UNITED STATES
SECURITIES AND EXCHANGE COMMISSION
WASHINGTON, D.C. 20549

 FORM

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

For the fiscal year ended
 December 31, 2024

 or

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

For the transition period from ____________ to ____________

 Registrant; State of Incorporation; Address; Telephone Number;
 Commission File Number; and I.R.S. Employer Identification No.

 EVERSOURCE ENERGY
 (a Massachusetts voluntary association)
 300 Cadwell Drive, Springfield, Massachusetts 01104
 Telephone: ( 800) 286-5000
 Commission File Number: 001-05324
 I.R.S. Employer Identification No. 04-2147929

 (a Connecticut corporation)
 107 Selden Street, Berlin, Connecticut 06037-1616
 Telephone: ( 800) 286-5000
 Commission File Number: 000-00404
 I.R.S. Employer Identification No. 06-0303850

 NSTAR ELECTRIC COMPANY
 (a Massachusetts corporation)
 800 Boylston Street, Boston, Massachusetts 02199
 Telephone: ( 800) 286-5000
 Commission File Number: 001-02301
 I.R.S. Employer Identification No. 04-1278810

 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE
 (a New Hampshire corporation)
 Energy Park
 780 North Commercial Street, Manchester, New Hampshire 03101-1134
 Telephone: ( 800) 286-5000
 Commission File Number: 001-06392
 I.R.S. Employer Identification No. 02-0181050

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

 Title of each class
 Trading Symbol(s)
 Name of each exchange on which registered

 Common Shares, $5.00 par value per share
 ES
 New York Stock Exchange

 Indicate by check mark if the registrants are well-known seasoned issuers, as defined in Rule 405 of the Securities Act.

 Yes
 No

 Indicate by check mark if the registrants are not required to file reports pursuant to Section 13 or Section 15(d) of the Act.

 Yes
 No

 Indicate by check mark whether the registrants (1) have 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 registrants were required to file such reports), and (2) have been subject to such filing requirements for the past 90 days.

 Yes
 No

 Indicate by check mark whether the registrants have 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 registrants were 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 an emerging growth company. See the definitions of "large accelerated filer," "accelerated filer," "smaller reporting company," and "emerging growth company" in Rule 12b-2 of the Exchange Act.

 Large accelerated filer

 Accelerated
filer

 Non-accelerated
filer

 Smaller reporting company

 Emerging growth company

 Large accelerated filer

 Accelerated
filer

 Non-accelerated filer

 Smaller reporting company

 Emerging growth company

 Large accelerated filer

 Accelerated
filer

 Non-accelerated filer

 Smaller reporting company

 Emerging growth company

 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 recovery period pursuant to §240.10D-1(b).

 Indicate by check mark whether the registrants are shell companies (as defined in Rule 12b-2 of the Exchange Act):

 Yes
 No

 The aggregate market value of Eversource Energy's Common Shares, $5.00 par value, held by non-affiliates, computed by reference to the price at which the common equity was last sold, or the average bid and asked price of such common equity, as of the last business day of Eversource Energy's most recently completed second fiscal quarter (June 30, 2024) was $ 20,096,384,968 based on a closing market price of $56.71 per share for the 354,371,098 common shares outstanding held by non-affiliates on June 30, 2024.

 Indicate the number of shares outstanding of each of the registrant's classes of common stock, as of the latest practicable date:

 Company - Class of Stock
 Outstanding as of January 31, 2025

Common Shares, $5.00 par value
 366,785,030
 shares

Common Stock, $10.00 par value
 shares

Common Stock, $1.00 par value
 shares

Common Stock, $1.00 par value
 shares

 Eversource Energy holds all of the 6,035,205 shares, 200 shares, and 301 shares of the outstanding common stock of The Connecticut Light and Power Company, NSTAR Electric Company, and Public Service Company of New Hampshire, respectively.

 The Connecticut Light and Power Company, NSTAR Electric Company, and Public Service Company of New Hampshire each meet the conditions set forth in General Instruction I(1)(a) and (b) of Form 10-K, and each is therefore filing this Form 10-K with the reduced disclosure format specified in General Instruction I(2) of Form 10 K.

 Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company, and Public Service Company of New Hampshire each separately file this combined Form 10-K. Information contained herein relating to any individual registrant is filed by such registrant on its own behalf. Each registrant makes no representation as to information relating to the other registrants.

 Documents Incorporated by Reference

 Portions of the Eversource Energy and Subsidiaries 2023 combined Annual Report on Form 10-K and portions of the Proxy Statement relating to the Annual Meeting of Shareholders to be held on May 1, 2025, are incorporated by reference into Parts II and III of this Report.

 GLOSSARY OF TERMS

 The following is a glossary of abbreviations and acronyms that are found in this report:

 Current or former Eversource Energy companies, segments or investments:

 Eversource, ES or the Company
 Eversource Energy and subsidiaries

 Eversource parent or ES parent
 Eversource Energy, a public utility holding company

 ES parent and other companies
 ES parent and other companies are comprised of Eversource parent, Eversource Service, and other subsidiaries, which primarily includes our unregulated businesses, The Rocky River Realty Company (a real estate subsidiary), the consolidated operations of CYAPC and YAEC, and Eversource parent's equity ownership interests that are not consolidated

 CL&P

 PSNH

 PSNH Funding
 PSNH Funding LLC 3, a bankruptcy remote, special purpose, wholly-owned subsidiary of PSNH

 NSTAR Gas
 NSTAR Gas Company

 EGMA
 Eversource Gas Company of Massachusetts

 Yankee Gas
 Yankee Gas Services Company

 Aquarion
 Aquarion Company and its subsidiaries

 HEEC
 Harbor Electric Energy Company, a wholly-owned subsidiary of NSTAR Electric

 Eversource Service
 Eversource Energy Service Company

 CYAPC
 Connecticut Yankee Atomic Power Company

 MYAPC
 Maine Yankee Atomic Power Company

 YAEC
 Yankee Atomic Electric Company

 Yankee Companies
 CYAPC, YAEC and MYAPC

 Regulated companies
 The Eversource regulated companies are comprised of the electric distribution and transmission businesses of CL&P, NSTAR Electric and PSNH, the natural gas distribution businesses of Yankee Gas, NSTAR Gas and EGMA, Aquarion's water distribution businesses, and the solar power facilities of NSTAR Electric

 Regulators and Government Agencies:

 DEEP
 Connecticut Department of Energy and Environmental Protection

 DOE
 U.S. Department of Energy

 DOER
 Massachusetts Department of Energy Resources

 DPU
 Massachusetts Department of Public Utilities

 EPA
 U.S. Environmental Protection Agency

 FERC
 Federal Energy Regulatory Commission

 ISO-NE
 ISO New England, Inc., the New England Independent System Operator

 MA DEP
 Massachusetts Department of Environmental Protection

 NHPUC
 New Hampshire Public Utilities Commission

 PURA
 Connecticut Public Utilities Regulatory Authority

 SEC
 U.S. Securities and Exchange Commission

 Other Terms and Abbreviations:

 ADIT

 AFUDC
 Allowance For Funds Used During Construction

 AOCI
 Accumulated Other Comprehensive Income

 ARO
 Asset Retirement Obligation

 Bcf
 Billion cubic feet

 CfD
 Contract for Differences

 CWIP
 Construction Work in Progress

 EDC
 Electric distribution company

 EDIT
 Excess Deferred Income Taxes

 EPS
 Earnings Per Share

 ERISA
 Employee Retirement Income Security Act of 1974

 ESOP
 Employee Stock Ownership Plan

 Eversource 2023 Form 10-K
 The Eversource Energy and Subsidiaries 2023 combined Annual Report on Form 10-K as filed with the SEC

 Fitch
 Fitch Ratings, Inc.

 FMCC
 Federally Mandated Congestion Charge

 GAAP
 Accounting principles generally accepted in the United States of America

 GSEP
 Gas System Enhancement Program

 i

 GWh
 Gigawatt-Hours

 IPP
 Independent Power Producers

 ISO-NE Tariff
 ISO-NE FERC Transmission, Markets and Services Tariff

 kV
 Kilovolt

 kVa
 Kilovolt-ampere

 kW
 Kilowatt (equal to one thousand watts)

 LNG
 Liquefied natural gas

 LPG
 Liquefied petroleum gas

 LRS
 Supplier of last resort service

 MG
 Million gallons

 MGP
 Manufactured Gas Plant

 MMBtu
 Million British thermal units

 MMcf
 Million cubic feet

 Moody's
 Moody's Investors Services, Inc.

 MW
 Megawatt

 MWh
 Megawatt-Hours

 NETOs
 New England Transmission Owners (including Eversource, National Grid and Avangrid)

 OCI
 Other Comprehensive Income/(Loss)

 PAM
 Pension and PBOP Rate Adjustment Mechanism

 PBOP
 Postretirement Benefits Other Than Pension

 PBOP Plan
 Postretirement Benefits Other Than Pension Plan

 Pension Plan
 Single uniform noncontributory defined benefit retirement plan

 PPA
 Power purchase agreement

 PPAM
 Pole Plant Adjustment Mechanism

 RECs
 Renewable Energy Certificates

 Regulatory ROE
 The average cost of capital method for calculating the return on equity related to the distribution business segment excluding the wholesale transmission segment

 ROE
 Return on Equity

 RRBs
 Rate Reduction Bonds or Rate Reduction Certificates

 RSUs
 Restricted share units

 S&P
 Standard & Poor's Financial Services LLC

 SERP
 Supplemental Executive Retirement Plans and non-qualified defined benefit retirement plans

 SS
 Standard service

 UI
 The United Illuminating Company

 VIE
 Variable Interest Entity

 ii

 2024 FORM 10-K ANNUAL REPORT

 Page

 Item 1.
 Business

 Item 1A.
 Risk Factors

 Item 1B.
 Unresolved Staff Comments

 Item 1C.
 Cybersecurity

 Item 2.
 Properties

 Item 3.
 Legal Proceedings

 Item 4.
 Mine Safety Disclosures

 Information About Our Executive Officers

 Item 5.
 Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 Item 6.
 Removed and Reserved

 Item 7.
 Management's Discussion and Analysis of Financial Condition and Results of Operations

 Item 7A.
 Quantitative and Qualitative Disclosures about Market Risk

 Item 8.
 Financial Statements and Supplementary Data

 Item 9.
 Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 Item 9A.
 Controls and Procedures

 Item 9B.
 Other Information

 Item 10.
 Directors, Executive Officers and Corporate Governance

 Item 11.
 Executive Compensation

 Item 12.
 Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 Item 13.
 Certain Relationships and Related Transactions, and Director Independence

 Item 14.
 Principal Accountant Fees and Services

 Item 15.
 Exhibits and Financial Statement Schedules

 Item 16.
 Form 10-K Summary

 Signatures

 E- 10

 iii

 SAFE HARBOR STATEMENT UNDER THE PRIVATE SECURITIES
 LITIGATION REFORM ACT OF 1995

 References in this Annual Report on Form 10-K to "Eversource," the "Company," "we," "our," and "us" refer to Eversource Energy and its consolidated subsidiaries. CL&P, NSTAR Electric, and PSNH are each doing business as Eversource Energy.

 We make statements concerning our expectations, beliefs, plans, objectives, goals, strategies, assumptions of future events, future financial performance or growth and other statements that are not historical facts. These statements are "forward-looking statements" within the meaning of U.S. federal securities laws. You can generally identify our forward-looking statements through the use of words or phrases such as "estimate," "expect," "pending," "anticipate," "intend," "plan," "project," "believe," "forecast," "would," "should," "could," and other similar expressions. Forward-looking statements involve risks and uncertainties that may cause actual results or outcomes to differ materially from those included in our forward-looking statements. Forward-looking statements are based on the current expectations, estimates, assumptions or projections of management and are not guarantees of future performance. These expectations, estimates, assumptions or projections may vary materially from actual results. Accordingly, any such statements are qualified in their entirety by reference to, and are accompanied by, the following important factors that may cause our actual results or outcomes to differ materially from those contained in our forward-looking statements, including, but not limited to:

 • cyberattacks or breaches, including those resulting in the compromise of the confidentiality of our proprietary information and the personal information of our customers,
 • the ability to qualify for investment tax credits and investment tax credit adders,
 • variability in the costs and final investment returns of the Revolution Wind and South Fork Wind offshore wind projects as it relates to the purchase price post-closing adjustment under the terms of the sale agreement for these projects,
 • disruptions in the capital markets or other events that make our access to necessary capital more difficult or costly,
 • changes in economic conditions, including impact on interest rates, tax policies, and customer demand and payment ability,
 • ability or inability to commence and complete our major strategic development projects and opportunities,
 • acts of war or terrorism, physical attacks or grid disturbances that may damage and disrupt our electric transmission and electric, natural gas, and water distribution systems,
 • actions or inaction of local, state and federal regulatory, public policy and taxing bodies,
 • substandard performance of third-party suppliers and service providers,
 • fluctuations in weather patterns, including extreme weather due to climate change,
 • changes in business conditions, which could include disruptive technology or development of alternative energy sources related to our current or future business model,
 • contamination of, or disruption in, our water supplies,
 • changes in levels or timing of capital expenditures,
 • changes in laws, regulations, Presidential executive orders or regulatory policy, including compliance with environmental laws and regulations,
 • changes in accounting standards and financial reporting regulations,
 • actions of rating agencies, and
 • other presently unknown or unforeseen factors.

 Other risk factors are detailed in our reports filed with the SEC and are updated as necessary and available on our website at www.eversource.com and on the SEC's website at www.sec.gov, and we encourage you to consult such disclosures.

 All such factors are difficult to predict and contain uncertainties that may materially affect our actual results, many of which are beyond our control. You should not place undue reliance on the forward-looking statements, as each speaks only as of the date on which such statement is made, and, except as required by federal securities laws, we undertake no obligation to update any forward-looking statement or statements to reflect events or circumstances after the date on which such statement is made or to reflect the occurrence of unanticipated events. New factors emerge from time to time and it is not possible for us to predict all of such factors, nor can we assess the impact of each such factor on the business or the extent to which any factor, or combination of factors, may cause actual results to differ materially from those contained in any forward-looking statements. For more information, see Item 1A, Risk Factors, included in this combined Annual Report on Form 10-K. This Annual Report on Form 10-K also describes material contingencies and critical accounting policies in the accompanying Management's Discussion and Analysis of Financial Condition and Results of Operations and Combined Notes to Financial Statements. We encourage you to review these items.

 Item 1. Business

 Please refer to the Glossary of Terms for definitions of defined terms and abbreviations used in this combined Annual Report on Form 10-K.

 Eversource Energy (Eversource), headquartered in Boston, Massachusetts and Hartford, Connecticut, is a public utility holding company subject to regulation by the Federal Energy Regulatory Commission (FERC) under the Public Utility Holding Company Act of 2005. We are engaged primarily in the energy delivery business through the following wholly-owned utility subsidiaries:

 • The Connecticut Light and Power Company (CL&P), a regulated electric utility that serves residential, commercial and industrial customers in parts of Connecticut;

 • NSTAR Electric Company (NSTAR Electric), a regulated electric utility that serves residential, commercial and industrial customers in parts of eastern and western Massachusetts and owns solar power facilities, and its wholly-owned subsidiary Harbor Electric Energy Company (HEEC), also a regulated electric utility that distributes electric energy to its sole customer;

 • Public Service Company of New Hampshire (PSNH), a regulated electric utility that serves residential, commercial and industrial customers in parts of New Hampshire;

 • NSTAR Gas Company (NSTAR Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts;

 • Eversource Gas Company of Massachusetts (EGMA), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Massachusetts;

 • Yankee Gas Services Company (Yankee Gas), a regulated natural gas utility that serves residential, commercial and industrial customers in parts of Connecticut; and

 • Aquarion Company (Aquarion), a utility holding company that owns five separate regulated water utility subsidiaries and collectively serves residential, commercial, industrial, and municipal and fire protection customers in parts of Connecticut, Massachusetts and New Hampshire. Eversource is currently in the process of selling its Aquarion water distribution business. For further information, see "Business Development and Capital Expenditures – Pending Sale of Aquarion" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 CL&P, NSTAR Electric and PSNH also serve New England customers through Eversource's electric transmission business. Along with NSTAR Gas, EGMA and Yankee Gas, each is doing business as Eversource Energy in its respective service territory.

 Eversource, CL&P, NSTAR Electric and PSNH each report their financial results separately. We also include information in this report on a segment basis for Eversource. Eversource has four reportable segments: electric distribution, electric transmission, natural gas distribution and water distribution. These segments represent substantially all of Eversource's total consolidated revenues. CL&P, NSTAR Electric and PSNH do not report separate business segments.

 Eversource's previous offshore wind business included 50 percent ownership interests in each of North East Offshore and South Fork Class B Member, LLC. In the third quarter of 2024, Eversource sold its interest in these entities, and in doing so, sold its interests in the Revolution Wind project, the South Fork Wind project, and the Sunrise Wind project. Eversource's current offshore wind business is now comprised only of a noncontrolling tax equity investment in South Fork Wind. For more information, see "Business Development and Capital Expenditures – Offshore Wind Business" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 ELECTRIC DISTRIBUTION SEGMENT

 Eversource's electric distribution segment consists of the distribution businesses of CL&P, NSTAR Electric and PSNH, which are engaged in the distribution of electricity to retail customers in Connecticut, Massachusetts and New Hampshire, respectively, and the solar power facilities of NSTAR Electric.

 ELECTRIC DISTRIBUTION – CONNECTICUT – THE CONNECTICUT LIGHT AND POWER COMPANY

 CL&P's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2024, CL&P furnished retail franchise electric service to approximately 1.30 million customers in 157 cities and towns in Connecticut. CL&P does not own any electric generation facilities.

 Rates

 CL&P is subject to regulation by the Connecticut Public Utilities Regulatory Authority (PURA), which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities. CL&P's present general rate structure consists of various rate and service classifications covering residential, commercial and industrial services.

 Under Connecticut law, all of CL&P's customers are entitled to choose their energy suppliers, while CL&P remains their electric distribution company. For those customers who do not choose a competitive energy supplier, CL&P purchases power on behalf of, and passes the related cost without mark-up through to, those customers under standard service (SS) rates for customers with less than 500 kilowatts of demand (residential customers and small and medium commercial and industrial customers), and supplier of last resort service (LRS) rates for customers with 500 kilowatts or more of demand (larger commercial and industrial customers). CL&P charges customers only the amount that it pays generators for producing electricity and does not earn a profit on the cost of electricity.

 CL&P's retail rates include an energy supply component and a delivery service component, which includes distribution, transmission, conservation, renewable energy programs and other public benefit charges that are assessed on all customers. The rates established by PURA for CL&P, which are grouped by the customer bill components, are comprised of the following:

 Supply: Cost of electricity from suppliers based on competitive procurements.

 • An electric generation service charge, which recovers energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to competitive energy suppliers. The generation service charge is adjusted periodically and reconciled annually in accordance with the policies and procedures of PURA, with any differences refunded to, or recovered from, customers.

 Local Delivery: Cost to build, maintain, repair and operate the distribution grid, including the poles, lines, and meters that deliver power from the substation. It also includes the cost of resiliency and reliability improvements.

 • A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the infrastructure to deliver electricity to customers, as well as ongoing operating costs to maintain the infrastructure.

 • A revenue decoupling adjustment that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by PURA.

 • An Electric System Improvements (ESI) charge, which collects the costs of building and expanding the infrastructure to deliver electricity to customers above the level recovered through the distribution charge. The ESI also recovers costs associated with CL&P's system resiliency program. The ESI is adjusted periodically and reconciled annually in accordance with the policies and procedures of PURA, with any differences refunded to, or recovered from, customers. In 2023, the state of Connecticut enacted a law that prohibits CL&P's ESI capital tracking mechanism from being reauthorized in the next general distribution proceeding. The ESI will therefore remain in place until base distribution rates are adjusted in CL&P's next general distribution rate proceeding.

 • A Competitive Transition Assessment (CTA) charge, assessed to recover stranded costs associated with electric industry restructuring such as various IPP contracts. The CTA is reconciled annually to actual costs incurred and reviewed by PURA, with any difference refunded to, or recovered from, customers.

 Public Benefits: Cost to support energy programs mandated by the state and federal government for financial assistance and energy efficiency programs, purchasing renewable and carbon-free electricity, and funding solar and electric vehicle incentives.

 • A Federally Mandated Congestion Charge (FMCC), which recovers any costs imposed by the FERC as part of the New England Standard Market Design, including locational marginal pricing, locational installed capacity payments, any costs approved by PURA to reduce these charges, as well as other costs approved by PURA. These costs include costs associated with ISO-NE, costs to avoid congestion on the transmission system, purchase contracts with zero-carbon energy generators (including the Millstone and Seabrook nuclear contracts) and with renewable energy generators, costs for capacity and gas peaker plants, renewable energy credits, and other initiatives required by state law. The non-bypassable component of the FMCC is adjusted periodically and reconciled annually in accordance with the policies and procedures of the PURA, with any differences refunded to, or recovered from, customers. CL&P is required by regulation to purchase electric generation from Millstone and Seabrook under PURA-approved PPAs entered into in 2019. CL&P does not have legislative authority to use this purchased output to serve its customer load and therefore sells the energy into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net cost or net sales amount is recovered from, or refunded to, customers in the non-bypassable component of the FMCC rate with no company profit.

 • A Systems Benefits Charge (SBC), established to fund expenses associated with various hardship and low-income programs. The SBC is reconciled annually to actual costs incurred, and reviewed by PURA, with any difference refunded to, or recovered from, customers.

 • A Renewable Energy Investment Charge, which is used to promote investment in renewable energy sources. Amounts collected by this charge are deposited into the Connecticut Clean Energy Fund and administered by the Connecticut Green Bank.

 • A Conservation Adjustment Mechanism (CAM) charge established to implement cost-effective energy conservation programs and market transformation initiatives. The CAM charge is reconciled annually to actual costs incurred, and reviewed by PURA, with any difference refunded to, or recovered from, customers through an approved adjustment to the following year's energy conservation spending plan budget.

 Transmission: Cost to maintain high voltage towers and lines, including building, maintaining and operating the regional transmission system that brings electricity from power generators to the local distribution system.

 • A transmission charge that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The transmission charge is adjusted periodically and reconciled annually to actual costs incurred, and reviewed by PURA, with any difference refunded to, or recovered from, customers.

 Distribution Rate Case and Settlement Agreement: CL&P's distribution rates were established in an April 2018 PURA-approved rate case settlement agreement with rates effective May 1, 2018, and incremental step adjustments effective May 1, 2019 and May 1, 2020. In accordance with a 2021 settlement agreement, CL&P agreed that its current base distribution rates would be frozen, subject to certain customer credits, until no earlier than January 1, 2024. The rate freeze applied only to base distribution rates (including storm costs) and not to other rate mechanisms such as the retail rate components, rate reconciling mechanisms, formula rates and any other adjustment mechanisms. The rate freeze also did not apply to any cost recovery mechanism outside of the base distribution rates with regard to grid-modernization initiatives or any other proceedings that were either pending or that could be initiated during the rate freeze period, that could have placed additional obligations on CL&P. The approval of the settlement agreement satisfied the Connecticut statute of rate review requirements that requires electric utilities to file a distribution rate case within four years of the last rate case.

 CL&P Performance Based Rate Making: PURA currently has an open proceeding to evaluate and eventually implement performance based regulation (PBR) for electric distribution companies. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Sources and Availability of Electric Power Supply

 As noted above, CL&P does not own any generation assets and purchases energy supply to serve its SS and LRS loads from a variety of competitive sources through requests for proposals. During 2024, CL&P supplied approximately 45 percent of its customer load at SS or LRS rates while the other 55 percent of its customer load had migrated to competitive energy suppliers. In terms of the total number of CL&P customers, this equates to 21 percent being on competitive supply, while 79 percent remain with SS or LRS. Because customer migration is limited to energy supply service, it has no impact on CL&P's electric distribution business or its operating income.

 As approved by PURA, CL&P periodically enters into full requirements supply contracts for SS loads for periods of up to one year. CL&P typically enters into full requirements supply contracts for LRS loads every three months. If CL&P does not obtain full requirements supply contracts for 100 percent of the customer load for any period, it is authorized by PURA to meet the remaining load obligations directly through the ISO-NE wholesale markets. Currently, CL&P has full requirements supply contracts in place for 100 percent of its SS load for the first half of 2025. For the second half of 2025, CL&P has 50 percent of its SS load under full requirements supply contracts and intends to purchase an additional 50 percent of full requirements. None of the SS load for 2026 has been procured. CL&P obtained a full requirements supply contract for its LRS load through March 2025 and intends to purchase 100 percent of full requirements for LRS for the remainder of 2025. CL&P is prepared to self-manage the LRS load if unable to obtain full requirements supply contracts for LRS.

 ELECTRIC DISTRIBUTION – MASSACHUSETTS – NSTAR ELECTRIC COMPANY

 NSTAR Electric's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2024, NSTAR Electric furnished retail franchise electric service to approximately 1.58 million customers in 159 cities and towns in eastern and western Massachusetts, including Boston, Cape Cod, Martha's Vineyard and the greater Springfield metropolitan area.

 NSTAR Electric does not own any generating facilities that are used to supply customers, and purchases its energy requirements from competitive energy suppliers. NSTAR Electric owns, operates and maintains a total of 70 MW of solar power facilities on twenty-two sites in Massachusetts. NSTAR Electric sells energy from these facilities into the ISO-NE market, with proceeds credited to customers.

 Rates

 NSTAR Electric is subject to regulation by the Massachusetts Department of Public Utilities (DPU), which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, acquisition of securities, standards of service and construction and operation of facilities. The present general rate structure for NSTAR Electric consists of various rate and service classifications covering residential, commercial and industrial services.

 Under Massachusetts law, all customers of NSTAR Electric are entitled to choose their energy suppliers, while NSTAR Electric remains their electric distribution company. For those customers who do not choose a competitive energy supplier, NSTAR Electric purchases power from competitive suppliers on behalf of, and passes the related cost without mark-up through to, those customers (basic service). Electric distribution companies in Massachusetts are required to obtain and resell power to retail customers through basic service for those who choose not to buy energy from a competitive energy supplier. NSTAR Electric charges customers only the amount that it pays generators for producing electricity and does not earn a profit on the cost of electricity.

 NSTAR Electric's retail rates include a supply component and a delivery component, which include distribution, transmission, renewable energy programs and other public policy charges that are assessed on all customers. The rates established by the DPU for NSTAR Electric, which are grouped by the customer bill components, are comprised of the following:

 Supply: Cost of electricity from suppliers based on competitive procurements.

 • A basic service charge that represents the collection of energy costs incurred as a result of providing electric generation service supply to all customers who have not migrated to competitive energy suppliers, including costs related to charge-offs of uncollectible energy costs from customers. Basic service rates are reset every six months (every three months for large commercial and industrial customers). Additionally, the DPU has authorized NSTAR Electric to recover the cost of its NSTAR Green wind contracts through the basic service charge. Basic service costs are reconciled annually, with any differences refunded to, or recovered from, customers.

 Delivery: Cost of grid maintenance and other critical customer services and also includes government-mandated charges.

 • A distribution charge, which includes a fixed customer charge and a demand and/or energy charge to collect the costs of building and expanding the distribution infrastructure to deliver electricity to its destination, as well as ongoing operating costs.

 • A revenue decoupling adjustment that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the DPU. Annual base distribution amounts are adjusted for inflation and certain other items and filed for approval by the DPU on an annual basis, until the next rate case.

 • A transmission charge that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The transmission charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.

 • A transition charge that represents costs to be collected primarily from previously held investments in generating plants, costs related to existing above-market power contracts, and contract costs related to long-term power contract buy-outs. The transition charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.

 • A renewable energy charge that represents a legislatively-mandated charge to support the Massachusetts Renewable Energy Trust Fund.

 • An energy efficiency charge that represents a legislatively-mandated charge to collect costs for energy efficiency programs. The energy efficiency charge is reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.

 • Reconciling adjustment charges that recover certain DPU-approved costs, including pension and PBOP benefits, low income customer discounts, credits issued to net metering facilities installed by customers, payments to solar facilities qualified under the state solar renewable energy target program, attorney general consultant expenses, long-term renewable contracts, company-owned solar facilities, vegetation management costs, storm restoration, credits related to the Tax Cuts and Jobs Act of 2017, grid modernization costs, advanced metering infrastructure costs, electric vehicle make-ready infrastructure costs, and provisional system planning charges. These charges are reconciled annually to actual costs incurred, and reviewed by the DPU, with any difference refunded to, or recovered from, customers.

 Distribution Rate Case: NSTAR Electric distribution rates were established in a November 2022 DPU-approved rate case, with rates effective January 1, 2023. The DPU approved a renewal of the PBR plan originally authorized in its last rate case for a five-year term, with a corresponding stay out provision. The PBR plan term has the possibility of a five-year extension. The PBR mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Service Quality Metrics: NSTAR Electric is subject to service quality (SQ) metrics that measure safety, reliability and customer service, and could be required to pay to customers a SQ charge of up to 2.5 percent of annual transmission and distribution revenues for failing to meet such metrics. NSTAR Electric will not be required to pay a SQ charge for its 2024 performance as the company achieved results at or above target for all of its SQ metrics in 2024.

 Sources and Availability of Electric Power Supply

 As noted above, NSTAR Electric does not own generation assets (other than 70 MW of solar power facilities that produce energy that is sold into the ISO-NE market) and purchases its energy supply requirements from a variety of competitive sources through requests for proposals issued periodically, consistent with DPU regulations. As approved by the DPU, NSTAR Electric enters into supply contracts for basic service for approximately 26 percent of its residential and 14 percent of its small commercial and industrial (C&I) customers twice per year for twelve-month terms. NSTAR Electric enters into supply contracts for basic service for three percent of its large C&I customers every three months.

 During 2024, NSTAR Electric supplied approximately 14 percent of its overall customer load at basic service rates. The remaining 86 percent of its overall customer load was served either by municipal aggregation or competitive supply. Because customer migration is limited to energy supply service, it has no impact on NSTAR Electric's electric distribution business or its operating income.

 ELECTRIC DISTRIBUTION – NEW HAMPSHIRE – PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

 PSNH's distribution business consists primarily of the purchase, delivery and sale of electricity to its residential, commercial and industrial customers. As of December 31, 2024, PSNH furnished retail franchise electric service to approximately 544,000 retail customers in 206 cities and towns in New Hampshire. PSNH does not own any electric generation facilities.

 Rates

 PSNH is subject to regulation by the New Hampshire Public Utilities Commission (NHPUC), which, among other things, has jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of securities, standards of service and construction and operation of facilities.

 Under New Hampshire law, all of PSNH's customers are entitled to choose competitive energy suppliers. For those customers who do not choose a competitive energy supplier, PSNH purchases power on behalf of, and passes the related cost without mark-up through to, those customers (default energy service). PSNH charges customers only the amount that it pays generators for producing electricity and does not earn a profit on the cost of electricity.

 PSNH's retail rates include a supply component and a delivery component, which include distribution, transmission, renewable energy programs and other public policy charges that are assessed on all customers. The rates established by the NHPUC for PSNH, which are grouped by the customer bill components, are comprised of the following:

 Supply: Cost of electricity from suppliers based on competitive procurements.

