best practices in good governance and is designed to be a working structure for principled actions, effective decision-making and appropriate monitoring of both compliance and performance.
1.Purpose
The Board of Directors believes that it is in the best interests of Avangrid and its shareholders to create and maintain a culture that emphasizes integrity and accountability and that reinforces Avangrid’s pay-for-performance compensation philosophy. The Board of Directors has therefore adopted this Policy, which provides for the recovery of certain executive compensation in the event of an accounting restatement resulting from material noncompliance with financial reporting requirements under the federal securities laws. This Policy is designed to comply with Section 10D of the Securities Exchange Act of 1934 (the “Exchange Act”) and contributes to the achievement of goal sixteen (Peace, Justice and Strong Institutions) of the Sustainable Development Goals approved by the member states of the United Nations.
2.Excess Incentive Compensation Recovery
In the event that Avangrid is required to prepare an accounting restatement of its financial statements filed with the U.S. Securities and Exchange Commission due to the Avangrid’s material noncompliance with any financial reporting requirement under the federal securities laws, including, without limitation, any restatement required to correct errors that were not material to previously issued financial statements but would result in a material misstatement if (a) the errors were left uncorrected in the current report or (b) the error correction was recognized in the current period, the Compensation and Nominating Committee of the Board of Directors (the “Committee”) shall require reimbursement, recovery or forfeiture of any excess Incentive Compensation (defined below) awarded to any Covered Executive (defined below) during the three completed fiscal years immediately preceding the date on which Avangrid is required to prepare such accounting restatement.
For purposes of this Policy, “Covered Executive” shall mean any current or former officer of the Avangrid Group who is required to file reports pursuant to Section 16 of the Exchange Act, as amended, and such other employees who may from time to time be deemed subject to the Policy by the Committee and “Incentive Compensation” shall mean all bonuses and other incentive and equity compensation awarded, granted, earned or vested based wholly or in part on the attainment of one or more Financial Reporting Measures (i.e., bonuses and other short- and long-term cash incentives; stock options; stock appreciation rights; restricted stock or restricted stock units; and performance shares or performance share units). “Financial Reporting Measures” are those measures that are determined and presented in accordance with the accounting principles used in preparing Avangrid’s financial statements and any measures derived wholly or in part from such financial information.
The Committee shall seek reimbursement or recovery of the portion of Incentive Compensation paid or awarded the Covered Executive that is greater than would have been paid or awarded if calculated based on the accurate financial statements for financial reporting measures, as determined by the Committee. If the Committee cannot determine the amount of excess Incentive Compensation received by the Covered Executive directly from the information in the accounting restatement, then it will make its determination based on a reasonable estimate of the effect of the accounting restatement.


The Committee will determine, in its sole discretion, the method for reimbursement or recovering of excess Incentive Compensation.
3.No Indemnification; Other Rights
Avangrid shall not indemnify any Covered Executives against the loss of any incorrectly awarded Incentive Compensation. The Committee may require that any employment agreement, equity award agreement or similar agreement, as a condition to the grant of any benefit thereunder, require a Covered Executive to agree to abide by the terms of this Policy. Any right of recovery under this Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to Avangrid pursuant to the terms of any similar policy in any employment agreement, equity award agreement, or similar agreement and any other legal remedies available to Avangrid.
4.Other Recoupment Rights
The Committee intends that this Policy will be applied to the fullest extent of the law. The Committee may require that any employment agreement, equity award agreement, or similar agreement entered into shall, as a condition to the grant of any benefit thereunder, require a Covered Executive to agree to abide by the terms of this Policy. Any right of recoupment under this Policy is in addition to, and not in lieu of, any other remedies or rights of recoupment that may be available to Avangrid pursuant to the terms of any similar policy in any employment agreement, equity award agreement, or similar agreement and any other legal remedies available to Avangrid. In addition to the mandatory reimbursement or forfeiture of excess Incentive Compensation received by any Covered Executive provided for in this Policy, to the extent permitted under applicable law, the Committee or the Administrator of any of the incentive compensation plans adopted by the Avangrid Group (as such term is defined in such incentive compensation plans) may require reimbursement or forfeiture of any excess Incentive Compensation received by any employee of the Avangrid Group that is not a Covered Employee during the three completed fiscal years immediately preceding the date on which Avangrid is required to prepare an accounting restatement.
5.Impracticability
The Committee shall recover any excess Incentive Compensation in accordance with this Policy unless such recovery would be impracticable, as determined by the Committee in accordance with Rule 10D-1 of the Exchange Act and the listing standards of the national securities exchange on which Avangrid’s securities are listed.
6.Miscellaneous
The Board of Directors is authorized to interpret and construe this Policy and to make all determinations necessary, appropriate, or advisable for the administration of this Policy. It is intended that this Policy be interpreted in a manner that is consistent with the requirements of Section 10D of the Exchange Act and any applicable rules or standards adopted by the Securities and Exchange Commission or any national securities exchange on which Avangrid’s securities are listed. The Board of Directors may amend this Policy from time to time in its discretion and shall amend this Policy as it deems necessary to reflect final regulations adopted by the Securities and Exchange Commission under Section 10D of the Exchange Act and to comply with any rules or standards adopted by a national securities exchange on which Avangrid’s securities are listed. The Board of Directors may terminate this Policy at any time. This Policy shall be binding and enforceable against all Covered Executives and their beneficiaries, heirs, executors, administrators, or other legal representatives.