 • A default energy service charge recovers energy-related costs incurred as a result of providing electric generation service supply to all customers who have not migrated to competitive energy suppliers. The default energy service charge changes semi-annually, and is reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers.

 Delivery: Cost of building, maintaining and operating distribution and transmission systems, as well as state and federally mandated charges that fund financial assistance, energy efficiency and renewable energy programs.

 • A distribution charge, which includes kilowatt-hour and/or demand-based charges to recover costs related to the maintenance and operation of PSNH's infrastructure to deliver power to its destination, as well as power restoration and service costs. It also includes a customer charge to collect the cost of providing service to a customer; such as the installation, maintenance, reading and replacement of meters and maintaining accounts and records.

 • A Transmission Charge Adjustment Mechanism (TCAM) that recovers the cost of transporting electricity over high-voltage lines from generating plants to substations, including costs allocated by ISO-NE to maintain the wholesale electric market. The transmission charge is reconciled annually to actual costs incurred, and reviewed by the NHPUC, with any difference refunded to, or recovered from, customers.

 • A Stranded Cost Recovery Charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations, recovery of costs of the net metering credit program, a credit for revenues generated by the RGGI program, other long-term investments and obligations, and the remaining costs associated with the 2018 sales of its generation facilities. The SCRC rate changes annually with the option to change semi-annually, and is reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers.

 • A Systems Benefits Charge (SBC), which funds energy efficiency programs for all customers, as well as assistance programs for residential customers within certain income guidelines. The SBC also has a component for the company to collect lost base revenue (LBR) from the implementation of energy efficiency measures. LBR will remain a component of the SBC charge unless and until PSNH has a decoupling or other revenue adjustment mechanism approved by the NHPUC. The SBC rate changes annually and is reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers.

 • A Regulatory Reconciliation Adjustment (RRA) that reconciles the difference between certain estimated and actual costs included in base distribution rates, including costs related to regulatory assessments, vegetation management program expenses, property tax expenses, storm cost amortization updated for the actual cost of long-term debt and lost base revenues related to net metering.

 • A Pole Plant Adjustment Mechanism (PPAM) that recovers certain costs associated with poles acquired under a 2023 purchase agreement between PSNH and Consolidated Communications, including the operation and maintenance of poles, pole inspections, and vegetation management expenses incurred, beginning February 10, 2021 through April 30, 2023.

 Distribution Rate Case and Settlement Agreement: PSNH's distribution rates were established in a 2020 NHPUC-approved rate case settlement agreement with rates effective January 1, 2021. PSNH was permitted three step increases, effective January 1, 2021, August 1, 2021, and November 1, 2022 to reflect plant additions in calendar years 2019, 2020 and 2021, respectively.

 On June 11, 2024, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase effective August 1, 2024, which was approved by the NHPUC on July 31, 2024. Also on June 11, 2024, PSNH filed an application with the NHPUC to request an increase in permanent base distribution rates, proposed to take effect August 1, 2025. A decision by the NHPUC on permanent rates is expected by August 1, 2025. For further information, see "Regulatory Developments and Rate Matters - New Hampshire" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Sources and Availability of Electric Power Supply

 PSNH does not own any generation assets and as approved by the NHPUC, purchases energy supply from a variety of competitive suppliers for its energy service customers through requests for proposals issued twice per year, for six-month terms, for approximately 58 percent of its residential and small C&I customers and for 15 percent of its large C&I customers. As required by the NHPUC, PSNH purchased 12.5 percent of its residential and small C&I customer load through direct wholesale market participation for the second half of 2024.

 During 2024, PSNH supplied approximately 58 percent of its customer load at default energy service rates while the other 42 percent of its customer load had migrated to competitive energy suppliers. Because customer migration is limited to energy supply service, it has no impact on PSNH's electric distribution business or its operating income.

 ELECTRIC TRANSMISSION SEGMENT

 CL&P, NSTAR Electric and PSNH each own and maintain transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. Each of CL&P, NSTAR Electric and PSNH, and most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. Under these arrangements, ISO-NE, a non-profit corporation whose board of directors and staff are independent of all market participants, serves as the regional transmission organization of the New England transmission system.

 Wholesale Transmission Rates and Transmission Proceedings

 CL&P, NSTAR Electric and PSNH wholesale transmission rates are calculated in accordance with a FERC-approved formula ratemaking framework and each utility is required to file an annual update on or before July 31st with resulting rates effective January 1st the following year. The formula rate framework provides for an annual reconciliation of the prior calendar year actual costs incurred related to our transmission facilities, including an allowed ROE, plus forecasted information through the next rate period. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refund to, transmission wholesale customers. The annual update process also includes formula rate protocols that provide disclosure of cost inputs, an opportunity for informal discovery procedures and a challenge process, which provides transparency to stakeholders. The transmission rates are collected from New England wholesale customers, including distribution customers of CL&P, NSTAR Electric and PSNH.

 From time to time, various matters are pending before FERC relating to transmission rates, incentives, interconnections and transmission planning. Depending on the outcome, any of these matters could materially impact our results of operations and financial condition. At this time, Eversource cannot predict the ultimate outcome of the matters currently pending before FERC, and the resulting impact on its transmission incentives or planning.

 Transmission Rate Base

 Transmission rate base under our FERC-approved tariff primarily consists of our investment in transmission net utility plant less accumulated deferred income taxes. Under our FERC-approved tariff, investments in net utility plant generally enter rate base after they are placed in commercial operation. At the end of 2024, our estimated transmission rate base was approximately $10.8 billion, including approximately $4.4 billion at CL&P, $4.4 billion at NSTAR Electric, and $2.0 billion at PSNH.

 FERC ROE Complaints

 Four separate complaints were filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15-month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive (incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable.

 In response to appeals of the FERC decision in the first complaint filed by the NETOs and the Complainants, the U.S. Court of Appeals for the D.C. Circuit (the Court) issued a decision on April 14, 2017 vacating and remanding the FERC's decision. On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE.

 During 2019 and 2020, FERC also issued multiple decisions in two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted new methodologies for determining base ROEs. On August 9, 2022, the Court issued a decision vacating these MISO FERC decisions and remanded to FERC to reopen the proceedings. On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings. On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing.

 On November 13, 2024, the NETOs filed a supplemental brief in their four pending ROE proceedings to explain to FERC that it cannot apply the reasoning and methodologies of the MISO ROE case to the NETOs' cases due to the entirely different set of facts in the MISO and NETOs ROE proceedings. Doing so would violate the substance of the Court's April 14, 2017 order and would violate the legal standard required by the Federal Power Act.

 Given the significant uncertainty regarding the applicability of the FERC order in the MISO transmission owners' two complaint cases to the NETOs' pending four complaint cases due to the complex differences between the cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaints or subsequent periods at this time and Eversource cannot reasonably estimate any potential range of loss for any of the four complaint proceedings at this time. The resolution of these proceedings could have a material impact on the financial condition, results of operations, and cash flows. For further information, see "FERC Regulatory Matters - FERC ROE Complaints" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 NATURAL GAS DISTRIBUTION SEGMENT

 NSTAR Gas distributes natural gas to approximately 315,000 customers in 59 communities in central and eastern Massachusetts. EGMA distributes natural gas to approximately 332,000 customers in 66 communities throughout Massachusetts. Yankee Gas distributes natural gas to approximately 254,000 customers in 85 cities and towns in Connecticut. Our natural gas businesses provide firm natural gas sales and transportation service to eligible retail customers who require a continuous natural gas supply throughout the year, such as residential customers who rely on natural gas for heating, hot water and cooking needs, as well as commercial and industrial customers who rely on natural gas for space heating, hot water, cooking and commercial and industrial applications. Total throughput (sales and transportation) in 2024 was approximately 69.0 Bcf for NSTAR Gas, 54.8 Bcf for EGMA, and 59.5 Bcf for Yankee Gas.

 NSTAR Gas, EGMA and Yankee Gas generate revenues primarily through the sale and/or transportation of natural gas. All NSTAR Gas and EGMA retail customers have the ability to choose to purchase gas from third party marketers under the Massachusetts Retail Choice program. In the past year in Massachusetts, Retail Choice represented only approximately one percent of the total residential load, while Retail Choice represented approximately 40 percent of the total commercial and industrial load. Retail natural gas service in Connecticut is partially unbundled: residential customers in Yankee Gas' service territory buy natural gas supply and delivery only from Yankee Gas while commercial and industrial customers may choose their natural gas suppliers. For customers who purchase natural gas from NSTAR Gas, EGMA and Yankee Gas, the purchased natural gas commodity cost is passed through to those customers without mark-up. NSTAR Gas, EGMA and Yankee Gas do not earn a profit on the cost of purchased gas.

 Firm transportation service is offered to customers who purchase natural gas from sources other than NSTAR Gas, EGMA or Yankee Gas. NSTAR Gas and EGMA have the ability to offer interruptible transportation and interruptible natural gas sales service to high volume commercial and industrial customers. Yankee Gas offers interruptible transportation and interruptible natural gas sales service to commercial and industrial customers who have the ability to switch from natural gas to an alternate fuel on short notice. NSTAR Gas, EGMA and Yankee Gas can interrupt service to these customers during peak demand periods or at any other time to maintain distribution system integrity.

 A portion of the storage of natural gas supply for NSTAR Gas and EGMA during the winter heating season is provided by Hopkinton LNG Corp., an indirect, wholly-owned subsidiary of Eversource. NSTAR Gas has access to facilities consisting of an LNG liquefaction and vaporization plant and three above-ground cryogenic storage tanks having an aggregate capacity of 3.0 Bcf of liquefied natural gas and facilities that include additional storage capacity of 0.5 Bcf. Total vaporization capacity of these facilities is 0.21 Bcf per day. EGMA has access to approximately 1.7 Bcf of LNG and 0.1 Bcf of LPG storage, with a total vaporization capacity of 0.15 Bcf per day. Yankee Gas owns a 1.2 Bcf LNG facility, which also has the ability to liquefy and vaporize up to 0.1 Bcf per day. This facility is used primarily to assist Yankee Gas in meeting its supplier-of-last-resort obligations and also enables it to provide economic supply and make economic refill of natural gas, typically during periods of low demand.

 Rates

 NSTAR Gas and EGMA are subject to regulation by the DPU and Yankee Gas is subject to regulation by the PURA, both of which, among other things, have jurisdiction over rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities.

 Retail natural gas supply and delivery rates are established by the DPU and the PURA and are comprised of:

 • A seasonal cost of gas adjustment clause (CGAC) at NSTAR Gas and EGMA that collects natural gas supply costs, pipeline and storage capacity costs, costs related to charge-offs of uncollected energy costs and working capital related costs. The CGAC is reset semi-annually with any difference being recovered from, or refunded to, customers during the following corresponding season. In addition, NSTAR Gas and EGMA file interim changes to the CGAC factor when the actual costs of natural gas supply vary from projections by more than five percent.

 • A Purchased Gas Adjustment (PGA) clause at Yankee Gas that collects the costs of the procurement of natural gas for its firm and seasonal customers. The PGA is evaluated monthly. Differences between actual natural gas costs and collection amounts from September 1st through August 31st of each PGA year are deferred and then recovered from, or refunded to, customers during the following PGA year. Carrying charges on outstanding balances are calculated using Yankee Gas' weighted average cost of capital in accordance with the directives of the PURA.

 • A distribution charge consisting of a fixed customer charge and a demand and/or energy charge that collects the costs of building, maintaining, and expanding the natural gas infrastructure to deliver natural gas supply to its customers. This also includes collection of ongoing operating costs.

 • A local distribution adjustment clause (LDAC) at NSTAR Gas and EGMA that collects all energy efficiency and related program costs, environmental costs, pension and PBOP related costs, attorney general consultant costs, credits related to the Tax Cuts and Jobs Act of 2017, gas system enhancement program (GSEP) costs, costs associated with low income customers, and costs associated with a geothermal pilot program. The LDAC is reset annually with any difference being recovered from, or refunded to, customers during the following period and provides for the recovery of certain costs applicable to both sales and transportation customers.

 • A Conservation Adjustment Mechanism (CAM) at Yankee Gas, which allows 100 percent recovery of conservation costs through this mechanism including program incentives to promote energy efficiency. A reconciliation of CAM revenues to expenses is performed annually with any difference being recovered from, or refunded to, customers with carrying charges during the following year.

 • A Gas System Improvement (GSI) reconciliation mechanism at Yankee Gas, which collects the costs of certain Distribution Integrity Management Program (DIMP) and core capital plant in service above and beyond the level that is recovered through the distribution charge. The GSI is adjusted and reconciled annually, with any differences refunded to, or recovered from, customers.

 • A System Expansion Rate (SER) reconciliation mechanism at Yankee Gas, which compares distribution system expansion investment costs and revenues from system expansion customers with the level projected in current distribution customer rates. This reconciliation is performed annually and customer rates are adjusted accordingly.

 • A Revenue Decoupling Mechanism (RDM) at NSTAR Gas and EGMA that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the DPU. The pre-established level of baseline distribution delivery service revenue requirement is also subject to adjustment in accordance with provisions of the November 2020 NSTAR Gas distribution rate case and the October 2020 EGMA rate settlement agreement.

 • A RDM at Yankee Gas that reconciles annual base distribution rate recovery amounts recovered from customers to the pre-established level of baseline distribution delivery service revenue requirement approved by the PURA. The pre-established level of baseline distribution delivery service revenue requirement is also subject to adjustment in accordance with provisions of the 2018 rate case settlement agreement.

 Distribution Rate Cases and Settlement Agreements:
 NSTAR Gas: NSTAR Gas distribution rates were established in an October 2020 DPU-approved rate case, with rates effective November 1, 2020. The DPU also approved a 10-year PBR plan through November 1, 2030, which includes inflation-based adjustments to annual base distribution amounts effective annually beginning November 1, 2021. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 EGMA: EGMA's distribution rates were established in a DPU-approved October 7, 2020 rate settlement agreement, with rate increases on November 1, 2021 and November 1, 2022, and two rate base resets during an eight-year rate plan. The first rate base reset occurred on November 1, 2024 and the second will occur November 1, 2027. Notwithstanding the two distribution rate increases, the two rate base reset provisions, and potential adjustments for qualifying exogenous events, EGMA agreed not to file for an increase or redesign of distribution base rates effective prior to November 1, 2028. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Yankee Gas: Yankee Gas distribution rates were established in a December 2018 PURA-approved rate case settlement agreement, with rates effective November 15, 2018. PURA also approved step adjustments effective January 1, 2020 and January 1, 2021. On November 12, 2024, Yankee Gas filed an application to amend its base distribution rates for effect on November 1, 2025. A final decision by PURA is expected in October 2025. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Service Quality Metrics: NSTAR Gas and EGMA are subject to SQ metrics that measure safety, reliability and customer service and each could be required to pay to customers a SQ charge of up to 2.5 percent of annual distribution revenues for failing to meet such metrics. NSTAR Gas and EGMA will not be required to pay any SQ charges relating to their 2024 performance.

 Natural Gas Replacement

 Massachusetts: Pursuant to Massachusetts legislation, in October of each year, NSTAR Gas and EGMA file GSEP Plans with the DPU for the following construction year. The GSEP Program is designed to accelerate the replacement of certain natural gas distribution facilities in the system to less than 25 years. The GSEP includes a tariff that provides NSTAR Gas and EGMA an opportunity to collect the costs for the program on an annual basis through a reconciling factor. On April 30th each year, the DPU approves the GSEP rate recovery factor that goes into effect on May 1st.

 In October 2020, the DPU opened Docket "DPU 20-80 The Future of Gas" to examine the role of Massachusetts natural gas local distribution companies (LDCs) in helping to meet the state's 2050 climate goals. For further information, see "Regulatory Developments and Rate Matters - Massachusetts" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Connecticut: Yankee Gas' December 2018 PURA-approved rate case settlement agreement included an accelerated pipeline replacement cost recovery program. The GSI rate recovers accelerated pipeline replacement as well as other capital investment through an annual reconciliation. Yankee Gas files its GSI reconciliation annually on March 1st for rates effective April 1st.

 Sources and Availability of Natural Gas Supply

 NSTAR Gas and EGMA maintain flexible resource portfolios consisting of natural gas supply contracts, transportation contracts on interstate pipelines, market area storage and peaking services. NSTAR Gas and EGMA purchase transportation, storage, and balancing services from Tennessee Gas Pipeline Company and Algonquin Gas Transmission Company, as well as other upstream pipelines that transport natural gas from major natural gas producing regions in the U.S., including the Gulf Coast, Mid-continent region, and Appalachian Shale (as well as Ontario, Canada specific to EGMA), which supply to the final delivery points in the NSTAR Gas and EGMA service areas. NSTAR Gas purchases all of its natural gas supply under a firm, competitively bid annual portfolio management contract. EGMA purchases the majority of its natural gas supply under a number of firm, competitively bid annual portfolio management contracts, and manages a portion of its own portfolio. In addition to the firm transportation and natural gas storage supplies discussed above, NSTAR Gas and EGMA utilize on-system LNG facilities (and also LPG facilities for EGMA) to meet winter peaking demands. These LNG facilities are located within NSTAR Gas' and EGMA's distribution systems and are used to liquefy pipeline natural gas and/or receive liquefied natural gas or liquefied petroleum gas to be stored during the warmer months for vaporization and use during the heating season. During the summer injection season, excess pipeline capacity and supplies are used to deliver and store natural gas in market area underground storage facilities located in Maryland and Pennsylvania. Stored natural gas is withdrawn during the winter season to supplement flowing pipeline supplies in order to meet firm heating demand. NSTAR Gas has firm underground storage contracts and total storage capacity entitlements of approximately 6.6 Bcf, and 3.5 Bcf LNG storage is provided by Hopkinton LNG Corp. in facilities located in two different locations in Massachusetts. EGMA has firm underground storage contracts and total storage capacity entitlements of approximately 8.8 Bcf, and 1.8 Bcf LNG and LPG storage is provided by Hopkinton LNG Corp. in facilities located at seven different locations in Massachusetts.

 PURA requires Yankee Gas to meet the needs of its firm customers under all weather conditions. Specifically, Yankee Gas must structure its supply portfolio to meet firm customer needs under a design day scenario (defined as the coldest day in 30 years) and under a design year scenario (defined as the average of the four coldest years in the last 30 years). Yankee Gas also maintains a flexible resource portfolio consisting of natural gas supply contracts, transportation contracts on interstate pipelines, off-system storage and its on-system 1.2 Bcf LNG storage facility in Connecticut to meet consumption needs during the coldest days of winter. Yankee Gas obtains its interstate capacity from the three interstate pipelines that directly serve Connecticut: the Algonquin, Tennessee and Iroquois Pipelines, which connect to other upstream pipelines that transport natural gas from major natural gas producing regions, including the Gulf Coast, Mid-continent, Canadian regions and Appalachian Shale supplies.

 Based on information currently available regarding projected growth in demand and estimates of availability of future supplies of pipeline natural gas, each of NSTAR Gas, EGMA and Yankee Gas believes that in order to meet the long-term firm customer requirements in a reliable manner, a combination of pipeline, storage, and non-pipeline solutions will be necessary.

 WATER DISTRIBUTION SEGMENT

 Aquarion Company (Aquarion) operates five separate regulated water utilities in Connecticut (Aquarion Water Company of Connecticut, or AWC-CT, and The Torrington Water Company), Massachusetts (Aquarion Water Company of Massachusetts, or AWC-MA), and New Hampshire (Aquarion Water Company of New Hampshire, or AWC-NH, and Abenaki Water Company). These regulated companies provide water services to approximately 248,000 residential, commercial, industrial, municipal and fire protection and other customers, in 73 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, 2024, approximately 91 percent of Aquarion's customers were based in Connecticut.

 Rates

 Aquarion's water utilities are subject to regulation by the PURA, the DPU and the NHPUC in Connecticut, Massachusetts and New Hampshire, respectively. These regulatory agencies have jurisdiction over, among other things, rates, certain dispositions of property and plant, mergers and consolidations, issuances of long-term securities, standards of service and construction and operation of facilities.

 Aquarion's general rate structure consists of various rate and service classifications covering residential, commercial, industrial, and municipal and fire protection services.

 The rates established by the PURA, DPU and NHPUC are comprised of the following:

 • A base rate, which is comprised of fixed charges based on meter/fire connection sizes, as well as volumetric charges based on the amount of water sold. Together these charges are designed to recover the full cost of service resulting from a general rate proceeding.

 • In Connecticut, a revenue adjustment mechanism (RAM) that reconciles earned revenues, with certain allowed adjustments, on an annual basis, to the revenue requirement approved by PURA.

 • In Connecticut and New Hampshire, a water infrastructure conservation adjustment (WICA) charge, and in Massachusetts, an annual main replacement adjustment mechanism (MRAM) charge, which is applied between rate case proceedings and seeks recovery of allowed costs associated with eligible infrastructure improvement projects placed in-service. The WICA is updated semi-annually in Connecticut and annually in New Hampshire. In Connecticut, an annual WICA reconciliation mechanism reconciles earned WICA revenue to the approved WICA revenue with any differences refunded to, or recovered from, customers.

 Distribution Rate Cases: On August 29, 2022, Aquarion Water Company of Connecticut (AWC-CT) filed an application with PURA to amend its existing rate schedules. On March 15, 2023, PURA issued a final decision that rejected AWC-CT's application with PURA, which was subsequently appealed by AWC-CT. On March 25, 2024, the State of Connecticut Superior Court issued a decision on the appeal and on March 28, 2024, AWC-CT filed an appeal of the Connecticut Superior Court decision. On July 31, 2024, PURA issued a final decision and increased AWC-CT's approved revenue requirement by $0.1 million above the amount authorized in the March 15, 2023 decision, which was also subsequently appealed by AWC-CT. Both appeals are pending. For further information, see "Regulatory Developments and Rate Matters - Connecticut" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Aquarion's Massachusetts base distribution rates were established in a 2018 DPU-approved rate case. Aquarion's New Hampshire base distribution rates were established in a July 2022 NHPUC-approved rate case settlement agreement, with a single step adjustment approved on January 19, 2023. Rates were effective March 1, 2023.

 Sources and Availability of Water Supply

 Our water utilities obtain their water supplies from owned surface water sources (reservoirs) and groundwater supplies (wells) with a total supply yield of approximately 135 million gallons per day, as well as water purchased from other water suppliers. Approximately 98 percent of our annual production is self-supplied and processed at ten surface water treatment plants and numerous well stations, which are all located in Connecticut, Massachusetts, and New Hampshire.

 The capacities of Aquarion's sources of supply, and water treatment, pumping and distribution facilities, are considered sufficient to meet the present requirements of Aquarion's customers under normal conditions. On occasion, drought declarations are issued for portions of Aquarion's service territories in response to extended periods of dry weather conditions.

 CAPITAL EXPENDITURES

 For information on capital expenditures and projects during 2024, as well as projected capital expenditures by business, see "Business Development and Capital Expenditures" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations.

 FINANCING

 For information regarding short-term and long-term debt agreements, see "Liquidity" in the accompanying Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, and Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt," of the Combined Notes to Financial Statements.

 NUCLEAR FUEL STORAGE

 CL&P, NSTAR Electric, PSNH, and several other New England electric utilities are stockholders in three inactive regional nuclear generation companies, CYAPC, MYAPC and YAEC (collectively, the Yankee Companies). The Yankee Companies have completed the physical decommissioning of their respective nuclear power facilities and are now engaged in the long-term storage of their spent nuclear fuel. The Yankee Companies fund these costs through litigation proceeds received from the DOE and, to the extent necessary, through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric and PSNH. CL&P, NSTAR Electric and PSNH, in turn recover these costs from their customers through state regulatory commission-approved retail rates. The Yankee Companies collect amounts that we believe are adequate to recover the remaining plant closure and fuel storage cost estimates for the respective plants. We believe CL&P and NSTAR Electric will recover their shares of these obligations from their customers. PSNH has recovered its total share of these costs from its customers.

 We consolidate the assets and obligations of CYAPC and YAEC on our consolidated balance sheet because our ownership and voting interests are greater than 50 percent of each of these companies.

 OTHER REGULATORY AND ENVIRONMENTAL MATTERS

 General

 We are regulated by various federal and state agencies, including FERC, the SEC, and various state and/or local regulatory authorities with jurisdiction over the industry and the service areas in which each of our companies operates, including the PURA, which has jurisdiction over CL&P, Yankee Gas, and Aquarion, the DPU, which has jurisdiction over NSTAR Electric, NSTAR Gas, EGMA and Aquarion, and the NHPUC, which has jurisdiction over PSNH and Aquarion.

 Renewable Portfolio Standards

 Each of the states in which we do business has Renewable Portfolio Standards (RPS) requirements, which generally require fixed percentages of our energy supply to come from renewable energy sources such as solar, wind, hydropower, landfill gas, fuel cells and other similar sources.

 Connecticut's RPS statute requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2024, the total RPS obligation was 37.0 percent and will ultimately reach 48.0 percent in 2030. CL&P is permitted to recover any costs incurred in complying with RPS from its customers through its generation service charge rate.

 Massachusetts' RPS program requires electricity suppliers to meet renewable energy standards. For 2024, the RPS and Clean Energy Standard (CES) requirements were 62.3 percent, and will ultimately reach 63.1 percent in 2025. Massachusetts electric suppliers were also required to meet Alternative Energy Portfolio Standards (APS) of 6.0 percent and Clean Peak Energy Standards (CPS) of 4.0 percent in 2024. Those requirements will reach 6.25 and 5.5 percent in 2025, respectively. NSTAR Electric is permitted to recover any costs incurred in complying with these requirements from its customers through rates. NSTAR Electric also owns renewable solar power facilities. The RECs generated from NSTAR Electric's solar power facilities are sold to other energy suppliers, and the proceeds from these sales are credited back to customers.

 New Hampshire's RPS provision requires increasing percentages of the electricity sold to retail customers to have direct ties to renewable sources. In 2024, the total RPS obligation was 24.3 percent and it will ultimately reach 25.2 percent in 2025. The costs of the RECs are recovered by PSNH through rates charged to customers.

 Environmental Regulation and Matters

 We are subject to various federal, state and local environmental legislation and regulation with respect to water quality, air quality, natural/working lands (wetlands, water resource areas that include land that borders a body of water, plant/animal habitat), hazardous materials and other environmental matters. Our environmental policy includes formal procedures and a task-scheduling system in place to help ensure environmental compliance. The Governance, Environmental and Social Responsibility Committee of Eversource's Board of Trustees also provides oversight of climate issues, environmental matters and compliance. We also identify and address potential environmental risks through our Enterprise Risk Management (ERM) program in addition to rigorous audits of our facilities, vendors, and processes.

 Additionally, projects may not be constructed or significantly modified without a review of the environmental impact of the proposed construction or modification by the applicable federal or state agencies. Many of our construction projects require the submission of comprehensive permitting applications to various local, state and federal agencies. The permits we receive outline various best management practices and restoration requirements to address construction period-impacts.

 We have recorded a liability for what we believe, based upon currently available information, is our reasonably estimable environmental investigation, remediation, and/or natural resource damages costs for waste disposal sites for which we have probable liability. Under federal and state law, government agencies and private parties can attempt to impose liability on us for recovery of investigation and remediation costs at contaminated sites. As of December 31, 2024, the liability recorded for our reasonably estimable and probable environmental remediation costs for known sites needing investigation and/or remediation, exclusive of recoveries from insurance or from third parties, was $128.0 million, representing 65 sites. These costs could be significantly higher if additional remediation becomes necessary or when additional information as to the extent of contamination becomes available.

 The most significant liabilities currently relate to future clean-up costs at former MGP facilities. These facilities were owned and operated by our predecessor companies from the mid-1800's to mid-1900's. By-products from the manufacture of natural gas using coal resulted in fuel oils, hydrocarbons, coal tar, purifier wastes, metals and other waste products that may pose a potential risk to human health and the environment. We currently have partial or full ownership responsibilities at former MGP sites that have a reserve balance of $115.9 million of the total $128.0 million as of December 31, 2024. MGP costs are recoverable through rates charged to our customers.

 When planning environmental investigations and remediation of impacted properties, we work closely with the municipalities and environmental regulators to ensure that our remediation plans adhere to applicable regulations while protecting human health and the environment. In many cases, these remediation projects are designed to address opportunities for beneficial reuse of the property.

 Global Climate Change and Greenhouse Gas Emission Issues

 Eversource assesses the regulatory, physical and transitional impacts related to climate change to develop mitigation strategies including evaluating the impacts of more severe and frequent weather events, financial risks, changing customer behaviors, and opportunities to reduce emissions in our operations and for the region through clean energy and emerging technologies investments.

 Regulatory Impacts of Climate Change: Global climate change has received focus from the federal and state governments. Some of the states in which we operate have aggressive climate goals and implementation plans. In Connecticut, legislation includes a target to achieve zero-carbon electricity by 2040. In response to the 2021 Massachusetts climate legislation calling for increased electrification of the transportation and building sectors, in 2023, Eversource developed an Electric Sector Modernization Plan (ESMP) detailing steps the Company will take over the next five and ten years to help ensure reliability and resiliency while supporting a clean energy future. Approved by the DPU in 2024, the ESMP includes incremental spending for interconnections of clean energy and resiliency initiatives and corresponding cost recovery will be established in 2025. Similarly, the Massachusetts "Future of Gas" docket (DPU 20-80) specified measures for natural gas local distribution companies to support the state's net zero by 2050 climate goal. These state regulations and related policies may introduce risks and opportunities to our businesses if demands for energy change. The prior administration had communicated a strong focus on addressing climate change by setting a U.S. target of reducing greenhouse gas (GHG) emissions by 50 percent by 2030, compared to 2005 levels, and achieving net-zero emissions by 2050 economy-wide. The plan called for aggressive measures focused on clean transportation, clean energy and climate investments targeted at environmental justice communities. In support of this plan, federal funding and incentive programs for clean transportation and energy have offered opportunities for Eversource to invest in projects that have the ability to reduce emissions in the region while benefiting our communities and shareholders. Under the new administration there is uncertainty about the future of this funding and other clean energy policies, and the potential impact it may have on future projects. In addition, the states we operate in may respond to the federal policy shift with enhancements to existing clean energy programs, creating additional opportunities.

 Eversource continually evaluates the evolving regulatory landscape concerning climate change, which could potentially lead to additional requirements, rules and regulations that could impact how we operate our businesses. Potential future environmental statutes, regulations, policies and reporting metrics for rate cases that address climate change could impose significant additional costs and there can be no assurance that regulators will approve the recovery of those costs.

 Physical and Transitional Impacts of Climate Change: Eversource assesses the physical impacts of climate change that are presented in the form of weather or natural events or due to longer-term shifts in climate patterns, as well as transitional impacts related to a shift to a lower-carbon economy and changes to address mitigation and adaptation requirements. To address physical and transitional impacts related to climate change, maintain resiliency across our system, and enable potential opportunities for our business, we are pursuing the following actions:

 • Improving our system resiliency in response to climate change through vegetation management, pole and wire strengthening, flood proofing, and other system hardening measures;
 • Conducting climate modeling to assess vulnerable regions and infrastructure in order to prioritize hazard mitigation projects;
 • Implementing a grid modernization plan that will enhance our electric distribution infrastructure to improve resiliency and reliability and increase opportunities to facilitate integration of distributed energy resources, electric vehicle infrastructure, and electrification of building heat;
 • Focusing on improving the efficiency of our electric and natural gas distribution systems, preparing for increased opportunities that clean energy advancements create, and providing customers with ways to optimize their energy efficiency;
 • Pursuing new technologies and incentives for decarbonization of energy in the sectors that both we and our customers operate in;
 • Evaluating opportunities for our natural gas system and exploring alternative, less carbon-intensive technologies like networked geothermal for heating and cooling; and
 • Investigating emerging technologies such as energy storage and automation programs that improve reliability.

 Physical risks from climate change may be acute due to increased severity of extreme weather events or chronic due to changes in precipitation patterns and extreme variability in weather patterns, rising mean temperatures and/or rising sea levels and shifting weather conditions, such as changes in precipitation, extreme heat, more frequent and severe storms, droughts, wildfires and floods. These risks may result in customers' energy and water usage increasing or decreasing depending on the duration and magnitude of the changes, degradation of water quality and our ability to reliably deliver our services to customers. Severe weather may cause outages, potential disruption of operations and property damage to our assets.

 Our actions to improve system reliability and resiliency allow our business to operate under changing conditions and meet customer expectations. System improvements are designed to withstand severe weather impacts and include installing new and stronger infrastructure like poles, wires and related system equipment, as well as enhanced year-round tree trimming. We are reinforcing existing critical facilities to withstand storm surges and future substations are being "flood hardened" to better protect our system against storm surges associated with the increasing risk of severe weather in the states that support this work. We created our comprehensive emergency preparedness and response plans in partnership with state and community leaders so that when a storm occurs, we can provide customers and municipalities with timely and accurate information, while safely and promptly restoring power. Additionally, we collaborate with other utility providers and industry partners across the country to better understand storm hazards and develop solutions to improve our system reliability.

 Eversource set a GHG reduction goal in 2019 to reduce Scope 1 and 2 emissions from our operations and reach carbon neutrality by 2030. This goal addresses emissions from our operations primarily in the form of line loss (emissions associated with the energy lost when power is transmitted and distributed across the electric system), methane leaks from our natural gas distribution system, fuel consumption from our facilities and vehicle fleet, and sulfur hexafluoride (SF6) leaks from electric equipment. Initiatives to reduce GHG emissions have resulted in a 30% reduction in emission from 2018 to 2023 from initiatives including improved energy efficiency at our buildings, utilizing alternative fuels and introducing more hybrid and electric vehicles into the company fleet, reducing fugitive emissions of methane by replacing leak-prone natural gas pipes, improving maintenance of SF6 gas-insulated electrical equipment, and piloting innovative SF6-free technologies thereby reducing SF6 emissions and supporting the overall interconnection of clean energy to the region thereby helping reduce the carbon intensity of line losses across the electric grid. Progress towards this target is reported at least annually through a third-party-verified GHG emission inventory. We are also looking to introduce an expanded target that will place a greater emphasis on the indirect Scope 3 emissions from our customers' energy use. An expanded target that aligns with the climate policies and regulations of the states where we operate will be introduced in early 2025.

 Our business is also exposed to climate-related transitional impacts, such as policy, legal and reputational impacts and technology and market changes as we enable broad decarbonization of the electrical and building sectors in support of regional policies and targets. We actively support local, state and federal emission reduction goals to address climate change and pursue climate-related opportunities that enable continued business success while serving the needs of our customers. Our investments help reduce regional emissions while improving shareholder value. Meanwhile, our energy efficiency solutions and electric vehicle infrastructure investments allow our customers to make choices that minimize climate-related impacts.

 Additionally, as our business transitions to support a more energy diverse economy, human capital needs will also change with the potential to impact our workforce. As new technologies are implemented, we will need to recruit, develop and possibly retrain employees to meet the need for new skill sets.

 Electric and Magnetic Fields

 For more than forty years, published reports have discussed the possibility of adverse health effects from electric and magnetic fields (EMF) associated with electric transmission and distribution facilities, including appliances, and wiring in buildings and homes. Some epidemiology studies have reported a possible statistical association between adverse health effects and exposure with EMF. The association identified in some of these studies remain unexplained and inconclusive. Numerous scientific review panels, considering all significant EMF epidemiology and laboratory studies, have concluded that the available body of scientific information does not support a conclusion that EMF affects human health at levels expected in the vicinity. In accordance with recommendations of various regulatory bodies and public health organizations, we use design principles that help reduce potential EMF exposures associated with new transmission lines.

 HUMAN CAPITAL

 Eversource is committed to delivering reliable energy and superior customer service; expanding energy options for our region; environmental stewardship; a safe and fairly compensated workforce; and community service and leadership. Our employees are critical to achieving this mission and we recognize the importance of attracting, retaining, and developing the most qualified individuals and ensuring fairness and equal employment opportunity for all. Leaders at all levels strive to create a workplace where our employees are engaged, empowered, advocate for the customer, work collaboratively, raise ideas for improvement and focus on delivering superior customer experience. We build employee engagement through continuous communication, talent development, and fostering teamwork. We have established metrics and annual goals on our corporate scorecard, including safety performance, talent management and employee engagement, that drive accountability for progress across the business.

 As of December 31, 2024, Eversource Energy employed a total of 10,680 employees, excluding temporary employees, of which 1,599 were employed by CL&P, 2,185 were employed by NSTAR Electric, and 848 were employed by PSNH. In addition, 4,286 were employed by Eversource Service, Eversource's service company, that provides support services to all Eversource operating companies. Approximately 48 percent of our employees are members of the International Brotherhood of Electrical Workers, the Utility Workers Union of America or The United Steelworkers, and are covered by various collective bargaining agreements.

 Safety. At Eversource, our commitment to "Safety First and Always" is a principle and a mindset present in every job and every task, whether in the field, office or at home. A priority at Eversource is continuous improvement and safety is at the forefront as we continue to build a strong safety culture, embrace new technologies, and learn with our industry and community partners to improve safety performance. We provide safety training and perform field safety job observations of both internal and contractor crews with a focus on high-energy hazards. We use metrics such as Days Away Restricted Time (DART) and High Energy Field Observations, among others, to monitor safety performance. Our DART safety performance was 0.76 in 2024, measured by days away, restricted or transferred per 100 workers, using the DART-OSHA method of measurement.

 Engagement. We believe an engaged workforce and culture of respect contribute to our success and sustainability by driving innovation and creating trusted relationships with our employees, customers, suppliers, and community partners. We support and continue to seek to identify many programs and agencies that address the specific challenges and particular issues facing each of the communities we serve. We are committed to merit-based hiring practices that emphasize recruiting the most qualified individuals, ensuring fairness and equal employment opportunity for all candidates, and we encourage our employees to embrace different perspectives and experiences in our workplace and within our communities.

 Eversource's executive leadership team promotes and supports a culture of engagement by building and leading high performing and dynamic teams, where employees' voices and contributions can deliver superior customer service and an engaged workplace culture. Leaders are committed to growing a pipeline of exceptional talent, leveraging multiple perspectives to improve customer service, and engaging with the many communities we serve. Our Business Resource Groups provide our leaders with valuable feedback on the impact of our decisions on workforce engagement and job satisfaction.

 Eversource's Board of Trustees also is committed to overseeing a high-performing and engaged workforce at Eversource. The Board receives regular monthly progress updates on human capital and employee engagement activities. The Corporate Governance, Environmental and Social Responsibility Committee of the Board of Trustees is responsible for the oversight of environmental, human capital management and social responsibility strategies, programs, and policies. The Board of Trustees seeks a diversity of experiences and professional perspectives when considering Trustee candidates.

 Compensation, Health and Wellness Benefits. Eversource is committed to the health, safety and wellness of our employees. We provide competitive compensation and comprehensive benefit packages, including healthcare, life insurance, sick time and disability plans, death benefits, retirement plans (defined benefit pension plans or 401k Plan), an Employee Stock Purchase Plan, health savings and flexible spending accounts, paid time off, employee assistance programs, and tuition assistance, among many others. Eversource also provides wellness programs and benefits to encourage employees and their families to adopt and maintain healthy lifestyle habits. Eversource has established flexible work guidelines and offers hybrid work arrangements to employees in applicable positions.

 Talent Development, Training Programs and Education Opportunities. Strategic workforce plans are developed every year as part of the annual business planning process to address immediate and long-range resource needs and to ensure that Eversource acquires, develops, and retains the most qualified individuals. We provide employees with education and experiences that broaden the reach of our brand through our Employee Value Proposition, the messaging that Eversource provides to staff, investors, customers and job candidates regarding our commitment to our values, rewards and recognition, and company culture of respect and engagement. Employee development programs are aligned to our strategic workforce plan to support succession within all levels of the organization. Continuous professional development is important to support our employees' ongoing success. These professional development programs include leadership effectiveness programs designed to develop new and current supervisors; a talent management process to identify high potential and emerging talent and ensure their development; multiple early career development programs in Engineering, Transmission and Operations; educational and professional development opportunities for employees who are recent college graduates; tuition assistance program; paid internships and co-ops; and workforce development programs focused on building a talent pipeline for our technical craft roles.

 We leverage educational partnerships in critical trade and technical areas and have developed proactive sourcing strategies to attract experienced workers in highly technical roles in engineering, electric and gas operations, and energy efficiency. As part of this process, Eversource identifies critical roles and develops succession plans to ensure we have a capable supply of talent for the future.

 Community & Social Impact. Eversource and our employees support many nonprofit organizations and programs that make a positive difference in the lives of our customers and the communities that we serve. The Eversource Foundation provides grants to charitable organizations that help to make broad, meaningful, and sustainable change for the communities we serve. Our employees also lend their time and talents to volunteer with charitable organizations that address local high-priority concerns and needs. Our goal at Eversource is to lend a hand to organizations that really make a difference in the communities where we live and work.

 See our 2023 Sustainability Report and our 2023 Diversity, Equity and Inclusion Report located on our website, for more detailed information regarding our human capital programs and initiatives. Nothing on our website, including our Sustainability Report, our Diversity, Equity and Inclusion Report, or sections thereof, shall be deemed incorporated by reference into this Annual Report.

 INTERNET INFORMATION

 Our website address is www.eversource.com. We make available through our website a link to the SEC's EDGAR website ( at which site Eversource's, CL&P's, NSTAR Electric's and PSNH's combined Annual Reports on Form 10-K, combined Quarterly Reports on Form 10-Q, Current Reports on Form 8-K and any amendments to those reports may be reviewed. Information contained on the Company's website or that can be accessed through the website is not incorporated into and does not constitute a part of this Annual Report on Form 10-K. Printed copies of these reports may be obtained free of charge by writing to our Investor Relations Department at Eversource Energy, 247 Station Drive, Westwood, MA 02090.

 Item 1A. Risk Factors

 In addition to the matters set forth under "Safe Harbor Statement Under the Private Securities Litigation Reform Act of 1995" included immediately prior to Item 1, Business, above, we are subject to a variety of material risks. Our susceptibility to certain risks, including those discussed in detail below, could exacerbate other risks. These risk factors should be considered carefully in evaluating our risk profile. There may be additional risks and uncertainties (either currently unknown or not currently believed to be material) that could adversely affect our financial position, results of operations, and cash flows.

 Cybersecurity Threats and Attacks:

 Cyberattacks, including acts of war or terrorism, targeted directly on or indirectly affecting our systems or the systems of third parties on which we rely, could severely impair operations, negatively impact our business, lead to the disclosure of confidential information and adversely affect our reputation.

 Cyberattacks that seek to exploit potential vulnerabilities in the utility industry and seek to disrupt electric, natural gas and water transmission and distribution systems are increasing in sophistication, magnitude and frequency. Various geo-political conflicts and acts of war around the world continue to result in increased cyberattacks against critical infrastructure. A successful cyberattack on the information technology systems that control our transmission, distribution, natural gas and water systems or other assets could impair or prevent us from managing these systems and facilities, operating our systems effectively, or properly managing our data, networks and programs. The breach of certain information technology systems could adversely affect our ability to correctly record, process and report financial information. A major cyber incident could result in significant expenses to investigate and to repair system damage or security breaches and could lead to litigation, fines, other remedial action, heightened regulatory scrutiny and damage to our reputation.

 We have instituted safeguards to protect our information technology systems and assets. We deploy substantial technologies to system and application security, encryption and other measures to protect our computer systems and infrastructure from unauthorized access or misuse. Specifically, regarding vulnerabilities, we patch systems timely where patches are available to deploy, and have technologies that detect exploits of vulnerabilities and proactively block the exploit when it happens. We also interface with numerous external entities to improve our cybersecurity situational awareness. The FERC, through the North American Electric Reliability Corporation (NERC), requires certain safeguards to be implemented to deter cyberattacks. These safeguards may not always be effective due to the evolving nature of cyberattacks. We maintain cyber insurance to cover damages, potential ransom and defense costs related to breaches of networks or operational technology, but it may be insufficient in limits and coverage exclusions to cover all losses.

 Any such cyberattacks could result in loss of service to customers and a significant decrease in revenues, which could have a material adverse impact on our financial position, results of operations, and cash flows.

 For further information, see Item 1C, Cybersecurity included in this Annual Report on Form 10-K.

 The unauthorized access to, and the misappropriation of, confidential and proprietary Company, customer, employee, financial or system operating information could adversely affect our business operations and adversely impact our reputation.

 In the regular course of business, we, and our third-party suppliers, rely on information technology to maintain sensitive Company, customer, employee, financial and system operating information. We are required by various federal and state laws to safeguard this information. Cyber intrusions, security breaches, theft or loss of this information by cybercrime or otherwise could lead to the release of critical operating information or confidential Company, customer or employee information, which could adversely affect our business operations or adversely impact our reputation, and could result in significant costs, fines and litigation. We employ system controls to prevent the dissemination of certain confidential information and periodically train employees on phishing risks. We maintain cyber insurance to cover damages, costs related to a system disruption, potential ransom and defense costs arising from unauthorized disclosure of, or failure to protect, private information, as well as costs for notification to, or for credit monitoring of, customers, employees and other persons in the event of a breach of private information. This insurance covers amounts paid to address a network attack or the disclosure of personal information, and costs of a qualified forensics firm to determine the cause, source and extent of a network attack or to investigate, examine and analyze our network to find the cause, source and extent of a data breach, but it may be insufficient to cover all losses. While we have implemented measures designed to prevent network attacks and mitigate their effects should they occur, these measures may not be effective due to the continually evolving nature of efforts to access confidential information.

 Regulatory, Legislative and Compliance Risks:

 The actions of regulators and legislators could result in outcomes that may adversely affect our earnings and liquidity.

 The rates that our electric, natural gas and water companies charge their customers are determined by their state regulatory commissions. These commissions also regulate the companies' accounting, operations, the issuance of certain securities and certain other matters. The FERC regulates the transmission of electric energy, the sale of electric energy at wholesale, accounting, issuance of certain securities and certain other matters, including reliability standards through the NERC. The regulatory process may be adversely affected by the political, regulatory and economic environment in the states in which we operate.

 Under state and federal law, our electric, natural gas and water companies are entitled to charge rates that are sufficient to allow them an opportunity to recover their prudently incurred operating and capital costs and a reasonable rate of return on invested capital, to attract needed capital and maintain their financial integrity, while also protecting relevant public interests. Our electric, natural gas and water companies are required to engage in regulatory approval proceedings as a part of the process of establishing the terms and rates for their respective services. Each of these companies prepares and submits periodic rate filings with their respective state regulatory commissions for review and approval, which allows for various entities to challenge our current or future rates, structures or mechanisms and could alter or limit the rates we are allowed to charge our customers. These proceedings typically involve multiple parties, including governmental bodies and officials, consumer advocacy groups, and various consumers of energy, who have differing concerns. Any change in rates, including changes in allowed rate of return, are subject to regulatory approval proceedings that can be contentious, lengthy, and subject to appeal. This may lead to uncertainty as to the ultimate result of those proceedings. Established rates are also subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed, including cost recovery mechanisms. The ultimate outcome and timing of regulatory rate proceedings or challenges to certain provisions in our distribution tariffs could have a significant effect on our ability to recover costs timely or at all or earn an adequate return. Adverse decisions in our proceedings could adversely affect our credit ratings, financial position, results of operations, and cash flows.

 The federal, state and local political and economic environment currently has, and may in the future have, an adverse effect on regulatory decisions with negative consequences for us. These regulatory decisions currently, and may in the future, require us 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. There can be no assurance that regulators will approve the recovery of all costs incurred by our electric, natural gas and water companies, including costs for construction, operation and maintenance, and storm restoration. The inability to recover a significant amount of operating costs in a timely manner or at all could have an adverse effect on our credit ratings, financial position, results of operations, and cash flows. Changes to rates may occur at times different from when costs are incurred. Additionally, catastrophic events at other utilities could result in our regulators and legislators imposing additional requirements that may lead to additional costs for the companies. In addition to the risk of disallowance of incurred costs, regulators may also impose downward adjustments in a company's allowed ROE as well as assess penalties and fines. These actions would have an adverse effect on our credit ratings, financial position, results of operations, and cash flows.

 We continue to experience challenges related to the regulatory environment in Connecticut with respect to our electric distribution, natural gas, and water businesses. S&P recently downgraded the credit ratings of Eversource and its regulated utilities as a result of the challenging regulatory environment in Connecticut.

 The FERC has jurisdiction over our transmission costs recovery and our allowed ROEs. If FERC changes its methodology on developing ROEs, there could be a negative impact on our results of operations and cash flows. Additionally, certain outside parties have filed four complaints against transmission-owning electric companies within ISO-NE alleging that our allowed ROEs are unjust and unreasonable. An adverse decision in any of these four complaints could adversely affect our financial position, results of operations, and cash flows.

 The FERC also has jurisdiction over our transmission rate incentives such as the regional transmission organization (RTO) participation ROE incentive adder, CWIP in rate base incentive and the abandoned plant incentive. If the FERC changes its policies regarding these incentives, there could be a negative impact on our financial position, results of operations, and cash flows. Additionally, the FERC issued a Supplemental Notice of Proposed Rulemaking (NOPR) on Transmission Incentives that proposes to eliminate the existing RTO ROE incentive adder for utilities that have been participating in an RTO for more than three years. A FERC decision approving this proposal could adversely affect our financial position, results of operations, and cash flows.

 FERC's policy has encouraged competition for transmission projects, even within existing service territories of electric companies, as it looks to expand the transmission system to accommodate state and federal policy goals to utilize more renewable energy resources as well as to enhance reliability and resilience for extreme weather events. Implementation of FERC's goals, including within our service territories, may expose us to competition for construction of transmission projects, additional regulatory considerations, and potential delay with respect to future transmission projects, which may adversely affect our results of operations and lower rate base growth.

 Changes in tax laws, as well as the potential tax effects of business decisions could negatively impact our business, financial position, results of operations, and cash flows.

 We are exposed to significant reputational risks, which make us vulnerable to increased regulatory oversight or other sanctions.

 Because utility companies, including our electric, natural gas and water utility subsidiaries, have large customer bases, they are subject to adverse publicity focused on the safety and 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, including those related to climate change.

 Adverse publicity of this nature could harm our reputation and the reputation of our subsidiaries; may make state legislatures, utility commissions and other regulatory authorities less likely to view us in a favorable light; and may cause us to be subject to less favorable legislative and regulatory outcomes, legal claims or increased regulatory oversight. Unfavorable regulatory outcomes can include more stringent laws and regulations governing our operations, such as reliability and customer service quality standards or vegetation management requirements, as well as fines, penalties or other sanctions or requirements. Further, we rely upon purchased power and purchased natural gas supply from third parties to meet customers' energy requirements. Due to a variety of factors, including the inflationary economic environment, geo-political conflicts, increased customer energy demand, the cost of energy supply, and public benefit charges assessed by our regulators, customer bills in New England remain high. We also may be required to implement rolling blackouts by ISO-NE, the region's independent grid operator if enough capacity is not available in the area to meet peak demand needs. Significant cost increases, as well as any failure to meet customer energy requirements, could negatively impact the satisfaction of our customers and our customers' ability to pay their utility bills, which could have an adverse impact on our business, reputation, financial position, results of operations, and cash flows.

 Addressing any adverse publicity, regulatory 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 our business, on the morale and performance of our employees and on our relationships with respective regulators, customers and counterparties. We are unable to predict future legislative or regulatory changes, initiatives or interpretations or other legal proceedings, and there can be no assurance that we will be able to respond adequately to such actions. The direct and indirect effects of negative publicity, and the demands of responding to and addressing it, may have a material adverse effect on our financial position, results of operations, and cash flows.

 Costs of compliance with environmental laws and regulations, including those related to climate change, may increase and have an adverse effect on our business and results of operations.

 Our subsidiaries' operations are subject to extensive and increasing federal, state and local environmental statutes, rules and regulations that govern, among other things, water quality (including treatment of PFAS (Per- and Polyfluoroalkyl Substances) and lead), water discharges, the management of hazardous material and solid waste, and air emissions including greenhouse gases. Compliance with these requirements requires us to incur significant costs relating to environmental permitting, monitoring, maintenance and upgrading of facilities, remediation, and reporting. For our water business, compliance with water quality regulations, including those for PFAS and lead, could require the construction of facilities and replacement of customer lead service lines, respectively.

 The costs of compliance with existing legal requirements or legal requirements not yet adopted may increase in the future. Although we have recorded liabilities for known environmental obligations, these costs can be difficult to estimate due to uncertainties about the extent of contamination, remediation alternatives, the remediation levels required by state and federal agencies, and the financial ability of other potentially responsible parties. An increase in such costs, unless promptly recovered, could have an adverse impact on our business and our financial position, results of operations, and cash flows.

 In each of the states that we operate, there are requirements for purchases of renewable energy credits from the generation of renewable energy. As the requirement for credits increase and outpace the renewable energy coming online, we may be required to pay higher prices and make alternative compliance payments to the states. Unless renewable energy availability is increased to meet these credit requirements, we will face the risk of increasing costs.

 For further information, see Item 1, Business – Other Regulatory and Environmental Matters, included in this Annual Report on Form 10-K.

 Offshore Wind Contingent Liability and Tax Risk:

 Variability in the costs and final investment returns of the Revolution Wind and South Fork Wind offshore wind projects no longer owned by Eversource and the inability to monetize investment tax credits and investment tax credit adders could have an adverse impact on our financial position, results of operations, and cash flows.

 We completed the sales of our offshore wind investments in 2024. Following the sale of our 50 percent ownership share in the South Fork Wind and Revolution Wind projects, we have continuing financial exposure as it relates to the purchase price post-closing adjustment payments under the terms of the sale agreement with Global Infrastructure Partners (GIP) for these projects. Our future obligations under the sale terms primarily include a capital expenditure overrun sharing obligation, an obligation to maintain GIP's internal rate of return through the construction period for each project, and obligation for other future costs. Post-closing purchase price adjustment payments will be made following the commercial operation of Revolution Wind. Factors that could increase the post-closing adjustment payments owed to GIP include the ultimate cost of construction and extent of cost overruns for Revolution Wind, delays in construction, which would impact the economics associated with the purchase price adjustment, and Revolution Wind's eligibility for federal investment tax credits (ITCs) at a lower value than assumed and included in the purchase price. New information that becomes available or future developments that arise as construction progresses and as cost estimates are reviewed and revised could result in increased costs of the project that would ultimately be owed to GIP. Adverse changes in facts and circumstances could increase the obligation under the sale agreement above the amount accrued and result in additional losses, which could have a material adverse effect on our financial position, results of operations, and cash flows.

 The purchase price included the sales value related to a 40 percent level of federal ITCs, 10 percent of which is the energy community ITC adder included in the Inflation Reduction Act related to Revolution Wind. If the project does not meet the qualifications under federal tax law for the full value of the ITC or there are changes to tax law, it could have a material adverse effect on our financial position, results of operations, and cash flows.

 Additionally, we hold a tax equity investment in South Fork Wind that is expected to result in cash flow benefits from ITCs at a 30 percent level. The tax deductibility of the ITCs could be challenged. If the project does not meet the qualifications under federal tax law, we may be unable to monetize the ITCs that support this investment, which could have a material adverse effect on our financial position, results of operations, and cash flows.

 Risks Related to the Environment and Catastrophic Events:

 The effects of climate change, including severe storms, could cause significant damage to any of our facilities requiring extensive expenditures, the recovery for which is subject to approval by regulators.

 Climate change creates physical and financial risks to our operations. Physical risks from climate change may include an increase in sea levels and changes in weather conditions, such as changes in precipitation, extreme heat and weather events, including the effects of significantly stronger wind-related events. Customers' energy and water needs vary with weather conditions, primarily related to temperature and humidity. For residential customers, heating and cooling represent their largest energy use. For water customers, conservation measures imposed by the communities we serve could impact water usage. To the extent weather conditions are affected by climate change, customers' energy and water usage could increase or decrease depending on the duration and magnitude of the changes.

 Severe weather induced by climate change, such as extreme and frequent ice and snowstorms, tornadoes, micro-bursts, hurricanes, floods, droughts, wildfires, excess humidity and other natural or weather-related phenomenon, may cause outages and property damage, which may require us to incur additional costs that may not be recoverable from customers. The cost of repairing damage to our operating subsidiaries' facilities and the potential disruption of their operations due to the increase in frequency and severity of storms, natural disasters or other catastrophic events could be substantial, particularly as regulators and customers demand better and quicker response times to outages. If, upon review, any of our state regulatory authorities finds that our actions were imprudent, some of those restoration costs may not be recoverable from customers and could result in penalties or fines. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations, and cash flows. We maintain property insurance, but it may be insufficient in limits and coverage exclusions to cover all losses. Additionally, these types of weather events risk interruption of the supply chain and could disrupt the delivery of goods and services required for our operations.

 Transitional impacts related to climate change may have an adverse effect on our business and results of operations due to costs associated with new technologies, evolving customer expectations and changing workforce needs.

 Initiatives to mitigate the impacts of climate change, support a transition to cleaner energy, and reduce emissions, may have a material adverse financial impact to our business. These impacts include the costs associated with the development and implementation of new technologies to maintain system reliability and resiliency and lower emissions, including grid modernization and energy storage. An increase in such costs, unless promptly recovered, could have an adverse impact on our financial position, results of operations, and cash flows. There may also be financial and reputational risks if we fail to meet evolving customer expectations, including enabling the integration of residential renewables and providing low carbon solutions, such as electric vehicle infrastructure and energy efficiency services. Additionally, actions to mitigate climate change may result in a transition in our workforce that must adapt to meet the need for new job skills. Associated costs include training programs for existing employees and workforce development as we transition to new technologies and clean energy solutions.

 Adequacy of water supplies and contamination of our water supplies, the failure of dams on reservoirs providing water to our customers, or requirements to repair, upgrade or dismantle any of these dams, may disrupt our ability to distribute water to our customers and result in substantial additional costs, which could adversely affect our financial position, results of operations, and cash flows.

 Our water business faces an inherent strategic risk related to adequacy of supply (i.e., water scarcity). Water scarcity risk is heightened by multiple factors. We expect that climate change will cause both an increase in demand due to increasing temperatures and a potential for a decrease of available supply due to shifting rainfall and recharge patterns. Regulatory constraints also present challenges to permit new sources of supply in the region. In Connecticut, where the vast majority of our dams are located, impounded waterways are required to release minimum downstream flow. New regulations are being phased into effect over the next one to five years that will increase the volume of downstream releases required across our Connecticut service territory, depleting the volume of supply in storage that is used to meet customer demands. This combination of factors may cause an increased likelihood of drought emergencies and water use restrictions that could adversely affect our ability to provide water to our customers, and reputational/brand damage that could negatively impact our water business.

 Our water supplies, including water provided to our customers, are also subject to possible contamination from naturally occurring compounds and elements or non-organic substances, including PFAS. Our water systems include impounding dams and reservoirs and groundwater sources (e.g. wells and aquifers) of various sizes. Although we believe our water supply facilities, dams, reservoirs, and groundwater sources are structurally sound and well-maintained, significant damage to these facilities, or a significant decrease in the water supplies (reservoirs and groundwater), could adversely affect our ability to provide water to our customers until the facilities and a sufficient amount of water can be restored. A failure of a dam could result in personal injuries and downstream property damage for which we may be liable. The failure of a dam would also adversely affect our ability to supply water in sufficient quantities to our customers. Any losses or liabilities incurred due to a failure of one of our dams may not be recoverable in rates and may have a material adverse effect on our financial position, results of operations, and cash flows. We maintain liability insurance, but it may be insufficient in limits and coverage exclusions to cover all losses.

 Physical attacks, including acts of war or terrorism, both threatened and actual, could adversely affect our ability to operate our systems and could adversely affect our financial results and liquidity.

 Physical attacks, including acts of war or terrorism, both threatened and actual, that damage our transmission and distribution systems or other assets could negatively impact our ability to transmit or distribute energy, water, natural gas, or operate our systems efficiently or at all. Because our electric transmission systems are part of an interconnected regional grid, we face the risk of widespread blackouts due to grid disturbances or disruptions on a neighboring interconnected system. Similarly, our natural gas distribution system is connected to transmission pipelines not owned by Eversource. If there was an attack on the transmission pipelines, it could impact our ability to deliver natural gas. If our assets were physically damaged and were not recovered in a timely manner, it could result in a loss of service to customers, a significant decrease in revenues, significant expense to repair system damage, costs associated with governmental actions in response to such attacks, and liability claims, all of which could have a material adverse impact on our financial position, results of operations, and cash flows. We maintain property and liability insurance, but it may be insufficient in limits and coverage exclusions to cover all losses. In addition, physical attacks against third-party providers could have a similar effect on the operation of our systems.

 Business and Operational Risks:

 Strategic development or investment opportunities in electric transmission, distributed generation, or clean-energy technologies may not be successful, which could have a material adverse effect on our business prospects.

 We are pursuing investment opportunities in electric transmission facilities, distributed generation and other clean-energy infrastructure, including interconnection facilities. The development of these projects involve numerous significant risks including federal, state and local permitting and regulatory approval processes, scheduling or permitting delays, increased costs, tax strategies and changes to federal tax laws, new legislation impacting the industry, including clean energy programs, economic events or factors, environmental, community, and customer affordability concerns, design and siting issues, difficulties in obtaining required rights of way, and competition from incumbent utilities and other entities. Also, supply constraints in New England have led to significant increases in commodity costs which may impact our ability to accomplish our strategic objectives. Further, regional clean energy goals may not be achieved if local, state, and federal policy is not in alignment with integrated planning of our infrastructure investments.

 Our transmission and distribution systems may not operate as expected, and could require unplanned expenditures, which could adversely affect our financial position, results of operations, and cash flows.

 Our ability to safely and properly operate our transmission and distribution systems is critical to the financial performance of our business. Our transmission and distribution businesses face several operational risks, including the breakdown, failure of, or damage to operating equipment, information technology systems, or processes, especially due to age; labor disputes; disruptions in the delivery of electricity, natural gas and water; increased capital expenditure requirements, including those due to environmental regulation; catastrophic events resulting from equipment failures such as wildfires and explosions, or external events such as a solar event, an electromagnetic event, or other similar occurrences; increasingly severe weather conditions due to climate change beyond equipment and plant design capacity; human error; global supply chain disruptions; and potential claims for property damage or personal injuries beyond the scope of our insurance coverage. Many of our transmission projects are expected to alleviate identified reliability issues and reduce customers' costs. However, if the in-service date for one or more of these projects is delayed due to economic events or factors, or regulatory or other delays, including permitting and siting, the risk of failures in the electric transmission system may increase. We also implement new information technology systems from time to time, which may disrupt operations. Any failure of our transmission and distribution systems to operate as planned may result in increased capital costs, reduced earnings or unplanned increases in operations and maintenance costs. The inability to recover a significant amount of such costs could have an adverse effect on our financial position, results of operations, and cash flows.

 New technology and alternative energy sources could adversely affect our operations and financial results.

 Advances in technology that reduce the costs of alternative methods of producing electric energy to a level that is competitive with that of current electric production methods, could result in loss of market share and customers, and may require us to make significant expenditures to remain competitive. These changes in technology, including micro-grids and advances in energy or battery storage, could also alter the channels through which electric customers buy or utilize energy, which could reduce our revenues or increase our expenses. Economic downturns or periods of high energy supply costs typically can lead to the development of legislative and regulatory policy designed to promote reductions in energy consumption and increased energy efficiency and self-generation by customers. Additionally, in response to risks posed by climate change, we may need to make investments in our system including upgrades or retrofits to meet enhanced design criteria, which can incur additional costs over conventional solutions.

 We rely on third-party suppliers for equipment, materials, and services and we outsource certain business functions to third-party suppliers and service providers, and substandard performance or inability to fulfill obligations by those third parties could harm our business, reputation and results of operations.

 We outsource certain services to third parties in areas including information technology, transaction processing, human resources, payroll and payroll processing and certain operational areas. Outsourcing of services to third parties could expose us to substandard quality of service delivery or substandard deliverables, which may result in missed deadlines or other timeliness issues, non-compliance (including with applicable legal requirements and industry standards) or reputational harm, which could negatively impact our results of operations. Our contractual arrangements with these contractors typically include performance standards, progress payments, insurance requirements and security for performance. The global supply chain of goods and services generally has stabilized; however, certain specialized equipment has long lead times and inflated prices.

 Additionally, rising geo-political tensions could negatively impact the global supply chain. If significant difficulties in the global supply chain cycle or inflationary impacts were to reemerge, they could adversely affect our results of operations, or adversely affect our ability to work with regulators, unions, customers or employees.

 The loss of key personnel, the inability to hire and retain qualified employees, or the failure to maintain a positive relationship with our workforce could have an adverse effect on our business, financial position and results of operations.

 Our operations depend on the continued efforts of our employees. Retaining key employees and maintaining the ability to attract new employees are important to both our operational and financial performance. We cannot guarantee that any member of our management or any key employee at the Eversource parent or subsidiary level will continue to serve in any capacity for any particular period of time. Our workforce in our subsidiaries includes many workers with highly specialized skills safely maintaining and servicing the electric, natural gas and water infrastructure that cannot be quickly replaced due to the technically complex work they perform. We have developed strategic workforce plans to identify key functions and proactively implement plans to assure a ready and qualified workforce, but we cannot predict the impact of these plans on our ability to hire and retain key employees. Labor disputes, work stoppages or an inability to negotiate future collective bargaining agreements on commercially reasonable terms, as well as the increased competition for talent or the intentional misconduct of employees or contractors, may also have an adverse effect on our business, financial position and results of operations.

 Financial, Economic, and Market Risks:

 Limits on our access to, or increases in, the cost of capital may adversely impact our ability to execute our business plan.

 We use short-term debt and the long-term capital markets as a significant source of liquidity and funding for capital requirements not obtained from our operating cash flow. If access to these sources of liquidity becomes constrained, our ability to implement our business strategy could be adversely affected. In addition, interest rates may increase in the future. As a result, interest rates on future credit facilities and debt offerings could be higher than current levels, causing our financing costs to increase accordingly, which could adversely impact our financial position, results of operations, and cash flows. S&P recently downgraded the credit ratings of Eversource and its regulated utilities as a result of the challenging regulatory environment in Connecticut. Downgrades of our credit ratings or events beyond our control, such as a disruption in global capital and credit markets, could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets and negatively affect our ability to maintain and to expand our businesses.

 Market performance or changes in assumptions may require us to make significant contributions to our pension and other postretirement benefit plans.

 We provide a defined benefit pension plan and other postretirement benefits for a substantial number of employees, former employees and retirees. Our future pension obligations, costs and liabilities are highly dependent on a variety of factors, many of which are beyond our control. These factors include estimated investment returns, interest rates, discount rates, health care cost trends, benefit changes, salary increases and the demographics of plan participants. If our assumptions prove to be inaccurate, our future costs could increase significantly. In addition, various factors, including underperformance of plan investments and changes in law or regulation, could increase the amount of contributions required to fund our pension plan in the future. Additional large funding requirements, when combined with the financing requirements of our construction program, could impact the timing, amounts, and number of future financings and negatively affect our financial position, results of operations, and cash flows.

 Goodwill, investments in equity method investments, and long-lived assets if impaired and written down, could adversely affect our future operating results and total capitalization.

 We have a significant amount of goodwill on our consolidated balance sheet, which, as of December 31, 2024 totaled $3.57 billion. The carrying value of goodwill represents the fair value of an acquired business in excess of the fair value of identifiable assets and liabilities as of the acquisition date. We test our goodwill balances for impairment on an annual basis or whenever events occur, or circumstances change that would indicate a potential for impairment. A determination that goodwill is deemed to be impaired would result in a non-cash charge that could materially adversely affect our financial position, results of operations, and total capitalization.

 We assess our investments (recorded as either long-lived assets or equity method investments) for impairment whenever events or circumstances indicate that the carrying amount of the investment may not be recoverable. To the extent the value of the investment becomes impaired, the impairment charge could have a material adverse effect on our financial position and results of operations.

 Our counterparties may not meet their obligations to us or may elect to exercise their termination rights, which could adversely affect our earnings.

 We are exposed to the risk that counterparties to various arrangements that owe us money, have contracted to supply us with energy or other commodities or services, or that work with us as strategic partners, including on significant capital projects, will not be able to perform their obligations, will terminate such arrangements or, with respect to our credit facilities, fail to honor their commitments. Should any of these counterparties fail to perform their obligations or terminate such arrangements, we might be forced to replace the underlying commitment at higher market prices and/or have to delay the completion of, or cancel, a capital project. Should any lenders under our credit facilities fail to perform, the level of borrowing capacity under those arrangements could decrease. In any such events, our financial position, results of operations, or cash flows could be adversely affected.

 As a holding company with no revenue-generating operations, Eversource parent's liquidity is dependent on dividends from its subsidiaries, its commercial paper program, and its ability to access the long-term debt and equity capital markets.

 Eversource parent is a holding company and as such, has no revenue-generating operations of its own. Its ability to meet its debt service obligations and to pay dividends on its common shares is largely dependent on the ability of its subsidiaries to pay dividends to, or repay borrowings from, Eversource parent, and/or Eversource parent's ability to access its commercial paper program or the long-term debt and equity capital markets. Prior to funding Eversource parent, the subsidiary companies have financial obligations that must be satisfied, including among others, their operating expenses, debt service, preferred dividends of certain subsidiaries, and obligations to trade creditors. Should the subsidiary companies not be able to pay dividends or repay funds due to Eversource parent, or if Eversource parent cannot access its commercial paper programs or the long-term debt and equity capital markets, Eversource parent's ability to pay interest, dividends and its own debt obligations would be restricted.

 Item 1B. Unresolved Staff Comments

 We do not have any unresolved SEC staff comments.

 Item 1C. Cybersecurity

 The Company's policies, practices and technologies allow it to protect its information systems and operational assets from threats. The Board of Trustees and its Finance and Audit Committees continue to provide substantial and focused attention to cyber and system security. The Finance Committee of the Board of Trustees is responsible for oversight of the Company's enterprise-wide risk s, including risks associated with cyber and physical security, and the Company's programs and practices to monitor and mitigate these risks.

 Management prepares comprehensive cyber security reports that are discussed at each meeting of the Finance Committee. The reports focus on the changing threat landscape and the risks to the Company, describe Eversource's cyber security drills and exercises, attempted and actual breaches on our systems, cyber incidents within the utility industry and around the world, and mitigation strategies. In addition, third-party experts of cyber security risks provide periodic assessments to the utility industry and the Company in particular to the Finance Committee. The Company regularly reviews and updates its cyber and system security programs, and the Finance Committee continues to enhance its robust oversight activities, including meetings with financial, information technology, legal and accounting management, other members of the Board, representatives of the Company's independent registered public accounting firm, and outside advisors and experts in cyber security risks, at which cyber and system security programs and issues that might affect the Company's financial statements and operational systems are discussed.

 The Company has a robust Enterprise Risk Management Program that has identified cyber security as a top enterprise risk. The managing and monitoring of risks are the responsibility of the Company's Risk Committee, which meets quarterly and is chaired by the Chief Financial Officer. Members include key leaders of the Company, including the Chief Information Officer.

 The Company is committed to continuous monitoring and assessment of cyber security controls. The Chief Information Security Officer is responsible for developing, implementing, and enforcing our cyber security program and information security policies to protect the Company's information systems and operational assets. The Chief Information Security Officer position requires at least 15 years of relevant information security experience and relevant security certifications. The Chief Information Security Officer reports directly to the Chief Information Officer and provides regular updates to the executive management team. Our Chief Information Security Officer has over 20 years of relevant experience.

 The Company created a Cyber Governance Committee, which includes the Chief Information Security Officer, Chief Information Technology Officer, Chief Accounting Officer, members of the executive management team, and other assurance functions such as Corporate Compliance, Enterprise Risk Management, and Internal Audit.

 To assess, identify and manage material risks from cybersecurity threats and to prevent, detect, mitigate and remediate a cyber security incident, the following key processes and programs have been implemented and are performed by the Company's Cyber Security Group, which is overseen by the Chief Information Security Officer:

 • Implementation of security solutions and standards based on industry best practices to prevent unauthorized access. The Company's cyber program has been modeled after the Department of Energy's Cyber Capability Maturity Model and the National Institute of Standards and Technology framework; both widely accepted frameworks utilized by utilities and other critical infrastructure industries.
 • Periodic external assessments, including outside system access testing, are performed. Rigorous auditing of all safeguards is performed on a regular basis. Risk assessments are held to identify and address new and changing risks to protect systems and sensitive data. Identified areas are monitored and improvements are implemented.
 • Eversource participates in information sharing programs both within and outside the utility industry, including with the U.S. government and industry organizations, to be able to identify and respond to emerging threats.
 • Established an Artificial Intelligence Executive Working Committee to ensure a "Secure by Design" approach to implementations of artificial intelligence.
 • The Company maintains current incident response and business continuity plans, which are periodically updated and tested.
 • Network activity is monitored on an ongoing basis.
 • Anti-phishing and malware tools are utilized and assessed.
 • Employees are trained to recognize phishing attempts and are periodically tested. Results of phishing testing are benchmarked against other companies both within and outside the utility industry.

 Specific to third parties, Eversource has implemented formal screening processes for any applicable vendors by the Company's Cyber Security Group as part of the Procurement process. The vendors are risk ranked based on the type of work being performed. Periodic rescreening is performed on critical vendors. Vendors are required to attest to their business continuity programs and provide evidence of appropriate insurance and indemnification agreements. The Company bars sourcing from countries included on the Department of Homeland Security's list of Prohibited Nations to further protect the Company's supply chain. The Company maintains cyber insurance which covers breaches of networks and operational technology. Our existing insurance limits may be inadequate to cover a material cyber incident. This could expose us to potentially significant claims and damages.

 As of December 31, 2024, there were no cyber incidents that have materially affected or are reasonably likely to materially affect the Company, its business strategy, results of operations, or financial condition.

 Item 2. Properties

 Transmission and Distribution System

 As of December 31, 2024, Eversource and our electric operating subsidiaries owned the following:

 Number of substations owned

 Transformer capacity (in kVa)
 48,055,400
 16,223,000

 Overhead lines (in circuit miles)
 40,595
 3,998

 Underground lines (in circuit miles)
 19,001

 Capacity range of overhead transmission lines (in kV)
 N/A

 Capacity range of underground transmission lines (in kV)
 N/A

 CL&P
 PSNH

 Number of substations owned

 Transformer capacity (in kVa)

 21,984,000
 3,184,000
 21,477,400
 8,688,000
 4,594,000
 4,351,000

 Overhead lines (in circuit miles)

 16,744
 1,674
 11,506
 1,272
 12,345
 1,052

 Underground lines (in circuit miles)

 6,932
 9,940
 2,129

 Capacity range of overhead transmission lines (in kV)

 N/A
 N/A
 N/A
 115 to 345

 Capacity range of underground transmission lines (in kV)

 N/A
 N/A
 115 to 345
 N/A

 CL&P
 PSNH

 Underground and overhead line transformers in service

 650,632
 294,777
 183,831
 172,024

 Aggregate capacity (in kVa)
 39,547,666
 16,931,978
 15,165,820
 7,449,868

 Electric Generating Plants

 As of December 31, 2024, NSTAR Electric owned the following solar power facilities:

 Type of Plant
 Number
of Sites
 Year
Installed
 Capacity
(kilowatts, dc)

 Solar Fixed Tilt, Photovoltaic
 2010 - 2019
 70,000

 CL&P and PSNH do not own any electric generating plants.

 Natural Gas Distribution System

 As of December 31, 2024, NSTAR Gas owned 21 active gate stations, 165 district regulator stations, and approximately 3,337 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns a satellite vaporization plant and above ground storage tanks in Acushnet, Massachusetts (0.5 Bcf of natural gas). In addition, Hopkinton owns a liquefaction and vaporization plant with above ground storage tanks in Hopkinton, Massachusetts (3.0 Bcf of natural gas). Combined, the two plants' tanks have an aggregate storage capacity equivalent to 3.5 Bcf of natural gas that is provided to NSTAR Gas under contract.

 As of December 31, 2024, EGMA owned 15 active gate stations, 178 district regulator stations, and approximately 5,021 miles of natural gas main pipeline. Hopkinton, another subsidiary of Eversource, owns liquefaction and vaporization plants and above ground storage tanks at four locations throughout Massachusetts with an aggregate storage capacity equivalent to 1.8 Bcf of natural gas. In addition, Hopkinton owns three propane peak shaving plants at three locations throughout Massachusetts with an aggregate storage capacity equivalent to 0.1 Bcf. Combined, these seven plants have an aggregate storage capacity equivalent to 1.9 Bcf of natural gas that is provided to EGMA under contract.

 As of December 31, 2024, Yankee Gas owned 28 active gate stations, 197 district regulator stations, and approximately 3,530 miles of natural gas main pipeline. Yankee Gas also owns a liquefaction and vaporization plant and above ground storage tank with a storage capacity equivalent of 1.2 Bcf of natural gas in Waterbury, Connecticut.

 Natural Gas Transmission System

 As of December 31, 2024, NSTAR Gas owned 0.65 miles of intrastate transmission natural gas pipeline.

 Water Distribution System

 Aquarion's properties consist of water transmission and distribution mains and associated valves, hydrants and service lines, water treatment plants, pumping facilities, wells, tanks, meters, dams, reservoirs, buildings, and other facilities and equipment used for the operation of our systems, including the collection, treatment, storage, and distribution of water.

 As of December 31, 2024, Aquarion owned and operated sources of water supply with a combined yield of approximately 135 million gallons per day; 3,817 miles of transmission and distribution mains; 10 surface water treatment plants; 37 dams; and 119 wellfields.

 Franchises

 CL&P Subject to the power of alteration, amendment or repeal by the General Assembly of Connecticut and subject to certain approvals, permits and consents of public authority and others prescribed by statute, CL&P has, subject to certain exceptions not deemed material, valid franchises free from burdensome restrictions to provide electric transmission and distribution services in the respective areas in which it is now supplying such service.

 In addition to the right to provide electric transmission and distribution services as set forth above, the franchises of CL&P include, among others, limited rights and powers, as set forth under Connecticut law and the special acts of the General Assembly constituting its charter, to manufacture, generate, purchase and/or sell electricity at retail, including to provide Standard Service, Supplier of Last Resort service and backup service, to sell electricity at wholesale and to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. The franchises of CL&P include the power of eminent domain. Connecticut law prohibits an electric distribution company from owning or operating generation assets. However, under "An Act Concerning Electricity and Energy Efficiency," enacted in 2007, an electric distribution company, such as CL&P, is permitted to purchase an existing electric generating plant located in Connecticut that is offered for sale, subject to prior approval from PURA and a determination by PURA that such purchase is in the public interest.

 NSTAR Electric Through its charter, which is unlimited in time, NSTAR Electric has the right to engage in the business of delivering and selling electricity within its respective service territory, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon electric companies under Massachusetts laws. The locations in public ways for electric transmission and distribution lines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide electric delivery service to retail customers within NSTAR Electric service territory without the written consent of NSTAR Electric. This consent must be filed with the DPU and the municipality so affected. The franchises of NSTAR Electric include the power of eminent domain, obtained through application to the DPU.

 Massachusetts restructuring legislation defines service territories as those territories actually served on July 1, 1997 and following municipal boundaries to the extent possible. The restructuring legislation further provides that until terminated by law or otherwise, distribution companies shall have the exclusive obligation to serve all retail customers within their service territories and no other person shall provide distribution service within such service territories without the written consent of such distribution companies.

 PSNH The NHPUC, pursuant to statutory requirements, has issued orders granting PSNH exclusive franchises to distribute electricity in the respective areas in which it is now supplying such service.

 In addition to the right to distribute electricity as set forth above, the franchises of PSNH include, among others, rights and powers to manufacture, generate, purchase, and transmit electricity, to sell electricity at wholesale to other utility companies and municipalities and to erect and maintain certain facilities on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. PSNH's status as a public utility gives it the ability to petition the NHPUC for the right to exercise eminent domain for distribution services and for transmission eligible for regional cost allocation.

 PSNH is also subject to certain regulatory oversight by the Maine Public Utilities Commission and the Vermont Public Utility Commission.

 NSTAR Gas Through its charter, which is unlimited in time, NSTAR Gas has the right to engage in the business of delivering and selling natural gas within its respective service territory, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon natural gas companies under Massachusetts laws. The locations in public ways for natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide natural gas delivery service to retail customers within the NSTAR Gas service territory without the written consent of NSTAR Gas. This consent must be filed with the DPU and the municipality so affected.

 EGMA Through its charter, which is unlimited in time, EGMA has the right to engage in the business of delivering and selling natural gas within its respective service territory, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon natural gas companies under Massachusetts laws. The locations in public ways for natural gas distribution pipelines are obtained from municipal and other state authorities who, in granting these locations, act as agents for the state. In some cases, the actions of these authorities are subject to appeal to the DPU. The rights to these locations are not limited in time and are subject to the action of these authorities and the legislature. Under Massachusetts law, no other entity may provide natural gas delivery service to retail customers within the EGMA service territory without the written consent of EGMA. This consent must be filed with the DPU and the municipality so affected.

 Yankee Gas Yankee Gas holds valid franchises to sell natural gas in the areas in which Yankee Gas supplies natural gas service. Generally, Yankee Gas holds franchises to serve customers in areas designated by those franchises as well as in most other areas throughout Connecticut so long as those areas are not occupied and served by another natural gas utility under a valid franchise of its own or are not subject to an exclusive franchise of another natural gas utility or by consent. Yankee Gas' franchises are perpetual but remain subject to the power of alteration, amendment or repeal by the General Assembly of the State of Connecticut, the power of revocation by PURA and certain approvals, permits and consents of public authorities and others prescribed by statute. Generally, Yankee Gas' franchises include, among other rights and powers, the right and power to manufacture, generate, purchase, transmit and distribute natural gas and to erect and maintain certain facilities on public highways and grounds, and the right of eminent domain, all subject to such consents and approvals of public authorities and others as may be required by law.

 Aquarion Water Company of Connecticut and The Torrington Water Company AWC-CT and The Torrington Water Company derive their rights and franchises to operate from special acts of the Connecticut General Assembly and subject to certain approvals, permits and consents of public authority and others prescribed by statute and by its charter, they have, with minor exceptions, solid franchises free from burdensome restrictions and unlimited as to time, and are authorized to sell potable water in the towns (or parts thereof) in which water is now being supplied by AWC-CT and The Torrington Water Company.

 In addition to the right to sell water as set forth above, the franchises of AWC-CT and The Torrington Water Company include rights and powers to erect and maintain certain facilities on public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law. Under the Connecticut General Statutes, AWC-CT and The Torrington Water Company may, upon payment of compensation, take and use such lands, springs, streams or ponds, or such rights or interests therein as the Connecticut Superior Court, upon application, may determine is necessary to enable AWC-CT and The Torrington Water Company to supply potable water for public or domestic use in its franchise areas.

 Aquarion Water Company of Massachusetts Through its charters, which are unlimited in time, AWC-MA has the right to engage in the business of distributing and selling water within its service territories, and has the power incidental thereto and is entitled to all the rights and privileges of and subject to the duties imposed upon water companies under Massachusetts laws. AWC-MA has the right to construct and maintain its mains and distribution pipes in and under any public ways and to take and hold water within its respective service territories. Subject to DPU regulation, AWC-MA has the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same. Certain of the towns within our service area have the right, at any time, to purchase the corporate property and all rights and privileges of AWC-MA according to pricing formulas and procedures specifically described in AWC-MA's respective charters and in compliance with Massachusetts law.

 Aquarion Water Company of New Hampshire and Abenaki Water Company The NHPUC, pursuant to statutory law, has issued orders granting and affirming AWC-NH's and Abenaki Water Company's exclusive franchises to own, operate, and manage plant and equipment and any part of the same, for the conveyance of water for the public located within its franchise territory. AWC-NH's franchise territory encompasses the towns of Hampton, North Hampton, Rye and a limited portion of Stratham. Abenaki Water Company's franchises extend to the boundaries of the water systems in the towns of Belmont, Bow, Carroll, and Gilford. Subject to NHPUC's regulations, AWC-NH and Abenaki have the right to establish and fix rates for use of the water distributed and to establish reasonable regulations regarding the same.

 In addition to the right to provide water supply, the franchise also allows AWC-NH and Abenaki to sell water at wholesale to other water utilities and municipalities and to construct plant and equipment and maintain such plant and equipment on certain public highways and grounds, all subject to such consents and approvals of public authority and others as may be required by law.

 AWC-NH's and Abenaki's status as regulated public utilities gives them the ability to petition the NHPUC for the right to exercise eminent domain for the establishment of plant and equipment. They can also petition the NHPUC for exemption from the operation of any local ordinance when certain utility structures are reasonably necessary for the convenience or welfare of the public and the local conditions, and, if the purpose of the structure relates to water supply withdrawal, the exemption is recommended by the New Hampshire Department of Environmental Services.

 Item 3. Legal Proceedings

 We are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business. For information regarding material lawsuits and proceedings, see Note 13, "Commitments and Contingencies," of the Combined Notes to Financial Statements.

 In addition, see Item 1, Business: "– Electric Distribution Segment," "– Electric Transmission Segment," "– Natural Gas Distribution Segment," and "– Water Distribution Segment" for information about various state and federal regulatory and rate proceedings, civil lawsuits related thereto, and information about proceedings relating to power, transmission and pricing issues; "– Nuclear Fuel Storage" for information related to nuclear waste; and "– Other Regulatory and Environmental Matters" for information about toxic substances and hazardous materials, climate change, and other matters. In addition, see Item 1A, Risk Factors, for general information about several significant risks.

 Item 4. Mine Safety Disclosures

 Not applicable.

 INFORMATION ABOUT OUR EXECUTIVE OFFICERS

 The following sets forth the executive officers of Eversource Energy as of February 14, 2025. All of Eversource Energy's officers serve terms of one year and until their successors are elected and qualified.

 Name

 Age

 Title

 Chairman of the Board, President, Chief Executive Officer and a Trustee

 Executive Vice President, Chief Financial Officer and Treasurer

 Executive Vice President and General Counsel

 Executive Vice President and Chief Operating Officer

 Penelope M. Conner
 Executive Vice President-Customer Experience and Energy Strategy

 James W. Hunt, III
 Executive Vice President-Corporate Relations and Sustainability and Secretary

 Susan Sgroi
 Executive Vice President-Human Resources and Information Technology

 Joseph R. Nolan, Jr. Mr. Nolan has served as Chairman of the Board of Eversource Energy since January 1, 2023, and has served as President and Chief Executive Officer and a Trustee of Eversource Energy since 2021. Previously, Mr. Nolan served as Executive Vice President-Strategy, Customer and Corporate Relations of Eversource Energy from February 5, 2020 until May 5, 2021, and as Executive Vice President-Customer and Corporate Relations of Eversource Energy from August 8, 2016 to February 5, 2020. Based on his experience as described, Mr. Nolan has the skills and qualifications necessary to serve as a Trustee of Eversource Energy.

 John M. Moreira. Mr. Moreira has served as Executive Vice President, Chief Financial Officer and Treasurer of Eversource Energy since May 4, 2022. He previously served as Senior Vice President-Financial and Regulatory and Treasurer of Eversource Energy from September 12, 2018 until May 4, 2022.

 Gregory B. Butler. Mr. Butler has served as General Counsel of Eversource Energy since May 1, 2001. He has served as Executive Vice President of Eversource Energy since August 8, 2016.

 Paul Chodak III. Mr. Chodak has served as Executive Vice President and Chief Operating Officer of Eversource Energy since November 13, 2023. Previously, Mr. Chodak served as Executive Vice President – Generation of American Electric Power Company, Inc. ("AEP") from January 1, 2019 until September 15, 2023, and as Executive Vice President – Utilities of AEP from January 1, 2017 until December 31, 2018.

 Penelope M. Conner. Ms. Conner has served as Executive Vice President-Customer Experience and Energy Strategy of Eversource Energy since May 5, 2021. Previously, Ms. Conner served as Senior Vice President and Chief Customer Officer of Eversource Service from March 2, 2013 until May 5, 2021.

 James W. Hunt, III. Mr. Hunt has served as Executive Vice President-Corporate Relations and Sustainability of Eversource Energy since May 5, 2021 and as Secretary of Eversource Energy since July 9, 2021. Previously Mr. Hunt served as Senior Vice President-Communications, External Affairs and Sustainability of Eversource Service from December 17, 2019 until May 5, 2021 and as Senior Vice President-Regulatory Affairs and Chief Communications Officer of Eversource Service from October 3, 2016 until December 17, 2019.

 Susan Sgroi. Ms. Sgroi has served as Executive Vice President-Human Resources and Information Technology of Eversource Energy since January 8, 2024. Previously, Ms. Sgroi served as Executive Vice President and Chief Human Resources Officer of Blue Cross and Blue Shield of Massachusetts from 2015 until October 31, 2023.

 Jay S. Buth. Mr. Buth has served as Vice President, Controller and Chief Accounting Officer of Eversource Energy since April 10, 2012.

 Item 5. Market for the Registrants' Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities

 (a) Market Information

 Our common shares are listed on the New York Stock Exchange. The ticker symbol is "ES." There is no established public trading market for the common stock of CL&P, NSTAR Electric and PSNH. All of the common stock of CL&P, NSTAR Electric and PSNH is held solely by Eversource.

 (b) Holders

 As of January 31, 2025, there were 27,747 registered common shareholders of our company on record. As of the same date, there were a total of 366,785,030 shares outstanding.

 (c) Dividends

 Information with respect to dividends and dividend restrictions for Eversource, CL&P, NSTAR Electric and PSNH is contained in Item 8, Financial Statements and Supplementary Data, in the Combined Notes to Financial Statements, within this Annual Report on Form 10-K.

 (d) Securities Authorized for Issuance Under Equity Compensation Plans

 For information regarding securities authorized for issuance under equity compensation plans, see Item 12, Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters, included in this Annual Report on Form 10-K.

 (e) Performance Graph

 The performance graph below illustrates a five-year comparison of cumulative total returns based on an initial investment of $100 in 2019 in Eversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 2019 through 2024, assuming all dividends are reinvested.

 December 31,

 2019
 2020
 2021
 2022
 2023
 2024

 $100
 $104
 $113
 $107
 $82
 $80

 EEI Index
 $100
 $99
 $116
 $117
 $107
 $127

 S&P 500
 $100
 $118
 $152
 $125
 $158
 $197

 Purchases of Equity Securities by the Issuer and Affiliated Purchasers

 The following table discloses purchases of our common shares made by us or on our behalf for the periods shown below. The common shares purchased consist of open market purchases made by the Company or an independent agent. These share transactions related to matching contributions under the Eversource 401k Plan.
 Period
 Total Number of Shares Purchased
 Average Price Paid per Share
 Total Number of Shares Purchased as
Part of Publicly Announced Plans or Programs
 Approximate Dollar
Value of Shares that
May Yet Be Purchased Under the Plans and Programs (at month end)

 October 1 - October 31, 2024
 —
 $
 —
 —
 —

 November 1 - November 30, 2024
 —
 —
 —
 —

 December 1 - December 31, 2024
 3,065
 57.39
 —
 —

 Total
 3,065
 $
 57.39
 —
 —

 Item 6. Removed and Reserved

 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations

 The following discussion and analysis should be read in conjunction with our consolidated financial statements and related combined notes included in this combined Annual Report on Form 10-K. References in this combined Annual Report on Form 10-K to "Eversource," the "Company," "we," "us," and "our" refer to Eversource Energy and its consolidated subsidiaries. All per-share amounts are reported on a diluted basis. The consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are herein collectively referred to as the "financial statements." Our discussion of fiscal year 2024 compared to fiscal year 2023 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2022 items and of fiscal year 2023 compared to fiscal year 2022, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2023 Annual Report on Form 10-K, which is incorporated herein by reference.

 Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout this Management's Discussion and Analysis of Financial Condition and Results of Operations.

 The only common equity securities that are publicly traded are common shares of Eversource. Our earnings discussion includes financial measures that are not recognized under GAAP (non-GAAP) referencing our earnings and EPS excluding losses on the sales and impairments of the offshore wind equity method investments, a loss on the pending sale of the Aquarion water distribution business, a loss on the disposition of land that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned, and certain transaction and transition costs. EPS by business is also a non-GAAP financial measure and is calculated by dividing the Net Income Attributable to Common Shareholders of each business by the weighted average diluted Eversource common shares outstanding for the period. The earnings and EPS of each business do not represent a direct legal interest in the assets and liabilities of such business, but rather represent a direct interest in our assets and liabilities as a whole.

 We use these non-GAAP financial measures to evaluate and provide details of earnings results by business and to more fully compare and explain our results without including these items. This information is among the primary indicators we use as a basis for evaluating performance and planning and forecasting of future periods. We believe the impacts of the losses on the offshore wind equity method investments, the loss on the pending sale of the Aquarion water distribution business, the loss on the disposition of land associated with an abandoned project, and transaction and transition costs are not indicative of our ongoing costs and performance. We view these charges as not directly related to the ongoing operations of the business and therefore not an indicator of baseline operating performance. Due to the nature and significance of the effect of these items on Net Income Attributable to Common Shareholders and EPS, we believe that the non-GAAP presentation is a more meaningful representation of our financial performance and provides additional and useful information to readers of this report in analyzing historical and future performance of our business. These non-GAAP financial measures should not be considered as alternatives to reported Net Income Attributable to Common Shareholders or EPS determined in accordance with GAAP as indicators of operating performance.

 Financial Condition and Business Analysis

 Executive Summary

 Eversource Energy is a public utility holding company primarily engaged, through its wholly-owned regulated utility subsidiaries, in the energy delivery business. Eversource Energy's wholly-owned regulated utility subsidiaries consist of CL&P, NSTAR Electric and PSNH (electric utilities), Yankee Gas, NSTAR Gas and EGMA (natural gas utilities) and Aquarion (water utilities). Eversource is organized into the electric distribution, electric transmission, natural gas distribution, and water distribution reportable segments.

 The following items in this executive summary are explained in more detail in this combined Annual Report on Form 10-K:

 Earnings Overview and Future Outlook:

 • We earned $811.7 million, or $2.27 per share, in 2024, compared with a loss of $442.2 million, or $1.26 per share, in 2023. Our 2024 results include an aggregate, net after-tax loss on the sales of our offshore wind investments of $524.0 million, or $1.47 per share, and an after-tax loss resulting from the expected sale of Aquarion of $298.3 million, or $0.83 per share. Our 2023 results included after-tax impairment charges on our offshore wind investments of $1.95 billion, or $5.58 per share. Our 2023 results also included after-tax land abandonment and other charges of $6.9 million, or $0.02 per share. Excluding these charges, our non-GAAP earnings were $1.63 billion, or $4.57 per share, in 2024, compared with non-GAAP earnings of $1.52 billion, or $4.34 per share, in 2023.

 • We project that we will earn within a 2025 earning guidance range of between $4.67 per share and $4.82 per share. We also project that our long-term EPS growth rate through 2029 will be in a 5 to 7 percent range, using 2024 non-GAAP EPS of $4.57 per share as the base year.

 Liquidity:

 • Cash flows provided by operating activities totaled $2.16 billion in 2024, compared with $1.65 billion in 2023. Investments in property, plant and equipment totaled $4.48 billion in 2024, compared with $4.34 billion in 2023.

 • Cash totaled $26.7 million as of December 31, 2024, compared with $53.9 million as of December 31, 2023. Our available borrowing capacity under our commercial paper programs totaled $607.2 million as of December 31, 2024.

 • In 2024, we issued $4.50 billion of new long-term debt and we repaid $1.95 billion of long-term debt.

 • In 2024, we paid dividends totaling $2.86 per common share, compared with dividends of $2.70 per common share in 2023. Our quarterly common share dividend payment was $0.715 per share in 2024, as compared to $0.675 per share in 2023. On January 29, 2025, our Board of Trustees approved a common share dividend payment of $0.7525 per share, payable on March 31, 2025 to shareholders of record as of March 4, 2025.

 • We project to make capital expenditures of $24.17 billion from 2025 through 2029, of which we expect $10.22 billion to be in our electric distribution segment, $6.00 billion to be in our natural gas distribution segment, and $6.81 billion to be in our electric transmission segment. We also project to invest $1.15 billion in information technology and facilities upgrades and enhancements.

 Strategic Developments:

 • On January 27, 2025, Eversource entered into a definitive agreement to sell Aquarion. Subject to certain closing adjustments, the aggregate enterprise value of the sale is approximately $2.4 billion in cash, which includes approximately $1.6 billion for the equity and $800 million of net debt that will be extinguished at closing. The sale is subject to regulatory and other approvals and is expected to close in late 2025. Eversource plans to use the net proceeds from the pending sale to pay down parent company debt.

 • In the third quarter of 2024, Eversource completed the sale of its 50 percent ownership share in the Sunrise Wind project to rsted for adjusted proceeds of $152 million and completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to GIP for adjusted gross proceeds of $745 million. Eversource recognized an aggregate net after-tax loss on the sales of its offshore wind investments of $524 million. Eversource recorded a contingent liability of $365 million, reflecting its estimate of the future obligations under the GIP sale terms, which include an expected cost overrun sharing obligation, expected obligation to maintain GIP's internal rate of return, and obligation for other future costs. Eversource does not have any ongoing financial obligations associated with Sunrise Wind.

 Earnings Overview

 Consolidated: Below is a summary of our earnings/(loss) by business, which also reconciles the non-GAAP financial measures of consolidated non-GAAP earnings and EPS, as well as EPS by business, to the most directly comparable GAAP measures of consolidated Net Income/(Loss) Attributable to Common Shareholders and diluted EPS.

 2024
 2023
 2022

 (Millions of Dollars, Except Per Share Amounts)

 Net Income/(Loss) Attributable to Common Shareholders (GAAP)
 $
 811.7
 $
 2.27
 $
 (442.2)
 $
 (1.26)
 $
 1,404.9
 $
 4.05

 Regulated Companies (Non-GAAP)
 $
 1,691.9
 $
 4.73
 $
 1,509.3
 $
 4.31
 $
 1,460.4
 $
 4.21

 Eversource Parent and Other Companies (Non-GAAP)
 (57.9)
 (0.16)
 8.4
 0.03
 (40.5)
 (0.12)

 Non-GAAP Earnings
 $
 1,634.0
 $
 4.57
 $
 1,517.7
 $
 4.34
 $
 1,419.9
 $
 4.09

 Losses on Offshore Wind Investments (after-tax) (1)

 (524.0)
 (1.47)
 (1,953.0)
 (5.58)
 —
 —

 Loss on Pending Sale of Aquarion (after-tax) (2)

 (298.3)
 (0.83)
 —
 —
 —
 —

 Land Abandonment Loss and Other Charges (after-tax) (3)

 —
 —
 (6.9)
 (0.02)
 —
 —

 Transaction and Transition Costs (after-tax) (4)

 —
 —
 —
 —
 (15.0)
 (0.04)

 Net Income/(Loss) Attributable to Common Shareholders (GAAP)
 $
 811.7
 $
 2.27
 $
 (442.2)
 $
 (1.26)
 $
 1,404.9
 $
 4.05

 (1) In 2024, we recorded a loss on the sales of our offshore wind equity method investments. In 2023, we recorded impairment charges resulting from the expected sales of these offshore wind investments. For further information, see "Business Development and Capital Expenditures – Offshore Wind Business" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

 (2) The 2024 loss includes an impairment charge of $297 million to write down the carrying value of the water business to fair value resulting from the expected sale of Aquarion, as well as transaction costs. For further information, see "Business Development and Capital Expenditures – Pending Sale of Aquarion" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

 (3) The 2023 charges primarily include a loss on the disposition of abandoned land intended to be used for the cancelled Northern Pass Transmission project.

 (4) Transaction costs in 2022 primarily include costs associated with the transition of systems as a result of our purchase of the assets of Columbia Gas of Massachusetts (CMA) on October 9, 2020 and integrating the CMA assets onto Eversource's systems.

 Regulated Companies: Our regulated companies comprise the electric distribution, electric transmission, natural gas distribution, and water distribution segments. A summary of our segment earnings and EPS is as follows:

 2024
 2023
 2022

 (Millions of Dollars, Except Per Share Amounts)

 Net Income - Regulated Companies (GAAP)
 $
 1,393.6
 $
 3.90
 $
 1,509.3
 $
 4.31
 $
 1,460.4
 $
 4.21

 Electric Distribution
 $
 631.7
 $
 1.77
 $
 608.0
 $
 1.74
 $
 592.8
 $
 1.71

 Electric Transmission
 724.6
 2.03
 643.4
 1.84
 596.6
 1.72

 Natural Gas Distribution
 291.0
 0.81
 224.8
 0.64
 234.2
 0.67

 Water Distribution, excluding Loss on Pending Sale (Non-GAAP)
 44.6
 0.12
 33.1
 0.09
 36.8
 0.11

 Net Income - Regulated Companies (Non-GAAP)
 $
 1,691.9
 $
 4.73
 $
 1,509.3
 $
 4.31
 $
 1,460.4
 $
 4.21

 Loss on Pending Sale of Aquarion (after-tax)
 (298.3)
 (0.83)
 —
 —
 —
 —

 Net Income - Regulated Companies (GAAP)
 $
 1,393.6
 $
 3.90
 $
 1,509.3
 $
 4.31
 $
 1,460.4
 $
 4.21

 Our electric distribution segment earnings increased $23.7 million in 2024, as compared to 2023, due primarily to higher revenues from base distribution rate increases at NSTAR Electric effective January 1, 2024 and at PSNH effective August 1, 2024 and from CL&P's capital tracking mechanism due to increased electric system improvements, and an increase in interest income primarily on regulatory deferrals. Those earnings increases were partially offset by higher operations and maintenance expense primarily driven by higher employee benefit costs, higher interest expense, higher depreciation expense, the absence of a prior year benefit at PSNH related to the establishment of a new regulatory tracking mechanism that allowed for the recovery of previously incurred operating expenses associated with poles acquired on May 1, 2023, higher property tax expense, and a higher effective tax rate.

 Our electric transmission segment earnings increased $81.2 million in 2024, as compared to 2023, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and the impact of the annual rate reconciliation filing with FERC, partially offset by a higher effective tax rate.

 Our natural gas distribution segment earnings increased $66.2 million in 2024, as compared to 2023, due primarily to higher revenues from base distribution rate increases effective November 1, 2024 at EGMA and effective November 1, 2024 and November 1, 2023 at NSTAR Gas and capital tracking mechanisms due to continued investments in natural gas infrastructure. Earnings also benefited from lower operations and maintenance expense, the absence of a prior year unfavorable regulatory adjustment resulting from NSTAR Gas' GSEP reconciliation filing, and a lower effective tax rate. Those earnings increases were partially offset by higher depreciation expense, higher interest expense, and higher property tax expense.

 Our water distribution segment recognized a $297 million impairment charge in 2024 as a result of writing down the carrying value of the business to fair value due to the expected sale of Aquarion. Excluding the impairment charge and transaction costs associated with the expected sale, water distribution segment earnings increased $11.5 million in 2024, as compared to 2023, due primarily to an after-tax benefit of $11.6 million recorded in 2024 to recognize the impacts of the Aquarion Water Company of Connecticut's rate case decision from PURA. The impacts of PURA's rate case decision on March 15, 2023 were recorded beginning in March 2024 as a result of the State of Connecticut Superior Court's decision on the rate case appeal on March 25, 2024. The impacts primarily include a reduction to depreciation expense to reflect lower depreciation rates ordered by PURA in its final decision, partially offset by lower authorized revenues.

 Eversource Parent and Other Companies: Eversource parent and other companies' losses decreased $1.37 billion in 2024, as compared to 2023, due primarily to the loss on the sale of Eversource parent's offshore wind investments in 2024, which resulted in an after-tax charge of $524.0 million, as compared to an impairment charge on these investments in 2023 of $1.95 billion. Results for 2023 also include a loss on the disposition of land that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned and other charges recorded of $6.9 million. Excluding these charges, Eversource parent and other companies earnings decreased by $66.3 million due primarily to higher interest expense and the absence of a benefit in 2023 from the liquidation of Eversource parent's equity method investment in a renewable energy fund, partially offset by the absence of a charitable contribution made in 2023 with a portion of the proceeds from the liquidation, and a lower effective tax rate.

 Liquidity

 Sources and Uses of Cash: Eversource's regulated business is capital intensive and requires considerable capital resources. Eversource's regulated companies' capital resources are provided by cash flows generated from operations, short-term borrowings, long-term debt issuances, capital contributions from Eversource parent, and existing cash, and are used to fund their liquidity and capital requirements. Eversource's regulated companies typically maintain minimal cash balances and use short-term borrowings to meet their working capital needs and other cash requirements. Short-term borrowings are also used as a bridge to long-term debt financings. The levels of short-term borrowing may vary significantly over the course of the year due to the impact of fluctuations in cash flows from operations (including timing of storm costs and regulatory recoveries), dividends paid, capital contributions received and the timing of long-term debt financings.

 Eversource, CL&P, NSTAR Electric and PSNH each uses its available capital resources to fund its respective construction expenditures, meet debt requirements, pay operating costs, including storm-related costs, pay dividends, and fund corporate obligations. Eversource's regulated companies recover their electric, natural gas and water distribution construction expenditures as the related project costs are depreciated over the life of the assets. This impacts the timing of the revenue stream designed to fully recover the total investment plus a return on the equity and debt used to finance the investments. Eversource's regulated companies spend a significant amount of cash on capital improvements and construction projects that have a long-term return on investment and recovery period. These factors have resulted in current liabilities exceeding current assets by $1.64 billion, $291.7 million and $112.0 million at Eversource, NSTAR Electric and PSNH, respectively, as of December 31, 2024.

 We expect the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with our existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities.

 As of December 31, 2024, $1.40 billion of Eversource's long-term debt, including $600.0 million at Eversource parent, $400.0 million at CL&P and $250.0 million at NSTAR Electric, matures within the next 12 months. Eversource, with its current credit ratings, has several options available in the financial markets to repay or refinance these maturities with the issuance of new long-term debt. Eversource, CL&P, NSTAR Electric and PSNH will reduce their short-term borrowings with operating cash flows or with the issuance of new long-term debt, determined by considering capital requirements and maintenance of Eversource's credit rating and profile.

 Eversource is currently in the process of selling its Aquarion water distribution business. For information regarding the pending sale and use of proceeds, see "Business Development and Capital Expenditures - Pending Sale of Aquarion" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Cash totaled $26.7 million as of December 31, 2024, compared with $53.9 million as of December 31, 2023.

 Short-Term Debt - Commercial Paper Programs and Credit Agreements: Eversource parent has a $2.00 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut are parties to a five-year $2.00 billion revolving credit facility, which terminates on October 11, 2029. This revolving credit facility serves to backstop Eversource parent's $2.00 billion commercial paper program.

 NSTAR Electric has a $650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $650 million revolving credit facility, which terminates on October 11, 2029, that serves to backstop NSTAR Electric's $650 million commercial paper program.

 The amount of borrowings outstanding and available under the commercial paper programs were as follows:
 Borrowings Outstanding
 as of December 31,
 Available Borrowing Capacity as of December 31,
 Weighted-Average Interest Rate as of December 31,

 2024
 2023
 2024
 2023
 2024
 2023

 Eversource Parent Commercial Paper Program
 $
 1,538.0
 $
 1,771.9
 $
 462.0
 $
 228.1
 4.76
 %
 5.60
 %

 NSTAR Electric Commercial Paper Program
 504.8
 365.8
 145.2
 284.2
 4.55
 %
 5.40
 %

 There were no borrowings outstanding on the revolving credit facilities as of December 31, 2024 or 2023.

 CL&P and PSNH have uncommitted line of credit agreements totaling $375 million and $250 million, respectively, all of which will expire in either May 2025, September 2025 or October 2025. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2024.

 Amounts outstanding under the commercial paper programs are included in Notes Payable and classified in current liabilities on the Eversource and NSTAR Electric balance sheets, as all borrowings are outstanding for no more than 364 days at one time. As a result of the CL&P long-term debt issuance in January 2024, $207.3 million of commercial paper borrowings under the Eversource parent commercial paper program were reclassified to Long-Term Debt on Eversource parent's balance sheet as of December 31, 2023.

 Intercompany Borrowings: Eversource parent uses its available capital resources to provide loans to its subsidiaries to assist in meeting their short-term borrowing needs. Eversource parent records intercompany interest income from its loans to subsidiaries, which is eliminated in consolidation. Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets. As of December 31, 2024, there were intercompany loans from Eversource parent to CL&P of $280.0 million and to PSNH of $131.1 million. As of December 31, 2023, there were intercompany loans from Eversource parent to CL&P of $457.0 million and to PSNH of $233.0 million. Eversource parent charges interest on these intercompany loans at the same weighted-average interest rate as its commercial paper program. Intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent and classified in current liabilities on the respective subsidiary's balance sheets, as these intercompany borrowings are outstanding for no more than 364 days at one time. As a result of the CL&P long-term debt issuance in January 2024, $207.3 million of CL&P's intercompany borrowings were reclassified to Long-Term Debt on CL&P's balance sheet as of December 31, 2023.

 Availability under Long-Term Debt Issuance Authorizations: On May 1, 2024, the DPU approved NSTAR Electric's request for authorization to issue up to $2.40 billion in long-term debt through December 31, 2026. On July 24, 2024, PURA approved CL&P's request for authorization to issue up to $1.00 billion in long-term debt through December 31, 2025. On August 12, 2024, the DPU approved EGMA's request for authorization to issue up to $325 million in long-term debt through December 31, 2026. On December 18, 2024, the DPU approved NSTAR Gas' request for authorization to issue up to $475 million in long-term debt through December 31, 2027. On January 28, 2025, Yankee Gas submitted an application to PURA requesting authorization to issue up to $360 million in long-term debt through December 31, 2026. PSNH has utilized its long-term debt authorizations in place with NHPUC.

 Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments:

 Issuance/
(Repayment)
 Issue Date or Repayment Date
 Maturity Date
 Use of Proceeds for Issuance/
Repayment Information

 CL&P 2024 Series A First Mortgage Bonds
 4.65
 %
 $
 350.0
 January 2029

 CL&P Series B First Mortgage Bonds
 4.95
 %
 300.0
 August 2034
 Repaid Series D Bonds, repaid short-term debt, and working capital

 CL&P Series D First Mortgage Bonds
 7.875
 %
 (139.8)

 CL&P 2025 Series A First Mortgage Bonds
 4.95
 %
 400.0
 January 2030

 NSTAR Electric Debentures
 5.40
 %
 600.0
 May 2024
 June 2034

 PSNH Series X First Mortgage Bonds
 5.35
 %
 300.0
 October 2033

 Eversource Parent Series DD Senior Notes
 5.00
 %
 350.0
 January 2027
 Repaid short-term debt

 Eversource Parent Series EE Senior Notes
 5.50
 %
 650.0
 January 2034
 Repaid short-term debt

 Eversource Parent Series FF Senior Notes
 5.85
 %
 700.0
 April 2031
 Repaid Series X Senior Notes and Aquarion's 2014 Senior Notes at maturity and short-term debt

 Eversource Parent Series GG Senior Notes
 5.95
 %
 700.0
 July 2034
 Repaid Series X Senior Notes and Aquarion's 2014 Senior Notes at maturity and short-term debt

 Eversource Parent Series X Senior Notes
 4.20
 %
 (900.0)

 Eversource Parent Series L Senior Notes
 2.90
 %
 (450.0)

 Eversource Parent Series H Senior Notes
 3.15
 %
 (300.0)

 NSTAR Gas Series W First Mortgage Bonds
 5.29
 %
 160.0
 June 2029
 Repaid short-term debt, paid capital expenditures and general corporate purposes

 NSTAR Gas Series X First Mortgage Bonds
 5.48
 %
 40.0
 June 2034
 Repaid short-term debt, paid capital expenditures and general corporate purposes

 Yankee Gas Series W First Mortgage Bonds
 5.50
 %
 90.0
 July 2024
 July 2029
 Repaid short-term debt, paid capital expenditures, working capital and repaid Series P bonds at maturity

 Yankee Gas Series X First Mortgage Bonds
 5.74
 %
 90.0
 July 2024
 July 2034
 Repaid short-term debt, paid capital expenditures, working capital and repaid Series P bonds at maturity

 Yankee Gas Series P First Mortgage Bonds
 2.23
 %
 (100.0)

 EGMA Series E First Mortgage Bonds
 5.17
 %
 100.0
 November 2034
 Refinanced existing indebtedness, paid capital expenditures and general corporate purposes

 Aquarion Senior Notes
 4.00
 %
 (360.0)

 Aquarion Water Company of Connecticut Senior Notes
 5.57
 %
 70.0
 September 2034
 Repaid short-term debt, paid capital expenditures and general corporate purposes

 As a result of the CL&P long-term debt issuance in January 2025, $397.1 million of current portion of long-term debt was reclassified to Long-Term Debt on Eversource's and CL&P's balance sheets as of December 31, 2024.

 Rate Reduction Bonds: PSNH's RRB payments consist of principal and interest and are paid semi-annually. PSNH paid $43.2 million of RRB principal payments in each of 2024 and 2023, and paid $14.9 million and $16.2 million of interest payments in 2024 and 2023, respectively.

 Common Share Issuances: Eversource had an equity distribution agreement pursuant to which it could offer and sell up to $1.2 billion of its common shares from time to time through an "at-the-market" (ATM) equity offering program. In 2024, Eversource issued 15,740,294 common shares, which resulted in proceeds of $989.4 million, net of issuance costs. Eversource used the net proceeds received for general corporate purposes. In 2023, no shares were issued under this agreement. Eversource completed the program in October 2024.

 Cash Flows: Cash flows from operating activities primarily result from the transmission and distribution of electricity, and the distribution of natural gas and water. Cash flows provided by operating activities totaled $2.16 billion in 2024, compared with $1.65 billion in 2023. Operating cash flows were favorably impacted by the timing of cash payments made on our accounts payable, a $108.8 million increase due to income tax refunds received in 2024 as compared to income tax payments made in 2023, an improvement in regulatory under-recoveries driven primarily by the timing of collections for the CL&P non-bypassable FMCC and other regulatory tracking mechanisms partially offset by the unfavorable impact in the timing of collections for energy supply costs, a $20.7 million decrease in cost of removal expenditures, a $12.4 million decrease in cash payments to vendors for storm costs, and the timing of other working capital items. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization on the statements of cash flows. These favorable impacts were partially offset by the timing of cash collections on our accounts receivable.

 In 2024, we paid cash dividends of $1.00 billion and issued non-cash dividends of $23.5 million in the form of treasury shares, totaling dividends of $1.03 billion, or $2.86 per common share. In 2023, we paid cash dividends of $919.0 million and issued non-cash dividends of $23.4 million in the form of treasury shares, totaling dividends of $942.4 million, or $2.70 per common share. Our quarterly common share dividend payment was $0.715 per share in 2024, as compared to $0.675 per share in 2023. On January 29, 2025, our Board of Trustees approved a common share dividend payment of $0.7525 per share, payable on March 31, 2025 to shareholders of record as of March 4, 2025.

 Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan.

 In 2024, CL&P, NSTAR Electric and PSNH paid $333.8 million, $643.9 million and $62.0 million, respectively, in common stock dividends to Eversource parent.

 Investments in Property, Plant and Equipment on the statements of cash flows do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP income/expense. In 2024, investments for Eversource, CL&P, NSTAR Electric, and PSNH were $4.48 billion, $978.5 million, $1.56 billion and $608.8 million, respectively. Capital expenditures were primarily for continuing projects to maintain and improve infrastructure and operations, including enhancing reliability to the transmission and distribution systems.

 Contractual Obligations: For information regarding our cash requirements from contractual obligations and payment schedules, see Note 9, "Long-Term Debt," Note 10, "Rate Reduction Bonds and Variable Interest Entities," Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," Note 13, "Commitments and Contingencies," and Note 14, "Leases," to the financial statements.

 Estimated interest payments on existing long-term fixed-rate debt are calculated by multiplying the coupon rate on the debt by its scheduled notional amount outstanding for the period of measurement as of December 31, 2024 and are as follows:

 2025
 2026
 2027
 2028
 2029
 Total

 $
 1,113.5
 $
 1,044.2
 $
 982.4
 $
 872.3
 $
 764.4
 $
 6,793.6
 $
 11,570.4

 Our commitments to make payments in addition to these contractual obligations include other liabilities reflected on our balance sheets, and guarantees of certain obligations primarily associated with construction of our previously owned offshore wind investments.

 For information regarding our projected capital expenditures over the next five years, see "Business Development and Capital Expenditures - Projected Capital Expenditures" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Credit Ratings: A summary of our current corporate credit ratings and outlooks by S&P, Moody's, and Fitch is as follows:

 S&P
 Moody's
 Fitch

 Eversource Parent
 BBB+
 Baa2
 BBB

 CL&P
 A-
 A3
 A-

 A-
 A2
 A-

 PSNH
 A-
 A3
 A-

 A summary of the current credit ratings and outlooks by S&P, Moody's, and Fitch for senior unsecured debt of Eversource parent and NSTAR Electric, and senior secured debt of CL&P and PSNH is as follows:

 S&P
 Moody's
 Fitch

 Eversource Parent
 BBB
 Baa2
 BBB

 CL&P
 A
 A1
 A+

 A-
 A2
 A

 PSNH
 A
 A1
 A+

 In June 2024, Moody's revised the outlook from stable to negative for CL&P citing a weaker financial profile and a challenging Connecticut regulatory environment. In December 2024, S&P downgraded the ratings for Eversource parent and its subsidiaries primarily due to S&P's negative assessment of the Connecticut regulatory construct for Eversource's Connecticut utilities. These credit ratings and outlook changes reflect higher regulatory risk in Connecticut with the regulatory construct and adverse regulatory developments, including recent rate orders and the passage of Senate Bill 7, negatively impacting the credit quality of Eversource and its subsidiaries.

 Business Development and Capital Expenditures

 Our consolidated capital expenditures, including amounts incurred but not paid, cost of removal, AFUDC, and the capitalized and deferred portions of pension and PBOP income/expense (all of which are non-cash factors), totaled $4.64 billion in 2024, $4.59 billion in 2023, and $3.79 billion in 2022. These amounts included $260.5 million in 2024, $214.4 million in 2023, and $266.5 million in 2022 related to information technology and facilities upgrades and enhancements, primarily at Eversource Service and The Rocky River Realty Company.

 Electric Transmission Business: Our consolidated electric transmission business capital expenditures decreased by $120.0 million in 2024, as compared to 2023. A summary of electric transmission capital expenditures by company is as follows:

 2024
 2023
 2022

 CL&P
 $
 450.0
 $
 470.4
 $
 416.8

 502.0
 567.4
 438.4

 PSNH
 375.8
 410.0
 351.8

 Total Electric Transmission
 $
 1,327.8
 $
 1,447.8
 $
 1,207.0

 Our transmission projects are designed to improve the reliability of the electric grid, meet customer demand for power, and strengthen the electric grid's resilience against extreme weather and other safety and security threats. In Connecticut, Massachusetts and New Hampshire, our transmission projects include transmission line upgrades, the installation of new transmission interconnection facilities, substations and lines, and transmission substation enhancements.

 Greater Cambridge Energy Program: The Greater Cambridge Energy Program will construct Eversource's first underground transmission substation in Cambridge, Massachusetts, along with associated transmission and distribution lines. The project will address the increased electric demand in the region, enhance the resiliency of the transmission system, and ensure a flexible grid to reliably serve customers. The flexibility to transmit and distribute mixed energy sources will support the decarbonization and electrification goals of both the City of Cambridge and the state of Massachusetts. The new 115/13.8-kV, 35,000 square foot substation will be located in an underground vault and includes three distribution power transformers supplying thirty-six distribution circuits. The project also includes five underground duct banks housing eight new 115-kV transmission lines. The Massachusetts Energy Facilities Siting Board approved the project on June 28, 2024. Additional required environmental permits are expected to be approved by the end of 2025, as well as a license from the MA DEP expected to be approved by the end of the second quarter of 2026. The initial in-service date for the project is June 2029, which includes two 115-kV transmission lines and the transmission portion of the substation. The first distribution circuits and substation distribution will be placed in-service by the end of 2029. The remaining transmission and distribution circuits will be placed in-service throughout 2030 and into 2031. The total project cost is approximately $1.84 billion, with $1.38 billion allocated for transmission and $460 million for distribution. As of December 31, 2024, $100.1 million has been spent on the project, with $70 million for transmission and $30.1 million for distribution.

 Distribution Business: A summary of distribution capital expenditures is as follows:

 CL&P
 PSNH
 Total Electric
 Water
 Total

 2024

 Basic Business
 $
 298.8
 $
 471.7
 $
 136.2
 $
 906.7
 $
 226.9
 $
 21.8
 $
 1,155.4

 Aging Infrastructure
 161.3
 365.8
 65.4
 592.5
 743.6
 140.5
 1,476.6

 Load Growth and Other
 110.6
 194.3
 66.4
 371.3
 52.3
 0.8
 424.4

 Total Distribution
 $
 570.7
 $
 1,031.8
 $
 268.0
 $
 1,870.5
 $
 1,022.8
 $
 163.1
 $
 3,056.4

 2023

 Basic Business
 $
 280.3
 $
 376.6
 $
 91.1
 $
 748.0
 $
 208.2
 $
 18.5
 $
 974.7

 Aging Infrastructure
 260.7
 310.0
 86.4
 657.1
 719.5
 142.3
 1,518.9

 Load Growth and Other
 138.0
 191.3
 37.2
 366.5
 70.1
 0.9
 437.5

 Total Distribution
 $
 679.0
 $
 877.9
 $
 214.7
 $
 1,771.6
 $
 997.8
 $
 161.7
 $
 2,931.1

 2022

 Basic Business
 $
 267.8
 $
 202.4
 $
 68.6
 $
 538.8
 $
 175.2
 $
 16.8
 $
 730.8

 Aging Infrastructure
 199.9
 245.1
 70.8
 515.8
 562.3
 137.6
 1,215.7

 Load Growth and Other
 90.7
 177.0
 31.3
 299.0
 66.4
 0.9
 366.3

 Total Distribution
 $
 558.4
 $
 624.5
 $
 170.7
 $
 1,353.6
 $
 803.9
 $
 155.3
 $
 2,312.8

 For the electric distribution business, basic business includes the purchase of meters, tools, vehicles, information technology, transformer replacements, equipment facilities, and the relocation of plant. Aging infrastructure relates to reliability and the replacement of overhead lines, plant substations, underground cable replacement, and equipment failures. Load growth and other includes requests for new business and capacity additions on distribution lines and substation additions and expansions.

 For the natural gas distribution business, basic business addresses daily operational needs including meters, pipe relocations due to public works projects, vehicles, and tools. Aging infrastructure projects seek to improve the reliability of the system through enhancements related to cast iron and bare steel replacement of main and services, corrosion mediation, and station upgrades. Load growth and other reflects growth in existing service territories including new developments, installation of services, and expansion.

 For the water distribution business, basic business addresses daily operational needs including periodic meter replacement, water main relocation, facility maintenance, and tools. Aging infrastructure relates to reliability and the replacement of water mains, regulators, storage tanks, pumping stations, wellfields, reservoirs, and treatment facilities. Load growth and other reflects growth in our service territory, including improvements of acquisitions, installation of new services, and interconnections of systems.

 Pending Sale of Aquarion: In early 2024, Eversource initiated an exploratory assessment of the potential sale of the Aquarion water distribution business. In December 2024, final bids were received, and Eversource obtained approval from its Board of Trustees to sell the Aquarion water distribution business. On January 27, 2025, Eversource entered into a definitive agreement to sell Aquarion. Subject to certain closing adjustments, the aggregate enterprise value of the sale is approximately $2.4 billion in cash, which includes approximately $1.6 billion for the equity and $800 million of net debt that will be extinguished at closing. The sale is subject to approval by PURA, DPU and the NHPUC, as well as other approvals pursuant to the Hart-Scott-Rodino Antitrust Improvements Act as well as other customary closing conditions. The sale is expected to close in late 2025. Eversource plans to use the net proceeds from the pending sale to pay down parent company debt.

 In the fourth quarter of 2024, upon classifying the assets and liabilities as held for sale, Eversource concluded that the likely sale of Aquarion at a loss resulted in the requirement to test water distribution goodwill for impairment. Eversource performed an impairment test by comparing the fair value of the business to its carrying value and recorded a goodwill impairment of $297 million, as the estimated fair value of the business based on the anticipated sale was less than the carrying value. The fair value included future cash outflows of approximately $140 million of estimated income taxes as a result of the transaction. The goodwill impairment charge is presented separately within Operating Income on the Eversource statement of income for the year ended December 31, 2024.

 Projected Capital Expenditures: A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution and natural gas distribution for 2025 through 2029, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows:

 Years

 2025
 2026
 2027
 2028
 2029
 2025 - 2029 Total

 CL&P Transmission
 $
 $
 $
 $
 $
 $
 1,808

 NSTAR Electric Transmission
 3,636

 PSNH Transmission
 1,363

 Total Electric Transmission

 1,406
 1,392
 1,363
 1,334
 1,312
 6,807

 Electric Distribution
 1,965
 2,231
 2,143
 1,958
 1,918
 10,215

 Natural Gas Distribution
 1,094
 1,164
 1,184
 1,259
 1,297
 5,998

 Total Electric and Natural Gas Distribution

 3,059
 3,395
 3,327
 3,217
 3,215
 16,213

 Information Technology and All Other
 1,152

 Total
 $
 4,721
 $
 5,009
 $
 4,912
 $
 4,776
 $
 4,754
 $
 24,172

 Actual capital expenditures could vary from the projected amounts for the companies and years above.

 The projected capital expenditures reflect a reduction in planned capital expenditures for Connecticut's electric and natural gas distribution businesses due to regulatory policies in Connecticut that discourage investment, including ensuring the timely recovery of costs and the ability to earn a fair return. The continuing pattern of adverse regulatory outcomes for Connecticut utilities and associated credit downgrades from our credit rating agencies necessitated a reduction to Connecticut's electric and natural gas distribution projected capital expenditures. These capital reductions do not impact Eversource's commitment to safety, reliability, or critical staffing structure.

 Projected capital expenditures for the water distribution business of $130 million are expected until the time of sale in late 2025 and have been factored into the water business impairment recorded as of December 31, 2024.

 Offshore Wind Business: Eversource's previous offshore wind business included 50 percent ownership interests in each of North East Offshore and South Fork Class B Member, LLC. During 2024, Eversource sold its interest in these entities, and in doing so, sold its interests in the Revolution Wind project, the South Fork Wind project, and the Sunrise Wind project. Eversource's current offshore wind business is now comprised only of a noncontrolling tax equity investment in South Fork Wind through a 100 percent ownership in South Fork Wind Holdings, LLC Class A interests.

 On May 25, 2023, Eversource announced that it had completed a strategic review of its offshore wind investments and determined that it would pursue the sale of its offshore wind investments. On September 7, 2023, Eversource completed the sale of its 50 percent interest in an uncommitted lease area consisting of approximately 175,000 developable acres located 25 miles off the south coast of Massachusetts to rsted for $625 million in an all-cash transaction.

 In September of 2023, Eversource made a $528 million investment in a tax equity interest for South Fork Wind. South Fork Wind was restructured as a tax equity investment, with Eversource purchasing 100 percent ownership of a new Class A tax equity membership interest. This investment will result in Eversource receiving cash flow benefits from investment tax credits (ITC) and other future cash flow benefits as well. As of December 31, 2024, $459 million of expected investment tax credits and other expected tax benefits were reclassified from the South Fork Wind tax equity investment balance reported in Investments in Unconsolidated Affiliates as a decrease in Accumulated Deferred Income Taxes on the Eversource balance sheet, which represented a non-cash reclassification. As a result of these investment tax credits, Eversource expects lower federal income tax payments from 2025 to 2027. As of December 31, 2024, the tax equity interest in South Fork Wind totaled $22.2 million.

 On January 24, 2024, Eversource entered into an agreement with rsted to sell Eversource's 50 percent share of Sunrise Wind, subject to certain conditions and regulatory approvals. On April 18, 2024, Eversource and rsted executed an equity and asset purchase agreement and on July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to rsted. In accordance with the equity and asset purchase agreement and after adjustment for a reduction in capital spending compared to forecasted amounts, adjusted proceeds totaled $152 million. rsted paid Eversource $118 million at the closing of the sale transaction, which was used to repay parent company debt. Remaining proceeds of $34 million will be paid after onshore construction is completed and certain other construction milestones are achieved. The remaining expected proceeds have been recorded in Other Long-Term Assets on Eversource's balance sheet as of December 31, 2024. Eversource recorded a pre-tax gain on the sale of Sunrise Wind of $377 million in 2024. With completion of the sale, Eversource does not have any ongoing financial obligations associated with Sunrise Wind.

 On February 13, 2024, Eversource executed an agreement to sell its 50 percent interests in the South Fork Wind and Revolution Wind projects to Global Infrastructure Partners (GIP) for an initial gross purchase price of approximately $1.1 billion. The initial purchase price was subject to adjustment based on, among other things, the progress, timing and the construction cost of Revolution Wind, including changes in actual versus forecasted capital spending between signing the agreement and closing of the transaction. On September 30, 2024, Eversource completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to GIP for adjusted gross proceeds of $745 million, which were received at closing. Adjusted gross proceeds from the sale were approximately $375 million lower than the previously estimated purchase price. This reduction reflects approximately $150 million resulting from lower capital spending between signing the agreement and closing, and approximately $225 million related to the final terms of the sale transaction, primarily due to the delay of the commercial operations date of Revolution Wind. Proceeds from the transaction were used to repay parent company debt.

 As part of the Revolution Wind and South Fork Wind sale, Eversource and GIP agreed to make certain post-closing purchase price adjustment payments, which could further impact the final purchase price. The post-closing purchase price adjustment payments include cost sharing obligations that require Eversource to share equally with GIP in GIP's funding obligations up to an effective cap of approximately $240 million of incremental capital expenditure overruns incurred during the construction phase for Revolution Wind, after which Eversource will have responsibility for GIP's obligations for any additional capital expenditure overruns in excess of this amount. The purchase price is also subject to post-closing adjustments as a result of final project economics, which includes Eversource's obligation to maintain GIP's internal rate of return through the construction period for each project as specified in the agreement. Post-closing purchase price adjustment payments will be made following the commercial operation date of Revolution Wind. South Fork Wind has achieved commercial operation, and Eversource is in the process of finalizing the construction cost post-close purchase price adjustment payment related to this project, which is not expected to be material.

 Upon the completion of both sale transactions in 2024, the total proceeds were compared to the carrying value of the investments, including an estimate of liability for post-closing adjustment payments to GIP, and Eversource recognized an aggregate, net after-tax loss on the sales of its offshore wind investments of $524 million. The aggregate, net after-tax loss is comprised of (1) the lower proceeds related to final terms of the sale transaction to GIP of approximately $225 million related to non-construction costs for the Revolution Wind and South Fork Wind projects, primarily due to a purchase price reduction of $150 million resulting from the delay of the commercial operations date of Revolution Wind, (2) recently identified forecasted construction costs as a result of a delay in the anticipated commercial operation date related to Revolution Wind of approximately $350 million, which includes an estimate for the anticipated post-closing adjustment to GIP related to Eversource's expected cost overrun sharing obligation, and (3) approximately $326 million, which includes an estimate for the anticipated post-closing adjustment related to Eversource's expected obligations to GIP as a result of final economics of the Revolution Wind and South Fork Wind projects and other future costs, as well as a net $60 million increase in income tax expense including an increase in the valuation allowance for unused capital losses. These losses were partially offset by the $377 million gain on the sale of Sunrise Wind.

 Upon sale, Eversource recorded a contingent liability of $365 million, reflecting its estimate of the future obligations under the GIP sale terms, which include the expected cost overrun sharing obligation, expected obligation to maintain GIP's internal rate of return, and obligation for other future costs. The majority of this liability is expected to be settled upon the completion of the Revolution Wind project. The long-term portion of the liability of $350 million is recorded in Other Long-Term Liabilities, and $15 million is recorded in Other Current Liabilities on Eversource's balance sheet as of December 31, 2024.

 Contingencies are evaluated using the best information available at the time the financial statements are prepared, and this assessment involves judgments and assumptions about future events. Factors that could increase the post-closing adjustment payments owed to GIP include the ultimate cost of construction and extent of cost overruns for Revolution Wind, delays in construction, which would impact the economics associated with the purchase price adjustment, and Revolution Wind's eligibility for federal investment tax credits at a lower value than assumed and included in the purchase price.

 The purchase price included the sales value related to a 40 percent level of federal investment tax credits, 10 percent of which is the energy community investment tax credit (ITC) adder included in the Inflation Reduction Act of approximately $170 million related to Revolution Wind. Although management believes the ITC adder value is realizable, there is some uncertainty at this time as to whether those ITC adders can be achieved, and management continues to evaluate the project's qualifications and to monitor guidance issued by the United States Treasury Department. A change in the expected value or qualification of ITC adders could result in a significant loss in a future period.

 New information or future developments that arise as construction progresses and as cost estimates are reviewed and revised will require a reassessment of the estimated liability for the post-closing adjustment payments. The Company is currently aware that construction of the offshore foundations, offshore substation and turbine tower installations could result in increased cost overruns in the future. Only preliminary construction cost projections are available for these cost overruns, and there is insufficient updated information at this point in order for Eversource to change its estimate with reasonably estimable information. Eversource will continue to assess the potential exposure and adjust the liability as needed. It is expected that updated costs estimates will become available in the first half of 2025, and adverse changes in facts and circumstances could result in additional losses that could be material. The Company believes it is reasonably possible that there is an additional loss in excess of the liability recorded, but management cannot reasonably estimate a range of loss beyond the $365 million recorded at this time.

 Total net proceeds could also be adjusted for a benefit due to Eversource if there are lower operation costs or higher availability of the projects through the period that is four years following the commercial operation of Revolution Wind.

 Under the agreement with GIP, Eversource's existing and certain additional credit support obligations for Revolution Wind are expected to roll off as the project completes construction. Under the agreement with rsted, Eversource's existing credit support obligations for Sunrise Wind were either terminated or indemnified by rsted as a result of the sale. Eversource has entered into separate construction management agreements to manage Sunrise Wind's and Revolution Wind's onshore electric substation construction through completion. In this role, Eversource will be solely a service provider to Sunrise Wind and Revolution Wind.

 2023 Impairments: Equity method investments are assessed for impairment when conditions exist as of the balance sheet date that indicate that the fair value of the investment may be less than book value. Eversource continually monitors and evaluates its equity method investments to determine if there are indicators of an other-than-temporary impairment. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations are based on best information available at the impairment assessment date. Subsequent declines or recoveries after the reporting date are not considered in the impairment recognized. Investments that are other-than-temporarily impaired and written down to their estimated fair value cannot subsequently be written back up for increases in estimated fair value. Impairment evaluations involve a significant degree of judgment and estimation, including identifying circumstances that indicate an impairment may exist at the equity method investment level, selecting discount rates used to determine fair values, and developing an estimate of discounted future cash flows expected from investment operations or the sale of the investment.

 During 2023, in connection with the process to divest its offshore wind business, Eversource identified indicators for impairment in both the second and fourth quarters of 2023. In each impairment assessment, Eversource evaluated its investments and determined that the carrying value of the equity method offshore wind investments exceeded the fair value of the investments and that the decline in fair value was other-than-temporary. The completion of the strategic review in the second quarter of 2023 resulted in Eversource recording a pre-tax other-than-temporary impairment charge of $401 million ($331 million after-tax) to reflect the investment at estimated fair value based on the expected sales price at that time. This established a new cost basis in the investments. Negative developments in the fourth quarter of 2023, including a lower expected sales price, additional projected construction cost increases, and the October 2023 OREC pricing denial for Sunrise Wind, resulted in Eversource conducting an impairment evaluation and recognizing an additional pre-tax other-than-temporary impairment charge of $1.77 billion ($1.62 billion after-tax) and establishing a new cost basis in the investments as of December 31, 2023. The Eversource statement of income for the year ended 2023 reflects a total pre-tax other-than-temporary impairment charge of $2.17 billion ($1.95 billion after-tax) in its offshore wind investments. The impairment charges were non-cash charges and did not impact Eversource's cash position at the time of the impairment. Eversource's offshore wind investments did not meet the criteria to qualify for presentation as a discontinued operation.

 The 2023 impairment evaluations involved judgments in developing the estimates and timing of the future cash flows arising from the expected sales price of Eversource's 50 percent interest in the wind projects, including expected sales value from investment tax credit adder amounts, less estimated costs to sell, and uncertainties related to the Sunrise Wind re-bid process in New York's offshore wind solicitation in 2024. Additional assumptions in the fourth quarter 2023 assessment included revised projected construction costs and estimated project cost overruns, management's assumption that the Sunrise Wind project would ultimately be abandoned, estimated termination costs, salvage values of Sunrise Wind assets, and the value of the tax equity ownership interest. The assumptions used in the discounted cash flow analyses were subject to inherent uncertainties and subjectivity. All significant inputs into the impairment evaluations were Level 3 fair value measurements.

 A summary of the significant estimates and assumptions included in the 2023 impairment charges is as follows:

 Second Quarter 2023

 Fourth Quarter 2023

 Total

 Lower expected sales proceeds across all three wind projects

 $
 $
 $

 Expected cost overruns not recovered in the sales price

 —

 Loss of sales value from the sale price offered by GIP, including loss of ITC adders value, cancellation costs and other impacts assuming Sunrise Wind project is abandoned

 —

 Impairment Charges, pre-tax
 1,766
 2,167

 Tax Benefit
 (70)
 (144)
 (214)

 Impairment Charges, after-tax
 $
 $
 1,622
 1,953

 A summary of the carrying value by investee and by project as of December 31, 2023 is as follows:

 Investments Expected to be Disposed of
 Investment to be Held

 North East Offshore
 South Fork Class B Member, LLC

 South Fork Wind Holdings, LLC Class A

 Total Offshore Wind Investments

 Sunrise Wind
 Revolution Wind

 Carrying Value as of December 31, 2023, before
 Impairment Charge
 $
 $
 $
 $
 $
 2,282

 Fourth Quarter 2023 Impairment Charge
 (1,218)
 (544)
 —
 (4)
 (1,766)

 Carrying Value as of December 31, 2023
 $
 (519)
 $
 $
 $
 $

 During 2024, Eversource sold its interest in the North East Offshore and South Fork Class B, Member LLC equity method investments and recognized an aggregate, net after-tax loss on the sale of its offshore wind investments of $524 million.

 Capital contributions in the offshore wind investments, including the 2023 contribution for the tax equity investment in South Fork Wind, were included in Investments in Unconsolidated Affiliates on the statements of cash flows. Proceeds received from the sale of the investments in 2024, and proceeds received from the 2023 sale of the unused lease area and from an October 2023 distribution of $318 million received primarily as a result of being a 50 percent joint owner in the Class B shares of South Fork Wind which was restructured as a tax equity investment, were included in Proceeds from Unconsolidated Affiliates on the statements of cash flows.

 FERC Regulatory Matters

 FERC ROE Complaints: Four separate complaints were filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15-month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive (incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable.

 The ROE originally billed during the period October 1, 2011 (beginning of the first complaint period) through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, FERC issued Opinion No. 531-A and set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the first complaint period. This was also effective for all prospective billings to customers beginning October 16, 2014. This FERC order was vacated on April 14, 2017 by the U.S. Court of Appeals for the D.C. Circuit (the Court).

 All amounts associated with the first complaint period have been refunded. Eversource has recorded a reserve of $39.1 million (pre-tax and excluding interest) for the second complaint period as of both December 31, 2024 and 2023. This reserve represents the difference between the billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $21.4 million for CL&P, $14.6 million for NSTAR Electric and $3.1 million for PSNH as of both December 31, 2024 and 2023.

 On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of the overall ROE methodology determined in the October 16, 2018 order provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results.

 The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, for the NETOs, which FERC concludes are of average financial risk, the preliminary just and reasonable base ROE is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent. If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order.

 On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases. On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in their four pending cases. FERC Opinion Nos. 569-A and 569-B were appealed to the Court. On August 9, 2022, the Court issued its decision vacating MISO ROE FERC Opinion Nos. 569, 569-A and 569-B and remanded to FERC to reopen the proceedings. The Court found that FERC's development of the new return methodology was arbitrary and capricious due to FERC's failure to offer a reasonable explanation for its decision to reintroduce the risk-premium financial model in its new methodology for calculating a just and reasonable return.

 On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings. The order addressed the Court's decision that the reintroduction of the risk-premium financial model in the ROE methodology was arbitrary and capricious by removing the risk-premium financial model from the ROE methodology. The removal of the risk-premium financial model was the only revision to FERC's ROE methodology and resulted in a two-model approach utilizing the two-step discounted cash flow model and the capital asset pricing model. MISO was directed to provide refunds for the period November 12, 2013 to February 11, 2015 (the first MISO ROE complaint refund period) and for the period from September 28, 2016 (the date of FERC's order on the first MISO ROE complaint) to October 17, 2024 by December 1, 2025. The order also stated that FERC does not preclude the use of the risk-premium financial model in future proceedings if the parties can demonstrate that FERC's stated concerns around the inclusion of the model have been addressed.

 On November 13, 2024, the NETOs filed a supplemental brief in their four pending ROE proceedings to explain to FERC that it cannot apply the reasoning and methodologies of the MISO ROE case to the NETOs' cases due to the entirely different set of facts in the MISO and NETOs ROE proceedings. Doing so would violate the substance of the Court's April 14, 2017 order and would violate the legal standard required by the Federal Power Act.

 On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing. The petition requests review of FERC's decision to retroactively backdate the MISO transmission owners' base ROE to the date of an earlier order that FERC abandoned when it issued Order No. 569, treat an underlying unlawful complaint as if it were legitimate, and order eight years of interest as part of the directed refunds.

 Given the significant uncertainty regarding the applicability of the FERC order in the MISO transmission owners' two complaint cases to the NETOs' pending four complaint cases due to the complex differences between the cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaints or subsequent periods at this time and Eversource cannot reasonably estimate any potential range of loss for any of the four complaint proceedings at this time. The resolution of these proceedings could have a material impact on the financial condition, results of operations, and cash flows.

 Eversource, CL&P, NSTAR Electric and PSNH currently record revenues at the 10.57 percent base ROE and incentive cap at 11.74 percent established in the October 16, 2014 FERC order.

 A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource's after-tax earnings by an average of approximately $3 million for each of the four 15-month complaint periods. Prospectively from the date of a final FERC order implementing a new base ROE, based off of estimated 2024 rate base, a change of 10 basis points to the base ROE would impact Eversource's future annual after-tax earnings by approximately $6 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure.

 Transmission Rates and Other Transmission Rates-Related Proceedings: CL&P, NSTAR Electric and PSNH transmission rates are calculated in accordance with a FERC-approved formula ratemaking framework and each utility is required to file an annual update on or before July 31st with resulting rates effective January 1st the following year. The formula rate framework provides for an annual reconciliation of the prior calendar year actual costs incurred related to our transmission facilities, including an allowed ROE, plus forecasted information through the next rate period. The annual update process includes formula rate protocols that provide disclosure of cost inputs, an opportunity for informal discovery procedures and a challenge process, which provides transparency to stakeholders.

 From time to time, various matters are pending before FERC relating to transmission rates, incentives, interconnections and transmission planning. Depending on the outcome, any of these matters could materially impact our results of operations and financial condition. At this time, Eversource cannot predict the ultimate outcome of the matters currently pending before FERC, and the resulting impact on its transmission incentives or planning.

 Regulatory Developments and Rate Matters

 Electric, Natural Gas and Water Utility Retail Tariff Rates: Each Eversource utility subsidiary is subject to the regulatory jurisdiction of the state in which it operates: CL&P, Yankee Gas and Aquarion operate in Connecticut and are subject to PURA regulation; NSTAR Electric, NSTAR Gas, EGMA and Aquarion operate in Massachusetts and are subject to DPU regulation; and PSNH and Aquarion operate in New Hampshire and are subject to NHPUC regulation. The regulated companies' distribution rates are set by their respective state regulatory commissions, and their tariffs include mechanisms for periodically adjusting their rates for the recovery of specific incurred costs.

 Base Distribution Rates: In Connecticut, PURA is required to conduct a review and investigation of the financial and operating records of each electric, natural gas and water utility serving more than seventy-five thousand customers within four years of its last general rate hearing. PURA can elect to convene a general rate hearing at an interval of less than four years unless prohibited from doing so by an agency decision or other law. In Massachusetts, electric distribution companies are required to file distribution rate schedules every five years, and natural gas local distribution companies to file distribution rate schedules every 10 years, and those companies are limited to one settlement agreement in any 10-year period. Aquarion is not required to initiate a rate review with the DPU. In New Hampshire, PSNH is not required to initiate a rate review with the NHPUC on any set timeframe, and the NHPUC has no obligation to hear any rate matter that it has investigated within a period of two years, though it may elect to do so at its discretion.

 Rate Reconciling Mechanisms: The Eversource electric distribution companies obtain and resell power to retail customers who choose not to buy energy from a competitive energy supplier. CL&P, NSTAR Electric and PSNH enter into full requirements energy supply procurement contracts for its customers that choose to purchase power from the electric distribution company (standard offer, basic service or default energy service, respectively). The natural gas distribution companies procure natural gas for firm and seasonal customers. These energy supply and natural gas supply procurement costs are recovered from customers in supply rates that are approved by the respective state regulatory commission. The rates are reset periodically (every six months for electric residential customers) and are fully reconciled to their costs. New energy supply rates for residential customers are established effective July 1st at CL&P and NSTAR Electric and effective August 1st at PSNH. Each electric and natural gas distribution company fully recovers its energy supply costs through approved regulatory rate mechanisms on a timely basis and, therefore, such costs have no impact on earnings. Increases or decreases in energy supply retail rates result in corresponding fluctuations in both energy supply procurement revenues and purchased power or purchased natural gas expenses on the statements of income.

 The electric and natural gas distribution companies also recover certain other costs from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, state mandated energy purchase agreements and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. The reconciliation filings compare the total actual costs allowed to revenue requirements related to these services and the difference between the costs incurred (or the rate recovery allowed) and the actual costs allowed is deferred and included, to be either recovered or refunded, in future customer rates. These cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings.

 Connecticut:

 CL&P Performance Based Rate Making: On May 26, 2021, in accordance with an October 2020 Connecticut law, PURA opened a proceeding to begin to evaluate and eventually implement performance-based regulation (PBR) for electric distribution companies. PURA is conducting the proceeding in two phases. On January 25, 2023, PURA staff issued a proposal outlining a suggested portfolio of PBR elements for further exploration and potential implementation in the second phase of the proceeding. On April 26, 2023, PURA issued a final decision on the first phase and identified various objectives to guide PBR development and evaluate adoption of a PBR framework. The decision commenced Phase 2 by initiating three reopener dockets focused on revenue adjustment mechanisms, performance metrics and integrated distribution system planning with final decisions expected in 2025.

 On November 16, 2023, PURA issued a straw proposal in the first reopener that focused on revenue adjustment mechanisms. The proposal outlines potential additions and reforms to the current revenue adjustment mechanisms, such as multi-year rate plans, earnings sharing mechanisms and the revenue decoupling mechanism. On March 14, 2024, PURA issued a straw proposal in the second reopener docket which concentrates on performance mechanisms in a PBR framework. The proposal suggests the development of performance incentive mechanisms, reported metrics and scorecards. These straw proposals are not authoritative and additional technical sessions, hearings and testimony will continue prior to a final decision, which will not be applied until the time of CL&P's next distribution rate case. PURA is expected to issue updated straw proposals in the first and second reopener dockets in the first quarter of 2025.

 We continue to monitor developments in this proceeding, and at this time, we cannot predict the ultimate outcome of this proceeding and the resulting impact to CL&P.

 CL&P Storm Filings: On March 28, 2024, PURA established a prudency review proceeding for the purpose of receiving and reviewing evidence of the costs reported by CL&P in response to catastrophic storms and pre-staging events totaling approximately $634 million that occurred between January 1, 2018 and December 31, 2021. PURA established a partial procedural schedule with hearings scheduled in the third quarter of 2025. On December 31, 2024, CL&P filed a supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for nine additional catastrophic storms and two additional pre-staging events for the period January 1, 2022 through January 31, 2023 totaling approximately $173 million. Although we cannot predict the ultimate outcome of this matter, we continue to believe these deferred storm restoration costs were prudently incurred and are probable of recovery.

 CL&P RAM Filing: On April 17, 2024, PURA issued an interim decision in CL&P's Rate Adjustment Mechanisms (RAM) filing and approved rates for six RAM components, with rates effective July 1, 2024 through April 30, 2025. The rate approvals include the recovery of NBFMCC and SBC net underrecoveries as of December 31, 2023 of $264.9 million and $86.2 million, respectively, and the recovery of expected net costs of $388.5 million for the NBFMCC and $254.4 million for the SBC for the period July 1, 2024 through April 30, 2025. The NBFMCC rate adjustment is primarily driven by long-term nuclear power purchase agreements required by state policy (Millstone and Seabrook) and the SBC rate adjustment is primarily driven by costs associated with accounts receivable hardship customer protection and the new low-income discount rate effective December 2023. On August 14, 2024, PURA issued a final decision that approved a further adjustment to the NBFMCC rate to include the recovery of incurred and deferred electric vehicle program costs from 2021 through May 31, 2024 of $44.4 million and expected electric vehicle program costs from June 1, 2024 through December 31, 2024 of $24.3 million. The $44.4 million, plus $5.4 million in carrying costs, will be recovered over a 20-month period of September 1, 2024 through April 30, 2026, and the $24.3 million will be recovered over an eight-month period of September 1, 2024 through April 30, 2025. In addition, PURA approved an incremental $3.5 million of 2024 Innovative Energy Solutions program costs and $1.5 million of Connecticut Green Bank program costs over an eight-month period of September 1, 2024 through April 30, 2025. These amounts are included in the "Public Benefits" portion of the customer bills in Connecticut.

 CL&P Advanced Metering Infrastructure Filing: On January 3, 2024, PURA issued a final decision regarding CL&P's Advanced Metering Infrastructure (AMI) investment and implementation plan, which CL&P estimated at $766.4 million for capital costs and operating expenses. In CL&P's view, the final decision does not provide a reasonable path for cost recovery and delays implementation by at least a year during the pendency of the cost recovery proceeding. In addition, in CL&P's view, the final decision modifies the prudence standard for recovery of costs expended on the project, improperly linking recovery to outcomes not known at the outset of the project. On January 18, 2024, CL&P submitted a motion for reconsideration to PURA, asking that the agency modify these aspects of the decision, which PURA subsequently denied on February 14, 2024. On March 6, 2024, CL&P filed written comments citing four major problems associated with PURA's guidelines for recovery of the costs of AMI implementation, which if not addressed, represent obstacles to AMI implementation in Connecticut. On April 16, 2024, PURA issued a procedural order directing Eversource and inviting all parties and intervenors to submit pre-filed testimony pertaining to AMI by May 14, 2024, and rebuttal testimony by May 29, 2024. CL&P witnesses filed testimony, including an updated estimate of $855 million for capital costs and operating expenses, and then subsequently participated in the AMI cost recovery hearing on June 6, 2024.

 On October 17, 2024, PURA issued a proposed final decision on recovery of the costs for AMI implementation. Written exceptions to the proposed final decision were filed on October 31, 2024, and oral arguments were presented on November 7, 2024. CL&P's written exceptions focused on three main aspects of the proposed decision, which include (1) clarifying the prudence standard to be used in evaluating AMI investments, (2) timing of prudency reviews, and (3) cost recovery related to incremental O&M expenses. On December 4, 2024, PURA issued a final decision on the recovery of costs for AMI implementation. On December 9, 2024, CL&P filed a petition for reconsideration because PURA had not fully resolved the issues CL&P raised in its October 31, 2024 written exceptions. On January 3, 2025, PURA stated it will evaluate the merits of CL&P's petition for reconsideration. Under state law, PURA is expected to issue its decision within 90 days of January 3, 2025.

 Yankee Gas Distribution Rate Case: On November 12, 2024, Yankee Gas filed an application with PURA to amend its existing distribution rates for effect on November 1, 2025. Yankee Gas's rate application requested approval of a distribution rate increase of $209 million, which included a base distribution rate increase of $274 million, partially offset by a reduction of $65 million in the combined Gas System Improvements and System Expansion Reconciliation rates. In addition, Yankee Gas requested approval to implement a rate credit of $37.4 million to offset the PGA rate for non-firm margin credits over one year beginning November 1, 2025. As part of the rate case, Yankee Gas proposed to implement a multi-year performance-based rate making plan with a four-year initial term from November 1, 2025 to October 31, 2029 that would adjust rates annually and includes performance metrics. A final decision by PURA is expected in October 2025.

 Aquarion Water Company of Connecticut Distribution Rate Case: On August 29, 2022, Aquarion Water Company of Connecticut (AWC-CT) filed an application with PURA to amend its existing rate schedules to address an operating revenue deficiency. AWC-CT's rate application requested approval of rate increases of $27.5 million, an additional $13.6 million, and an additional $8.8 million, effective March 15, 2023, 2024, and 2025, respectively. On March 15, 2023, PURA issued a final decision that rejected this request. In this decision, PURA ordered a decrease to total authorized revenues of $4.0 million effective March 15, 2023. The decision allows an authorized regulatory ROE of 8.70 percent. On March 30, 2023, AWC-CT filed an appeal on the decision and requested a stay of the decision with the State of Connecticut Superior Court. On April 5, 2023, the Court temporarily granted AWC-CT's request to stay and on May 25, 2023 granted a permanent stay of certain orders affecting base rates, which would keep existing rates in place until the appeal is completed. The stay included the condition that AWC-CT place any revenue received from customers above the rates and amounts authorized in the March 15, 2023 decision in a separate, interest bearing account until further order. On March 25, 2024, the State of Connecticut Superior Court issued a decision on the appeal which dismissed nine, remanded back to PURA two, and partially remanded one of AWC-CT's twelve claims of error in its appeal. On March 28, 2024, AWC-CT filed an appeal of the Connecticut Superior Court decision to the Connecticut Appellate Court, and that appeal was subsequently transferred to the Connecticut Supreme Court for review. A ruling on the appeal is pending.

 On April 18, 2024, PURA initiated a docket to address the matters on remand. On July 31, 2024, PURA issued a final decision in this docket and increased AWC-CT's approved revenue requirement by $0.1 million above the amount authorized in the March 15, 2023 decision. Rates went into effect on July 31, 2024. On September 13, 2024, AWC-CT filed an appeal of PURA's July 31, 2024 final decision to the Connecticut Superior Court. A ruling on the appeal is pending.

 As a result of the State of Connecticut Superior Court's March 2024 decision on the appeal, AWC-CT recorded the impacts of the PURA rate case decision from the effective date of the order on March 15, 2023 through December 31, 2024. The impacts primarily include a reduction to depreciation expense to reflect lower depreciation rates ordered by PURA in its final decision, partially offset by lower authorized revenues. These adjustments resulted in an after-tax benefit of $11.6 million in 2024.

 Massachusetts:

 NSTAR Electric Distribution Rates: NSTAR Electric's PBR mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. On September 16, 2024, NSTAR Electric submitted its annual PBR Adjustment filing for a $55.8 million increase to base distribution rates, for effect on January 1, 2025. The requested base distribution rate increase is comprised of a $35.3 million inflation-based adjustment and a $20.5 million adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement. On December 23, 2024, the DPU approved this filing.

 NSTAR Electric CIP Filing: On December 30, 2022, the DPU approved a provisional system planning tariff for the recovery of costs associated with a capital investment project (CIP) proposal submitted by NSTAR Electric for one of six geographic study areas in its service territory in accordance with DPU's directives. The DPU established a new, provisional framework for planning and funding upgrades to the electric power system to foster development and interconnection of distributed energy facilities. Under the DPU program, NSTAR Electric has filed infrastructure upgrade proposals to be built within a four-year construction timeframe that allocate the costs of interconnection upgrades between the interconnecting distributed generation facility and distribution customers based on a technical analysis of capacity benefits. Payments made by the distributed generation facility will be applied against the total capital investment made by NSTAR Electric and NSTAR Electric will earn a return on the net investment. The amount allocated to distribution customers will be recovered through a reconciling mechanism, the Provisional System Planning Tariff. The DPU approved the first of these provisional system planning projects, the Marion-Fairhaven group study area, which will enable 141 MW of distributed energy resources (DER) to be interconnected at a total estimated cost of $120 million. Of the total $120 million, $66 million will be allocated to distribution customers, once the enabled distributed energy facilities capacity is fully subscribed by distributed energy facilities interconnecting customers. Additionally, NSTAR Electric will proceed with construction of approximately $54 million of transmission upgrades necessary to improve local reliability and integrate distribution energy resources in the Marion-Fairhaven area and recover the amount through local transmission rates.

 On June 4, 2024, the DPU approved four of the remaining five CIPs that were originally submitted by NSTAR Electric. These included the Plainfield-Blandford CIP, which will enable 40 MW of DER to be interconnected at a total estimated distribution investment of $37 million, the Dartmouth-Westport CIP which enables 60 MW of DER for a total distribution investment of $58 million, the Plymouth CIP which enables 380 MW of DER for a total distribution investment of $152 million and the Cape Cod CIP which enables 296 MW of DER for a total distribution investment of $170 million. Of the total $417 million for these four recently approved CIPs, $183 million will be allocated to distribution customers, once the enabled distributed energy facilities capacity is fully subscribed by distributed energy facilities interconnecting customers. Additionally, NSTAR Electric will proceed with construction of approximately $64 million of transmission upgrades necessary to improve local reliability and integrate distribution energy resources in the four CIP areas and recover the amount through local transmission rates. On January 27, 2025, NSTAR Electric filed a petition with the DPU to withdraw the sixth CIP project, Freetown, that was originally submitted.

 NSTAR Electric's Electric Sector Modernization Plan (ESMP) Filing: On January 29, 2024, in accordance with Massachusetts state law, NSTAR Electric filed its ESMP with the DPU. The law required each electric distribution company to develop and file a comprehensive distribution system plan to proactively upgrade the distribution system (and, where applicable, the associated transmission system) to: (i) improve grid reliability, communications and resiliency; (ii) enable increased, timely adoption of renewable energy and distributed energy resources; (iii) promote energy storage and electrification technologies necessary to decarbonize the environment and economy; (iv) prepare for future climate-driven impacts on the transmission and distribution systems; (v) accommodate increased transportation electrification, increased building electrification and other potential future demands on distribution and, where applicable, the transmission system; and (vi) minimize or mitigate impacts on Massachusetts ratepayers, thereby helping the state realize its statewide greenhouse gas emissions limits and sublimits under the law. NSTAR Electric's plan meets these requirements by providing a comprehensive view of all the investments required to build a safer, more reliable, more resilient electric distribution system to enable an affordable, equitable clean energy transition taking into account the needs of environmental justice communities. For the five-year period from 2025 through 2029, the proposed incremental distribution capital investment is $608 million and the incremental distribution expense amount is $211 million. On August 29, 2024, the DPU approved the overall ESMP for a five-year period commencing July 1, 2025.

 On November 21, 2024, the DPU opened a second phase of the proceeding to consider a short-term ESMP-focused cost recovery mechanism and metrics. In issuing the notice of proceeding, the DPU limited the review of investment in this docket and excluded NSTAR Electric's ESMP proposals regarding the EV Phase II extension, low and moderate income solar and the new CIPs. These investments will be reviewed in separate proceedings. This reduced the amount of company-proposed incremental capital investment to $295 million and the incremental expense to $44 million related to resiliency and grid modernization. NSTAR Electric filed its proposed tariff and testimony on December 18, 2024, and is currently in the discovery process, which will be followed by hearings and briefing with completion of the proceeding and final orders expected prior to the start of the plan in July 2025.

 NSTAR Gas Distribution Rates: NSTAR Gas' PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On September 16, 2024, NSTAR Gas submitted its annual PBR Adjustment filing for a $12.7 million increase to base distribution rates for effect on November 1, 2024. On October 30, 2024, the DPU approved this filing.

 EGMA Distribution Rates: On November 4, 2024, EGMA submitted a revised filing for its first rate base reset for rates to be effective November 1, 2024, in accordance with an October 7, 2020 EGMA Rate Settlement Agreement approved by the DPU. The compliance filing was ordered by the DPU on October 31, 2024. The rate base reset occurring on November 1, 2024 adjusted distribution rates to account for capital additions (including the roll-in of GSEP capital additions), depreciation expense, property taxes, and return on rate base for capital additions placed into service through December 31, 2023. The total revenue requirement calculated for the first rate base reset is an increase to base distribution rates of $147.8 million, of which $34.0 million is associated with GSEP investments through December 31, 2023. Under the terms of the Rate Settlement Agreement, EGMA applied a cap on the revenue change effective November 1, 2024, and the amount in excess of the cap will be deferred for recovery through the Local Distribution Adjustment Clause (LDAC) on May 1, 2025, including carrying charges. After adjusting for the cap, the increase to base distribution rates is $85.6 million effective November 1, 2024 (of which $8.8 million is offset by a reduction in the GSEP revenue requirement and GSEP rate also taking effect on November 1, 2024 for a net distribution rate change on November 1, 2024 of $76.8 million). Base distribution rates will be increased effective November 1, 2025 to incorporate the $62.2 million remaining revenue requirement. On November 7, 2024, the DPU approved this filing.

 Future of Gas Docket: In October 2020, the DPU opened Docket "DPU 20-80 The Future of Gas" to examine the role of Massachusetts natural gas local distribution companies (LDCs) in helping to meet the state's 2050 climate goals. In December 2023, the DPU issued an order for this docket. The DPU will consider and, in some cases, require new processes and analysis for traditional natural gas investments, which may require significant changes to the LDC planning process and business models. The DPU intends to put policies and structures in place that would protect customers as Massachusetts works to decarbonize the building sector, which may involve subsequent dockets and regulatory proceedings and potentially recasting the role of LDCs in Massachusetts. The DPU preserved customer choice for energy needs and encouraged further development of decarbonized alternatives, such as the networked geothermal systems that NSTAR Gas is piloting in Framingham, Massachusetts.

 On December 29, 2023, Eversource and other LDCs sought formal clarity from the DPU to fully understand the resulting impact to their natural gas businesses and the associated timing of any impacts. On April 2, 2024, the DPU issued an order responding to the request for clarification indicating that the LDCs shall implement the inclusion of a Non-Gas Pipeline Alternatives (NPA) analysis on all project authorizations effective immediately. Existing NPA analysis processes will be used until such time a formal stakeholder-based NPA analysis framework is established and approved by the DPU. Eversource, along with the other LDCs, have engaged a consultant to inform the development of the required NPA framework by conducting a stakeholder engagement process as mandated by the order. Another component of the order is the submission of climate compliance plans every five years beginning April 1, 2025. The climate compliance plan filings will include the NPA frameworks, along with energy transitions plans including details on the management of embedded infrastructure investments and cost recovery. Eversource along with the LDCs, have also contracted a consultant to model and investigate statewide cost recovery scenarios including under accelerated depreciation rates.

 The DPU also indicated that NSTAR Gas and EGMA are not required to provide climate compliance performance metrics in the next PBR filing, however would be expected to propose metrics at the latest in the next base distribution rate proceeding. GHG emissions reporting was not changed from the order, however, effective November of 2024, reporting requirements have changed per the MA DEP and these requirements implement registration and GHG emissions reporting requirements for companies selling and distributing heating fuels to homes and businesses in Massachusetts, including suppliers of natural gas, fuel oil, and propane, and implement a reporting requirement for fuel storage facilities.

 Eversource does not believe there is any indication of an inability to recover costs or risk of impairment of NSTAR Gas' and EGMA's natural gas assets at this time.

 New Hampshire:

 PSNH Distribution Rate Case: On June 11, 2024, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase. On July 31, 2024, the NHPUC approved a settlement agreement that was reached by PSNH, New Hampshire Department of Energy, and the Office of the Consumer Advocate to implement a temporary annual base distribution rate increase of $61.2 million effective August 1, 2024.

 Also on June 11, 2024, PSNH filed an application with the NHPUC to request an increase in permanent base distribution rates of $181.9 million, which is inclusive of the temporary rate increase, and proposed to take effect August 1, 2025. The temporary rates are subject to reconciliation based on the outcome of the permanent rate case back to the date when temporary rates took effect. The permanent rate increase request includes $247 million in unrecovered storm costs to be recovered over a five-year period. As part of the rate case, PSNH proposed to implement a performance-based rate making plan that would adjust rates annually over a four-year term, with a commitment to not file another rate case for at least four years. The plan includes a revenue-cap formula adjusted for inflation, a supplemental capital adjustment formula to support PSNH's planned capital infrastructure improvements, an exogenous events recovery mechanism, performance metrics and an earnings sharing mechanism, among others. If the NHPUC approves the performance-based rate making plan as proposed, the previously established RRA and PPAM rate reconciling mechanisms and lost base revenues will be eliminated. The NHPUC is permitted up to twelve months to investigate the proposed rates and issue a final order. A decision by the NHPUC on permanent rates is expected by August 1, 2025.

 Legislative and Policy Matters

 Federal: On April 10, 2024, the U.S. Environmental Protection Agency announced the final regulation setting drinking water standards for six per- and polyfluoroalkyl substances (PFAS) compounds. The regulation requires compliance under a phased approach in which systems will need to complete the initial monitoring requirements for each PFAS within three years, and when warranted, take steps to assure compliance within five years. Beginning in 2027, systems will need to report results of initial monitoring and regular monitoring and issue public notifications for any monitoring and reporting violations. Starting in 2029, systems must comply with all maximum contaminant levels (MCL) and provide public notification for MCL violations. Eversource is currently evaluating the impacts to comply with the regulation for its water business.

 Critical Accounting Policies

 The preparation of financial statements in conformity with GAAP requires management to make estimates, assumptions and, at times, difficult, subjective or complex judgments. Changes in these estimates, assumptions and judgments, in and of themselves, could materially impact our financial position, results of operations or cash flows. Our management discusses with the Audit Committee of our Board of Trustees significant matters relating to critical accounting policies. Our critical accounting policies are discussed below. See the combined notes to our financial statements for further information concerning the accounting policies, estimates and assumptions used in the preparation of our financial statements.

 Regulatory Accounting: Our regulated companies are subject to rate regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The regulated companies' financial statements reflect the effects of the rate-making process. The rates charged to the customers of our regulated companies are designed to collect each company's costs to provide service, plus a return on investment.

 We believe that the operations of each of our regulated companies currently satisfy the criteria for application of regulatory accounting. If events or circumstances should change in a future period so that those criteria are no longer satisfied, we would be required to eliminate any associated regulatory assets and liabilities and the impact would be recognized in the statement of income and may result in a material adverse effect on results of operations and financial condition.

 The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. In some cases, we record regulatory assets before approval for recovery has been received from the applicable regulatory commission. We must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. We base our conclusion on certain factors, including, but not limited to, regulatory precedent.

 Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers. We make judgments regarding the future outcome of regulatory proceedings that involve potential future refund to customers and record liabilities for these loss contingencies when probable and reasonably estimable based upon available information. Regulatory liabilities are recorded at the best estimate, or at a low end of the range of possible loss. The amount recorded may differ from when the uncertainty is resolved. Such differences could have a significant impact on our financial statements.

 We continually assess whether the regulatory assets and liabilities continue to meet the criteria for probable future recovery or refund. This assessment includes consideration of recent orders issued by regulatory commissions, the passage of new legislation, historical regulatory treatment for similar costs in each of our jurisdictions, discussions with legal counsel, the status of any appeals of regulatory decisions, and changes in applicable regulatory and political environments. We believe that we will continue to be able to defer and recover prudently incurred costs, including additional storm costs, based on the legal and regulatory framework.

 We use judgment when recording regulatory assets and liabilities; however, regulatory commissions can reach different conclusions about the recovery of costs, and those conclusions could have a material impact on our financial statements. The ultimate outcome of regulatory rate proceedings could have a significant effect on our ability to recover costs or earn an adequate return. Established rates are also often subject to subsequent prudency reviews by state regulators, whereby various portions of rates could be adjusted, subject to refund or disallowed.

 Storm restoration and pre-staging costs are subject to prudency reviews from our regulators. We have $2.10 billion of deferred storm costs that either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review as of December 31, 2024. Tropical Storm Isaias in August 2020 resulted in deferred storm restoration costs of approximately $232 million at CL&P as of December 31, 2024. While it is possible that some amount of the Tropical Storm Isaias costs may be disallowed by PURA, any such amount cannot be estimated at this time. We believe that our storm restoration costs were prudently incurred, meet the criteria for cost recovery and are probable of recovery.

 We believe it is probable that each of our regulated companies will recover its respective investments in long-lived assets and the regulatory assets that have been recorded. If we determine that we can no longer apply the accounting guidance applicable to rate-regulated enterprises, or that we cannot conclude it is probable that costs will be recovered from customers in future rates, the applicable costs would be charged to net income in the period in which the determination is made.

 Pension, SERP and PBOP: We sponsor Pension, SERP and PBOP Plans to provide retirement benefits to our employees. Plan assets and the benefit obligation are presented on a net basis and we recognize the overfunded or underfunded status of the plans as an asset or liability on the balance sheet. These amounts are remeasured annually using a December 31st measurement date. For each of these plans, several significant assumptions are used to determine the projected benefit obligation, funded status, and net periodic benefit expense/income. These assumptions include the expected long-term rate of return on plan assets, discount rate, compensation/progression rate, cash balance interest crediting rate and mortality and retirement assumptions. We evaluate these assumptions annually and adjust them as necessary. Changes in these assumptions could have a material impact on our financial position, results of operations or cash flows.

 Expected Long-Term Rate of Return on Plan Assets Assumption: In developing the expected long-term rate of return, we consider historical and expected returns, as well as input from our consultants. Our expected long-term rate of return on assets is based on assumptions regarding target asset allocations and corresponding expected rates of return for each asset class. We routinely review the actual asset allocations and periodically rebalance the investments to the targeted asset allocations. For the year ended December 31, 2024, our expected long-term rate-of-return assumption used to determine our pension and PBOP expense was 8.25 percent for the Eversource Service Pension and PBOP plans. For the forecasted 2025 pension and PBOP expense, an expected long-term rate of return of 8.25 percent for the Eversource Service Pension and PBOP plans will be used reflecting our target asset allocations.

 Discount Rate Assumptions: Payment obligations related to the Pension, SERP and PBOP Plans are discounted at interest rates applicable to the expected timing of each plan's cash flows. The discount rate that was utilized in determining the pension, SERP and PBOP obligations was based on a yield-curve approach. This approach utilizes a population of bonds with an average rating of AA based on bond ratings by Moody's, S&P and Fitch, and uses bonds with above median yields within that population. As of December 31, 2024, the discount rates used to determine the funded status were within a range of 5.6 percent to 5.7 percent for the Pension and SERP Plans, and 5.7 percent for the PBOP Plans. As of December 31, 2023, the discount rates used were within a range of 4.9 percent to 5.0 percent for the Pension and SERP Plans, and 5.0 percent to 5.2 percent for the PBOP Plans. The increase in the discount rates used to calculate the funded status resulted in a decrease to the Pension and SERP Plans' projected benefit obligation of $332.9 million and a decrease to the PBOP Plans' projected benefit obligation of $39.8 million as of December 31, 2024.

 The Company uses the spot rate methodology for the service and interest cost components of Pension, SERP and PBOP expense because it provides a relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve. The discount rates used to estimate the 2024 expense were within a range of 4.7 percent to 5.1 percent for the Pension and SERP Plans, and within a range of 4.9 percent to 5.2 percent for the PBOP Plans.

 Mortality Assumptions: Assumptions as to mortality of the participants in our Pension, SERP and PBOP Plans are a key estimate in measuring the expected payments a participant may receive over their lifetime and the corresponding plan liability we need to record. The mortality assumption is composed of a base table that represents the current expectation of life expectancy of the population adjusted by an improvement scale that attempts to anticipate future improvements in life expectancy. In 2024, our mortality assumption utilized the Society of Actuaries base mortality tables (Pri-2012), adjusted to reflect Eversource's own mortality experience, and projected generationally using the MP-2021 improvement scale.

 Compensation/Progression Rate Assumptions: This assumption reflects the expected long-term salary growth rate, including consideration of the levels of increases built into collective bargaining agreements, and impacts the estimated benefits that Pension and SERP Plan participants will receive in the future. As of December 31, 2024 and 2023, the compensation/progression rates used to determine the Pension and SERP Plan funded status were within a range of 3.5 percent to 4.0 percent.

 Health Care Cost Assumptions: The Eversource Service PBOP Plan is not subject to health care cost trends. As of December 31, 2024, for the Aquarion PBOP Plan, the health care trend rate used to determine the funded status for pre-65 retirees is 7.5 percent, with an ultimate rate of 5 percent in 2035, and for post-65 retirees, the health care trend rate and ultimate rate is 3.5 percent.

 Cash Balance Interest Crediting Rate Assumption: The Cash Balance Pension Plan is a new, additional obligation of the existing Pension Plan and the liability will begin to accrue benefits upon the effective date of January 1, 2025. The cash balance interest crediting rate assumption represents the long-term rate by which the Pension Plan's cash balance accounts are expected to grow. Actual interest on the cash balance accounts is based on the 30-year U.S. Treasury securities rate in effect for September of the preceding year, with a minimum rate of 4 percent. The cash balance interest crediting rate assumption used in determining the forecasted 2025 pension expense was 4.8 percent.

 Actuarial Gains and Losses: Actuarial gains and losses represent the differences between actuarial assumptions and actual information or updated assumptions. Unamortized actuarial gains or losses arising at the December 31st measurement date are primarily from differences in actual investment performance compared to our expected return and changes in the discount rate assumption. The Eversource Service Pension and PBOP Plans use the corridor approach to determine the amount of gain or loss to amortize into net periodic benefit expense/income. The corridor approach defers all actuarial gains and losses arising at remeasurement and the net unrecognized actuarial gain or loss balance is amortized as a component of expense if, as of the beginning of the year, that net gain or loss exceeds 10 percent of the greater of the market value of the plan's assets or the projected benefit obligation. The amount of net unrecognized actuarial gain or loss in excess of the 10 percent corridor is amortized to expense over the estimated average future employee service period. For the Eversource Service Pension Plan, the net actuarial gain or loss is amortized as a component of expense over the estimated average future employee service period of eleven years. For the Eversource Service PBOP Plan, the net unrecognized actuarial gain or loss was within the 10 percent corridor and therefore there was no amortization to expense during 2024.

 A decrease in the discount rate used to determine our pension funded status would increase our projected benefit obligation at December 31st, resulting in a higher unamortized actuarial loss to be recognized in future years' pension expense, subject to exceeding the 10 percent corridor. A decrease in the discount rate at December 31st would also result in a decrease in the interest cost component and an increase in the service cost component of the subsequent year's benefit plan expense.

 The calculated expected return on plan assets is compared to the actual return or loss on plan assets at the end of each year to determine the investment gains or losses to be immediately reflected in unamortized actuarial gains and losses. An underperformance of our pension plan investment returns relative to the expected returns would increase our pension liability at December 31st, resulting in a higher unamortized actuarial loss to be recognized in future years' pension expense, subject to exceeding the 10 percent corridor, and a lower expected return on assets component of pension expense in future years' pension expense.

 Net Periodic Benefit Expense/Income: Pension, SERP and PBOP expense/income is determined by our actuaries and consists of service cost and prior service cost/credit, interest cost based on the discounting of the obligations, amortization of actuarial gains and losses, and the expected return on plan assets. For the Pension and SERP Plans, pre-tax net periodic benefit income was $76.8 million, $108.4 million and $181.6 million for the years ended December 31, 2024, 2023 and 2022, respectively. For the PBOP Plans, pre-tax net periodic benefit income was $64.3 million, $57.3 million and $79.8 million for the years ended December 31, 2024, 2023 and 2022, respectively.

 The change in pension, SERP and PBOP expense/income arising from the annual remeasurement does not fully impact earnings. Our Massachusetts utilities recover qualified pension and PBOP expenses related to their distribution operations through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year, therefore the change in their pension and PBOP expense does not impact earnings. Our electric transmission companies' rates provide for an annual true-up of estimated to actual costs, which include pension expenses, therefore the change in their pension expense does not impact earnings. Any differences between the fixed level of PBOP expense included in our formula rate and the PBOP expense calculated in accordance with authoritative accounting guidance is accumulated as a regulatory asset or liability, and is expected, over time, to be recovered from or returned to customers. Additionally, the portion of our pension and PBOP expense that relates to company labor devoted to capital projects is capitalized on the balance sheet instead of being charged to expense.

 Forecasted Expense/Income and Expected Contributions: We estimate that net periodic benefit income in 2025 for the Pension and SERP Plans will be approximately $93 million and for the PBOP Plans will be approximately $69 million. The increase in pension income from 2024 to 2025 is driven primarily by lower amortization of actuarial losses, partially offset by an increase in the service cost component, both of which were due in part to the impact of the new cash balance pension plan. The increase in PBOP income from 2024 to 2025 is driven primarily by favorable expected return on assets due to a higher asset balance. For the PBOP Plans, there is no amortization of actuarial loss in 2025. Pension, SERP and PBOP expense/income for subsequent years will depend on future investment performance, changes in future discount rates and other assumptions, and various other factors related to the populations participating in the plans.

 Our policy is to fund the Pension Plans annually in an amount at least equal to the amount that will satisfy all federal funding requirements. Based on the current status of the Pension Plans and federal pension funding requirements, for our Eversource Service Pension Plan there is no minimum funding requirement in 2025 and we do not expect to make pension contributions in 2025. It is our policy to fund the PBOP Plans annually through tax deductible contributions to external trusts. We do not expect to make any contributions to the Eversource Service PBOP Plan in 2025.

 Sensitivity Analysis: The following table illustrates the hypothetical effect on reported annual net periodic benefit income as a result of a change in the following assumptions by 50 basis points:

 Pension Plans (excluding SERP Plans)
 PBOP Plans

 Decrease in Plan Income
 Decrease/(Increase) in Plan Income

 2024
 2023
 2024
 2023

 Lower expected long-term rate of return
 $
 28.9
 $
 29.1
 $
 5.0
 $
 0.2

 Lower discount rate
 27.4
 24.7
 (0.5)
 4.7

 Higher compensation rate
 5.9
 8.1
 N/A
 N/A

 Goodwill: Goodwill is recognized on our balance sheet from previous mergers and acquisitions to the extent that the consideration paid exceeded the net fair value of the identified assets and liabilities acquired in each business combination. We are required to test goodwill balances for impairment at least annually by considering the fair values of the reporting units, which requires us to use estimates and judgments. Additionally, we monitor all relevant events and circumstances during the year to determine if an interim impairment test is required. We have selected October 1st of each year as the annual goodwill impairment test date. Goodwill impairment is deemed to exist if the carrying amount of a reporting unit exceeds its estimated fair value. If goodwill were to be impaired, it would be written down in the current period to the extent of the impairment.

 We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution. The Electric Distribution and Electric Transmission reporting units include carrying values for the respective components of CL&P, NSTAR Electric and PSNH. The Natural Gas Distribution reporting unit includes the carrying values of NSTAR Gas, Yankee Gas and EGMA. The Water Distribution reporting unit includes the Aquarion water utility businesses. As of December 31, 2024, goodwill was allocated to the reporting units as follows: $2.54 billion to Electric Distribution, $577 million to Electric Transmission, and $451 million to Natural Gas Distribution. Goodwill allocated to Water Distribution of $663 million is classified as held for sale.

 In assessing goodwill for impairment, an entity is permitted to first assess qualitatively whether it is more likely than not that goodwill impairment exists as of the annual impairment test date. If we perform the qualitative assessment but determine it is more likely than not that a reporting unit's 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.

 We performed the annual impairment assessment of goodwill as of October 1, 2024 for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units. Our qualitative assessment included an evaluation of multiple factors that impact the fair value of the reporting units, including general, macroeconomic and market conditions, and entity-specific assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, the Company's share price and credit ratings, analyst reports, financial performance, cost and risk factors, internal estimates and projections of future cash flows and net income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings.

 In the fourth quarter of 2024, we concluded that the likely sale of Aquarion at a loss resulted in the requirement to perform an interim goodwill impairment test for Water Distribution goodwill. We compared the estimated fair value of the business from the anticipated transaction to its carrying value. Assumptions used in the valuation were the future cash flows from the sale, including the estimated income tax impacts as a result of the transaction. Based on the interim impairment test, we recorded a goodwill impairment of $297 million to write down the carrying value of the water distribution reporting unit to its estimated fair value.

 We did not identify any events or conditions that make it more likely than not that an impairment may have occurred at our other reporting units. For these remaining reporting units, we believe that the fair value was substantially in excess of carrying value. Adverse regulatory actions, changes in the regulatory and political environment, or changes in significant assumptions could potentially result in future goodwill impairment indicators.

 Long-Lived Assets: Impairment evaluations of long-lived assets, including property, plant and equipment and other assets, involve a significant degree of estimation and judgment, including identifying circumstances that indicate an impairment may exist. An impairment analysis is required when events or changes in circumstances indicate that the carrying value of a long-lived asset may not be recoverable. Indicators of potential impairment include a deteriorating business climate, unfavorable regulatory action, decline in value that is other than temporary in nature, plans to dispose of a long-lived asset significantly before the end of its useful life, and accumulation of costs that are in excess of amounts allowed for recovery. The review of long-lived assets for impairment utilizes significant assumptions about operating strategies and external developments, including assessment of current and projected market conditions that can impact future cash flows. If indicators are present for a long-lived asset or asset group, a comparison of the undiscounted expected future cash flows to the carrying value is performed. No significant impairments occurred during the year 2024.

 Equity Method Investments: Investments in affiliates where we have the ability to exercise significant influence, but not control, over an investee are initially recognized as an equity method investment at cost. Any differences between the cost of an investment and the amount of underlying equity in net assets of an investee are considered basis differences and are determined based upon the estimated fair values of the investee's identifiable assets and liabilities.

 Equity method investments are assessed for impairment when conditions exist as of the balance sheet date that indicate that the fair value of the investment may be less than book value. Eversource continually monitors and evaluates its equity method investments to determine if there are indicators of an other-than-temporary impairment. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations are based on best information available at the impairment assessment date. Subsequent declines or recoveries after the reporting date are not considered in the impairment recognized. Investments that are other-than-temporarily impaired and written down to their estimated fair value cannot subsequently be written back up for increases in estimated fair value. Impairment evaluations involve a significant degree of judgment and estimation, including identifying circumstances that indicate an impairment may exist at the equity method investment level, selecting discount rates used to determine fair values, and developing an estimate of discounted future cash flows expected from investment operations or the sale of the investment.

 During 2023, in connection with the process to divest its offshore wind business, Eversource identified indicators for impairment in both the second and fourth quarters of 2023. In each impairment assessment, Eversource evaluated its investments and determined that the carrying value of the equity method offshore wind investments exceeded the fair value of the investments and that the decline was other-than-temporary. The impairment evaluations involved judgments in developing the estimates and timing of future cash flows, including key judgments in determining the most likely outcome of the projects, the likelihood of realization of investment tax credit adders, and the likelihood of future spending amounts and cost overruns, as well as potential cancellation costs and salvage values of Sunrise Wind assets. The assumptions used in the discounted cash flow analyses were subject to inherent uncertainties and subjectivity. The use of different assumptions, estimates, or judgments with respect to the
 estimation of future cash flows could have materially changed the impairment charges. The impairment charges were non-cash charges and did not impact Eversource's cash position at the time of the impairment. During 2024, Eversource sold its interest in the North East Offshore and South Fork Class B, Member LLC equity method investments and recognized an aggregate, net after-tax loss on the sale of its offshore wind investments of $524 million.

 Loss Contingencies: We make judgments regarding the future outcome of contingent events and record liabilities for loss contingencies that are probable and can be reasonably estimated based upon available information. The assessment of loss contingencies involves judgments and assumptions about future events. Our estimates are subject to revision in future periods based on actual costs or new information. The amount recorded may differ from the actual expense incurred when the uncertainty is resolved. Such difference would be a change in estimate and could have a significant impact on the financial statements.

 Upon the sales of our offshore wind investments in the third quarter of 2024, Eversource recorded a contingent liability of $365 million, reflecting its estimate of the future obligations under the GIP sale terms. Assumptions and key judgments in determining the estimated liability include the expected cost overrun sharing obligation, expected obligation to maintain GIP's internal rate of return, and obligation for other future costs, as well as the likelihood of realization of investment tax credit adders that were included in the purchase price. The use of different assumptions, estimates, or judgments could materially impact the financial statements. New information or future developments that arise as construction progresses and as cost estimates are reviewed and revised will require a reassessment of the estimated liability for the post-closing adjustment payments. Adverse changes in facts and circumstances could result in additional losses that could be material to the financial statements.

 Accounting for Environmental Reserves: Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. Increases to estimates of environmental liabilities could have an adverse impact on earnings. We estimate these liabilities based on findings through various phases of the assessment, considering the most likely action plan from a variety of available remediation options (ranging from no action required to full site remediation and long-term monitoring), current site information from our site assessments, remediation estimates from third party engineering and remediation contractors, and our prior experience in remediating contaminated sites. If a most likely action plan cannot yet be determined, we estimate the liability based on the low end of a range of possible action plans. A significant portion of our environmental sites and reserve amounts relate to former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which we may have potential liability. Estimates are based on the expected remediation plan. Our estimates are subject to revision in future periods based on actual costs or new information from other sources, including the level of contamination at the site, the extent of our responsibility or the extent of remediation required, recently enacted laws and regulations or a change in cost estimates.

 Income Taxes: Income tax expense is estimated for each of the jurisdictions in which we operate and is recorded each quarter using an estimated annualized effective tax rate. This process to record income tax expense involves estimating current and deferred income tax expense or benefit and the impact of temporary differences resulting from differing treatment of items for financial reporting and income tax return reporting purposes. Such differences are the result of timing of the deduction for expenses, as well as any impact of permanent differences, or other items that directly impact income tax expense as a result of regulatory activity (flow-through items). The temporary differences and flow-through items result in deferred tax assets and liabilities that are included in the balance sheets.

 We also account for uncertainty in income taxes, which applies to all income tax positions previously filed in a tax return and income tax positions expected to be taken in a future tax return that have been reflected on our balance sheets. The determination of whether a tax position meets the recognition threshold under applicable accounting guidance is based on facts and circumstances available to us.

 The interpretation of tax laws and associated regulations involves uncertainty since tax authorities may interpret the laws differently. Ultimate resolution or clarification of income tax matters may result in favorable or unfavorable impacts to net income and cash flows, and adjustments to tax-related assets and liabilities could be material.

 Significant management judgment is required in determining the provision for income taxes, primarily due to the uncertainty related to tax positions taken, as well as deferred tax assets and liabilities and valuation allowances. We evaluate the probability of realizing deferred tax assets by reviewing a forecast of future taxable income and our intent and ability to implement tax planning strategies, if necessary, to realize deferred tax assets. We also assess negative evidence, such as the expiration of historical operating loss or tax credit carryforwards, that could indicate the inability to realize the deferred tax assets. Valuation allowances are provided to reduce deferred tax assets to the amount that will more likely than not be realized in future periods. This requires management to make judgments and estimates regarding the amount and timing of the reversal of taxable temporary differences, expected future taxable income, and the impact of tax planning strategies.

 Actual income taxes could vary from estimated amounts due to the future impacts of various items, including future changes in income tax laws, not realizing expected tax planning strategy amounts, as well as results of audits and examinations of filed tax returns by taxing authorities.

 Fair Value Measurements: We follow fair value measurement guidance that defines fair value as the price that would be received for the sale of an asset or paid to transfer a liability in an orderly transaction between market participants at the measurement date (an exit price). We have applied this guidance to our Company's derivative contracts that are not elected or designated as "normal purchases" or "normal sales," to marketable securities held in trusts, and to our investments in our Pension and PBOP Plans. Fair value measurements are also incorporated into the accounting for goodwill, long-lived assets, equity method investments, AROs, and in the valuation of business combinations and asset acquisitions. The fair value measurement guidance was also applied in estimating the fair value of preferred stock, long-term debt and RRBs.

 Changes in fair value of our derivative contracts are recorded as Regulatory Assets or Liabilities, as we recover the costs of these contracts in rates charged to customers. These valuations are sensitive to the prices of energy-related products in future years and assumptions made.

 We use quoted market prices when available to determine the fair value of financial instruments. When quoted prices in active markets for the same or similar instruments are not available, we value derivative contracts using models that incorporate both observable and unobservable inputs. Discounted cash flow valuations incorporate estimates of premiums or discounts, reflecting risk-adjusted profit that would be required by a market participant to arrive at an exit price, using available historical market transaction information. Valuations of derivative contracts also reflect our estimates of nonperformance risk, including credit risk.

 RESULTS OF OPERATIONS – EVERSOURCE ENERGY AND SUBSIDIARIES

 The following provides the amounts and variances in operating revenues and expense line items in the statements of income for Eversource for the years ended December 31, 2024 and 2023 included in this Annual Report on Form 10-K:

 2024
 2023
 Increase/(Decrease)

 $
 11,900.8
 $
 11,910.7
 $
 (9.9)

 Purchased Power, Purchased Natural Gas and Transmission
 3,736.1
 5,168.2
 (1,432.1)

 2,012.9
 1,895.7
 117.2

 1,433.5
 1,305.8
 127.7

 Amortization
 342.9
 (490.1)
 833.0

 671.8
 691.4
 (19.6)

 997.9
 940.4
 57.5

 297.0
 —
 297.0

 9,492.1
 9,511.4
 (19.3)

 2,408.7
 2,399.3
 9.4

 1,111.3
 855.4
 255.9

 Losses on Offshore Wind Investments
 464.0
 2,167.0
 (1,703.0)

 410.5
 348.1
 62.4

 Income/(Loss) Before Income Tax Expense
 1,243.9
 (275.0)
 1,518.9

 424.7
 159.7
 265.0

 819.2
 (434.7)
 1,253.9

 7.5
 7.5
 —

 Net Income/(Loss) Attributable to Common Shareholders
 $
 811.7
 $
 (442.2)
 $
 1,253.9

 Sales Volumes: A summary of our retail electric GWh sales volumes, our firm natural gas MMcf sales volumes, and our water MG sales volumes, and percentage changes, is as follows:

 Firm Natural Gas
 Water

 Sales Volumes (GWh)
 Percentage
 Sales Volumes (MMcf)
 Percentage
 Sales Volumes (MG)
 Percentage

 2024
 2023
 2024
 2023
 2024
 2023

 Traditional
 7,807
 7,590
 2.9
 %
 —
 —
 —
 %
 1,669
 1,488
 12.2
 %

 Decoupled
 43,516
 41,978
 3.7
 %
 147,293
 142,328
 3.5
 %
 24,308
 23,129
 5.1
 %

 Total Sales Volumes
 51,323
 49,568
 3.5
 %
 147,293
 142,328
 3.5
 %
 25,977
 24,617
 5.5
 %

 Weather, fluctuations in energy supply rates, conservation measures (including utility-sponsored energy efficiency programs), and economic conditions affect customer energy usage and water consumption. Industrial sales volumes are less sensitive to temperature variations than residential and commercial sales volumes. In our service territories, weather impacts both electric and water sales volumes during the summer and both electric and natural gas sales volumes during the winter; however, natural gas sales volumes are more sensitive to temperature variations than electric sales volumes. Customer heating or cooling usage may not directly correlate with historical levels or with the level of degree-days that occur.

 Fluctuations in retail electric sales volumes at PSNH impact earnings ("Traditional" in the table above). For CL&P, NSTAR Electric, NSTAR Gas, EGMA, Yankee Gas, and our Connecticut water distribution business, fluctuations in retail sales volumes do not materially impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms ("Decoupled" in the table above). These distribution revenues are decoupled from their customer sales volumes, which breaks the relationship between sales volumes and revenues recognized.

 Operating Revenues: The variance in Operating Revenues by segment in 2024, as compared to 2023, is as follows:

 Increase/(Decrease)

 Electric Distribution
 $
 93.0

 Natural Gas Distribution
 (117.8)

 Electric Transmission
 205.1

 (3.2)

 Other
 64.7

 (251.7)

 $
 (9.9)

 Electric and Natural Gas Distribution Revenues:
 Base Distribution Revenues:
 • Base electric distribution revenues increased $141.1 million due primarily to a base distribution rate increase at NSTAR Electric effective January 1, 2024 and a temporary base distribution rate increase at PSNH effective August 1, 2024.

 • Base natural gas distribution revenues increased $49.2 million due primarily to base distribution rate increases effective November 1, 2024 at EGMA and effective November 1, 2024 and November 1, 2023 at NSTAR Gas.

 NSTAR Electric's PBR mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. On December 26, 2023, the DPU approved a $104.9 million increase to NSTAR Electric's base distribution rates effective January 1, 2024.

 On July 31, 2024, the NHPUC approved a settlement agreement to implement a temporary annual base distribution rate increase of $61.2 million effective August 1, 2024 at PSNH.

 NSTAR Gas' PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On October 30, 2023, the DPU approved a $25.4 million increase to NSTAR Gas' base distribution rates, of which, $15.5 million was associated with a base rate adjustment and the remainder for a prior period exogenous cost adjustment, for effect on November 1, 2023. On October 30, 2024, the DPU approved a $12.7 million increase to NSTAR Gas' base distribution rates effective November 1, 2024.

 EGMA was allowed two rate base resets in a DPU-approved October 7, 2020 rate settlement agreement, with the first rate base reset on November 1, 2024. The increase to base distribution rates was $85.6 million effective November 1, 2024 (of which $8.8 million is offset by a reduction in the GSEP revenue requirement and GSEP rate also taking effect on November 1, 2024 for a net distribution rate change on November 1, 2024 of $76.8 million).

 Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement, state mandated energy purchase agreements and other energy-related costs, electric retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third party marketers, and the sale of RECs to various counterparties.

 Customers have the choice to purchase electricity from their Eversource electric utility or from a competitive third party supplier. For customers who have contracted separately with these competitive suppliers, revenue is not recorded for the sale of the electricity commodity, as the utility is acting as an agent on behalf of the third party supplier. For customers that choose to purchase electric generation from CL&P, NSTAR Electric or PSNH, each utility purchases power on behalf of, and is permitted to recover the related energy supply cost without mark-up from, its customers, and records offsetting amounts in revenues and purchased power related to this energy supply procurement. CL&P, NSTAR Electric and PSNH each remain as the distribution service provider for all customers and charge a regulated rate for distribution delivery service recorded in revenues. Certain eligible natural gas customers may elect to purchase natural gas from their Eversource natural gas utility or may contract separately with a
 gas supply operator. Revenue is not recorded for the sale of the natural gas commodity to customers who have contracted separately with these
 operators, only the delivery to a customer, as the utility is acting as an agent on behalf of the gas supply operator.

 The variance in tracked distribution revenues in 2024, as compared to 2023 is due primarily to the following:

 Electric Distribution
 Natural Gas Distribution

 Retail Tariff Tracked Revenues:

 Energy supply procurement
 $
 (1,239.6)
 $
 (165.2)

 CL&P NBFMCC
 544.9
 —

 NSTAR Electric net metering
 133.1
 —

 Stranded costs
 127.1
 —

 Retail transmission
 98.9
 —

 CL&P System Benefit Charge
 88.4
 —

 Other distribution tracking mechanisms
 159.2
 44.0

 Wholesale Market Sales Revenue
 33.9
 (44.8)

 Fluctuations in retail tariff tracked revenues are driven by adjustments to retail rates to recover costs and changes in sales volumes.

 The decrease in energy supply procurement within electric distribution was driven by lower average prices and lower average supply-related sales volumes. The decrease in energy supply procurement within natural gas distribution was driven by lower average prices, partially offset by higher average supply-related sales volumes.

 The increase in CL&P's NBFMCC revenues was driven by an increase in the retail Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate. The CL&P NBFMCC rate includes the recovery of costs incurred under long-term state mandated energy purchase contracts with the Millstone and Seabrook nuclear power plants, net of the benefits received from selling this energy into the ISO-NE wholesale market. Effective January 1, 2023, CL&P reduced the average NBFMCC rate to a credit of $0.01524 per kWh. The rate reduction returned to customers the net benefits of higher wholesale market sales received in the ISO-NE market for these energy contracts. The average NBFMCC rate changed to $0.00000 per kWh effective July 1, 2023 and then to $0.00293 per kWh effective September 1, 2023. As a result of the April 2024 interim decision in the 2024 CL&P RAM filing, the average NBFMCC rate increased to $0.03906 per kWh effective July 1, 2024. As a result of the August final decision in the 2024 CL&P RAM filing, the average NBFMCC rate increased to $0.04290 per kWh effective September 1, 2024. The rate increases primarily resulted from higher net costs associated with power purchase agreements with the Millstone and Seabrook nuclear power plants.

 CL&P is required by regulation to purchase electric generation from Millstone and Seabrook under PURA-approved PPAs entered into in 2019. CL&P does not have legislative authority to use this purchased output to serve its customer load and therefore sells the energy into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net cost or net sales amount is recovered from, or refunded to, customers in the non-bypassable component of the CL&P FMCC rate.

 Electric Transmission Revenues: Electric transmission revenues increased $205.1 million due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and the impact of the annual rate reconciliation filing with FERC.

 Other Revenues and Eliminations: Other revenues primarily include the revenues of Eversource's service company, most of which are eliminated in consolidation. Eliminations are also related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers.

 Purchased Power, Purchased Natural Gas and Transmission expense includes costs associated with providing electric generation service
 supply and natural gas to all customers who have not migrated to third party suppliers, the cost of energy purchase contracts entered into as
 required by regulation, and transmission costs. These electric and natural gas supply procurement costs, other energy-related costs, and
 transmission costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on
 earnings (tracked costs). The variance in Purchased Power, Purchased Natural Gas and Transmission expense in 2024, as compared to 2023, is due primarily to the following:

 Increase/(Decrease)

 Energy supply procurement costs
 $
 (1,243.2)

 Other electric distribution costs
 130.6

 Natural gas supply costs
 (218.8)

 Transmission costs
 77.8

 (178.5)

 Total Purchased Power, Purchased Natural Gas and Transmission
 $
 (1,432.1)

 The variance in energy supply procurement costs is offset in Operating Revenues (tracked energy supply procurement revenues). The variance in other electric distribution costs is due to higher long-term contractual energy-related costs that are recovered in the non-bypassable component of the FMCC mechanism at CL&P, higher net metering costs and an increase in long-term renewable contract costs at NSTAR Electric, partially offset by a decrease in long-term renewable energy purchase contract costs at PSNH.

 Costs at the natural gas distribution segment relate to supply procurement costs for retail customers. Total natural gas costs decreased due primarily to a decrease in the retail cost deferral and lower average prices, partially offset by higher average purchased volumes.

 The increase in transmission costs was primarily the result of an increase in costs billed by ISO-NE that support regional grid investments and an increase in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network. These increases were partially offset by a decrease in the retail transmission cost deferral, which reflects the actual cost of transmission service compared to estimated amounts billed to customers.

 Operations and Maintenance expense includes tracked costs and costs that are part of base electric, natural gas and water distribution rates with changes impacting earnings (non-tracked costs). The variance in Operations and Maintenance expense in 2024, as compared to 2023, is due primarily to the following:

 Increase/(Decrease)

 Base Electric Distribution (Non-Tracked Costs):

 Employee-related expenses (including labor and benefits)
 $
 22.7

 Uncollectible expense
 14.9

 Shared corporate costs (including IT system depreciation at Eversource Service)
 11.2

 Operations-related expenses (including vegetation management, vendor services, vehicles and materials)
 6.3

 General costs (including vendor services in corporate areas, insurance, fees and assessments)
 3.8

 Storm-related costs
 (4.5)

 Total Base Electric Distribution (Non-Tracked Costs)
 54.4

 Tracked Electric Costs (Electric Distribution and Electric Transmission) - Increase due primarily to higher transmission expense, increases in grid modernization and pension tracking mechanisms at NSTAR Electric, and higher uncollectible expense
 98.0

 Total Electric Distribution and Electric Transmission
 152.4

 Natural Gas Distribution:

 Base (Non-Tracked Costs) - Decrease due primarily to lower uncollectible expense
 (14.2)

 Tracked Costs
 11.0

 Total Natural Gas Distribution
 (3.2)

 3.8

 Eversource Parent and Other Companies - other operations and maintenance
 26.8

 (62.6)

 $
 117.2

 Depreciation expense increased due primarily to higher net plant in service balances.

 Amortization expense includes the deferral of energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. These costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates.

 The variance in Amortization is due primarily to the deferral adjustment of energy-related and other tracked costs at CL&P (included in the non-bypassable component of the FMCC mechanism), NSTAR Electric and PSNH, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The CL&P non-bypassable FMCC retail rate increased in 2024 as compared to 2023, and the higher collections lowered the regulatory under-recovery deferral adjustment, resulting in an increase to amortization expense of $548.5 million. Amortization expense also increased at NSTAR Electric as a result of an increase in storm costs recovered in rates and increased at PSNH due to the absence of a 2023 benefit related to the establishment of a new regulatory tracking mechanism that allowed for the recovery of previously incurred operating expenses associated with poles acquired from Consolidated Communications on May 1, 2023. The establishment of the PPAM regulatory asset resulted in a pre-tax benefit of $16.9 million recorded in Amortization expense on the statement of income in 2023.

 Energy Efficiency Programs expense includes costs of various state energy policy initiatives and expanded energy efficiency programs that are recovered from customers in rates, most of which have no impact on earnings. Energy Efficiency Programs expense includes a deferral adjustment that reflects the actual costs of energy efficiency programs compared to the amounts billed to customers, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. Energy Efficiency Programs expense decreased due primarily to the deferral adjustment, partially offset by higher program spending.

 Taxes Other Than Income Taxes expense increased due primarily to higher property taxes as a result of higher utility plant balances and higher Connecticut gross earnings taxes.

 Loss on Pending Sale of Aquarion relates to the impairment charge recorded in 2024 to write down the carrying value of the water business to fair value resulting from the expected sale of Aquarion. For further information, see "Business Development and Capital Expenditures – Pending Sale of Aquarion" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Interest Expense increased due primarily to an increase in interest on long-term debt as a result of debt issuances ($220.7 million), higher interest on short-term notes payable due to increased borrowings ($16.0 million), an increase in interest expense on regulatory deferrals ($15.8 million), and higher amortization of debt discounts and premiums, net ($4.1 million), partially offset by an increase in capitalized AFUDC related to debt funds and other capitalized interest ($3.2 million), and a decrease in RRB interest expense ($1.4 million).

 Losses on Offshore Wind Investments relates to the loss recorded on the 2024 sales of our equity method offshore wind investments and the impairment charge in 2023 resulting from the expected sales of these offshore wind investments. See "Business Development and Capital Expenditures – Offshore Wind Business" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations for further information.

 Other Income, Net increased due primarily to an increase in interest income primarily from regulatory deferrals ($44.0 million), an increase in equity in earnings related to Eversource's equity method investments ($36.4 million), an increase in capitalized AFUDC related to equity funds ($19.7 million), investment income in 2024 compared to investment losses in 2023 driven by market volatility ($5.5 million) and a gain on the sale of an unregulated water business in 2024 ($4.4 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($17.5 million). The variance in Other Income, Net was also due to the absence in 2024 of a benefit in 2023 from the liquidation of Eversource's equity method investment in a renewable energy fund in excess of its carrying value, partially offset by a charitable contribution made with a portion of the proceeds from the liquidation in 2023, as well as the absence in 2024 of a loss on the abandonment of land in 2023.

 Income Tax Expense increased due primarily to higher pre-tax earnings ($319.0 million), a decrease in amortization of EDIT ($14.5 million), a higher share-based payment tax deficiency ($1.8 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($28.3 million). This was partially offset by a decrease in reserves ($9.0 million) primarily related to the loss on sales of Eversource's offshore wind investments in 2024 compared to the impairment on these investments in 2023, lower state taxes ($49.3 million), and lower return to provision adjustments ($40.3 million).

 RESULTS OF OPERATIONS –

 The following provides the amounts and variances in operating revenues and expense line items in the statements of income for CL&P, NSTAR Electric and PSNH for the years ended December 31, 2024 and 2023 included in this Annual Report on Form 10-K:

 CL&P
 PSNH

 2024
 2023
 Increase/
(Decrease)
 2024
 2023
 Increase/
(Decrease)
 2024
 2023
 Increase/
(Decrease)

 $
 4,615.0
 $
 4,578.8
 $
 36.2
 $
 3,720.9
 $
 3,515.5
 $
 205.4
 $
 1,294.5
 $
 1,447.9
 $
 (153.4)

 Purchased Power and Transmission
 1,836.9
 2,612.9
 (776.0)
 1,045.3
 1,154.0
 (108.7)
 244.4
 605.0
 (360.6)

 815.3
 733.3
 82.0
 735.0
 668.5
 66.5
 288.3
 284.4
 3.9

 406.5
 376.9
 29.6
 407.7
 372.6
 35.1
 154.1
 140.4
 13.7

 104.5
 (500.3)
 604.8
 130.9
 16.1
 114.8
 136.1
 (16.3)
 152.4

 171.7
 133.5
 38.2
 263.4
 325.6
 (62.2)
 42.9
 39.6
 3.3

 419.6
 401.1
 18.5
 280.3
 256.1
 24.2
 96.9
 93.9
 3.0

 3,754.5
 3,757.4
 (2.9)
 2,862.6
 2,792.9
 69.7
 962.7
 1,147.0
 (184.3)

 860.5
 821.4
 39.1
 858.3
 722.6
 135.7
 331.8
 300.9
 30.9

 231.0
 193.4
 37.6
 222.7
 189.2
 33.5
 77.8
 72.8
 5.0

 77.6
 61.6
 16.0
 191.4
 164.1
 27.3
 31.1
 26.6
 4.5

 707.1
 689.6
 17.5
 827.0
 697.5
 129.5
 285.1
 254.7
 30.4

 194.5
 170.9
 23.6
 190.6
 153.0
 37.6
 70.2
 59.0
 11.2

 $
 512.6
 $
 518.7
 $
 (6.1)
 $
 636.4
 $
 544.5
 $
 91.9
 $
 214.9
 $
 195.7
 $
 19.2

 Sales Volumes: A summary of our retail electric GWh sales volumes is as follows:

 2024
 2023
 Percentage

 CL&P
 20,151
 19,577
 2.9
 %

 23,365
 22,401
 4.3
 %

 PSNH
 7,807
 7,590
 2.9
 %

 Fluctuations in retail electric sales volumes at PSNH impact earnings. For CL&P and NSTAR Electric, fluctuations in retail electric sales volumes do not impact earnings due to their respective regulatory commission-approved distribution revenue decoupling mechanisms.

 Operating Revenues: Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, increased $36.2 million at CL&P and $205.4 million at NSTAR Electric and decreased $153.4 million at PSNH in 2024, as compared to 2023.

 Base Distribution Revenues:
 • CL&P's distribution revenues were flat.
 • NSTAR Electric's distribution revenues increased $105.3 million due primarily to a base distribution rate increase effective January 1, 2024.
 • PSNH's distribution revenues increased $35.8 million due primarily to a temporary base distribution rate increase effective August 1, 2024.

 Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates on a fully reconciling basis through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. Costs recovered through cost tracking mechanisms include, among others, energy supply procurement, state mandated energy purchase agreements and other energy-related costs, retail transmission charges, energy efficiency program costs, electric restructuring and stranded cost recovery revenues (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for NSTAR Electric, pension and PBOP benefits, net metering for distributed generation, and solar-related programs. Revenues from certain of these cost tracking mechanisms also include certain incentives earned, return on capital tracking mechanisms, and carrying charges that are billed in rates to customers, which do impact earnings. Tracked revenues also include wholesale market sales transactions, such as sales of energy and energy-related products into the ISO-NE wholesale electricity market and the sale of RECs to various counterparties.

 Customers have the choice to purchase electricity from their Eversource electric utility or from a competitive third party supplier. For customers who have contracted separately with these competitive suppliers, revenue is not recorded for the sale of the electricity commodity, as the utility is acting as an agent on behalf of the third party supplier. For customers that choose to purchase electric generation from CL&P, NSTAR Electric or PSNH, each utility purchases power on behalf of, and is permitted to recover the related energy supply cost without mark-up from, its customers, and records offsetting amounts in revenues and purchased power related to this energy supply procurement. CL&P, NSTAR Electric and PSNH each remain as the distribution service provider for all customers and charge a regulated rate for distribution delivery service recorded in revenues.

 The variance in tracked distribution revenues in 2024, as compared to 2023, is due primarily to the following:

 CL&P
 PSNH

 Retail Tariff Tracked Revenues:

 Energy supply procurement
 $
 (710.5)
 $
 (253.9)
 $
 (275.2)

 CL&P NBFMCC
 544.9
 —
 —

 NSTAR Electric net metering
 —
 133.1
 —

 Stranded costs
 6.6
 77.7
 42.8

 Retail transmission
 (9.8)
 60.2
 48.5

 CL&P System Benefit Charge
 88.4
 —
 —

 Other distribution tracking mechanisms
 69.7
 77.2
 12.3

 Wholesale Market Sales Revenue
 62.8
 (0.7)
 (28.2)

 Fluctuations in retail tariff tracked revenues are driven by adjustments to retail rates to recover costs and changes in sales volumes.

 The decrease in energy supply procurement at CL&P, NSTAR Electric and PSNH was driven by lower average prices and lower average supply-related sales volumes.

 The increase in CL&P's NBFMCC revenues was driven by an increase in the retail Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate. The CL&P NBFMCC rate includes the recovery of costs incurred under long-term state mandated energy purchase contracts with the Millstone and Seabrook nuclear power plants, net of the benefits received from selling this energy into the ISO-NE wholesale market. Effective January 1, 2023, CL&P reduced the average NBFMCC rate to a credit of $0.01524 per kWh. The rate reduction returned to customers the net benefits of higher wholesale market sales received in the ISO-NE market for these energy contracts. The average NBFMCC rate changed to $0.00000 per kWh effective July 1, 2023 and then to $0.00293 per kWh effective September 1, 2023. As a result of the April 2024 interim decision in the 2024 CL&P RAM filing, the average NBFMCC rate increased to $0.03906 per kWh effective July 1, 2024. As a result of the August final decision in the 2024 CL&P RAM filing, the average NBFMCC rate increased to $0.04290 per kWh effective September 1, 2024. The rate increases primarily resulted from higher net costs associated with power purchase agreements with the Millstone and Seabrook nuclear power plants.

 CL&P is required by regulation to purchase electric generation from Millstone and Seabrook under PURA-approved PPAs entered into in 2019. CL&P does not have legislative authority to use this purchased output to serve its customer load and therefore sells the energy into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net cost or net sales amount is recovered from, or refunded to, customers in the non-bypassable component of the CL&P FMCC rate.

 Transmission Revenues: Transmission revenues increased $69.6 million at CL&P, $89.5 million at NSTAR Electric and $46.0 million at PSNH due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and the impact of the annual rate reconciliation filing with FERC.

 Eliminations: Eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business in rates charged to their customers. The impact of eliminations decreased revenues by $86.3 million at CL&P, $86.0 million at NSTAR Electric and $38.2 million at PSNH.

 Purchased Power and Transmission expense includes costs associated with providing electric generation service supply to all customers who have not migrated to third party suppliers, the cost of energy purchase contracts entered into as required by regulation, and transmission costs. These energy supply procurement costs, other energy-related costs, and transmission costs are recovered from customers in rates through commission-approved cost tracking mechanisms, which have no impact on earnings (tracked costs). The variance in Purchased Power and Transmission expense in 2024, as compared to 2023, is due primarily to the following:

 CL&P
 PSNH

 Energy supply procurement costs
 $
 (710.2)
 $
 (259.9)
 $
 (273.1)

 Other electric distribution costs
 43.6
 176.6
 (89.6)

 Transmission costs
 (23.1)
 60.6
 40.3

 (86.3)
 (86.0)
 (38.2)

 Total Purchased Power and Transmission
 $
 (776.0)
 $
 (108.7)
 $
 (360.6)

 The variance in energy supply procurement costs is offset in Operating Revenues (tracked energy supply procurement revenues). The variance in other electric distribution costs at CL&P is due to higher long-term contractual energy-related costs that are recovered in the non-bypassable component of the FMCC mechanism, at NSTAR Electric is due to higher net metering costs and an increase in long-term renewable contract costs, and at PSNH is due primarily to a decrease in long-term renewable energy purchase contract costs.

 Included in transmission costs are charges that recover the cost of transporting electricity over high-voltage lines from generation facilities to substations, including costs allocated by ISO-NE to maintain the wholesale electric market.

 • The decrease in transmission costs at CL&P was due primarily to a decrease resulting from the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. The decrease was partially offset by an increase in costs billed by ISO-NE that support regional grid investments and an increase in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network.
 • The increase in transmission costs at NSTAR Electric was due primarily to an increase resulting from the retail transmission cost deferral, an increase in costs billed by ISO-NE, and an increase in Local Network Service charges.
 • The increase in transmission costs at PSNH was due primarily to an increase in costs billed by ISO-NE and an increase in Local Network Service charges. These increases were partially offset by a decrease resulting from the retail transmission cost deferral.

 Operations and Maintenance expense includes tracked costs and costs that are part of base distribution rates with changes impacting earnings (non-tracked costs). The variance in Operations and Maintenance expense in 2024, as compared to 2023, is due primarily to the following:

 CL&P
 PSNH

 Base Electric Distribution (Non-Tracked Costs):

 Employee-related expenses (including labor and benefits)
 $
 13.0
 $
 7.8
 $
 1.9

 Uncollectible expense
 5.4
 11.2
 (1.7)

 Shared corporate costs (including IT system depreciation at Eversource Service)
 5.1
 4.0
 2.1

 Operations-related expenses (including vegetation management, vendor services, vehicles and materials)
 3.8
 4.5
 (2.0)

 Storm-related costs
 (2.2)
 3.5
 (5.8)

 General costs (including vendor services in corporate areas, insurance, fees and assessments)
 (11.8)
 3.6
 12.0

 Total Base Electric Distribution (Non-Tracked Costs)
 13.3
 34.6
 6.5

 Total Tracked Costs - Increase at CL&P due to higher uncollectible expense and at NSTAR Electric due to an increase in grid modernization costs
 68.7
 31.9
 (2.6)

 $
 82.0
 $
 66.5
 $
 3.9

 Depreciation expense increased for CL&P, NSTAR Electric and PSNH due to higher net plant in service balances.

 Amortization of Regulatory Assets/(Liabilities), Net expense includes the deferral of energy-related costs and other costs that are included in certain regulatory commission-approved cost tracking mechanisms. This deferral adjusts expense to match the corresponding revenues compared to the actual costs incurred. These costs are recovered from customers in rates and have no impact on earnings. Amortization expense also includes the amortization of certain costs as those costs are collected in rates. The variance in Amortization of Regulatory Assets/(Liabilities), Net is due primarily to the following:

 • The variance at CL&P was due primarily to the deferral adjustment of energy-related and other tracked costs that are included in the non-bypassable component of the FMCC mechanism, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The CL&P non-bypassable FMCC retail rate increased in 2024 as compared to 2023, and the higher collections lowered the regulatory under-recovery deferral adjustment recorded in the same period, resulting in an increase to amortization expense of $548.5 million.
 • The increase in expense at NSTAR Electric was due to the deferral adjustment of energy-related and other tracked costs that are included in the transition and solar facilities regulatory mechanisms, and higher amortization of storm costs recovered in rates.

 • The increase in expense at PSNH was due to the deferral adjustment of energy-related and other tracked costs that are included in the stranded cost recovery charge regulatory mechanism and the absence of a 2023 benefit related to the establishment of a new regulatory tracking mechanism that allowed for the recovery of previously incurred operating expenses associated with poles acquired from Consolidated Communications on May 1, 2023. The establishment of the PPAM regulatory asset resulted in a pre-tax benefit of $16.9 million recorded in Amortization expense on the PSNH statement of income in 2023.

 Energy Efficiency Programs expense includes costs of various state energy policy initiatives and expanded energy efficiency programs that are recovered from customers in rates, most of which have no impact on earnings. Energy Efficiency Programs expense includes a deferral adjustment that reflects the actual costs of energy efficiency programs compared to the amounts billed to customers, which can fluctuate from period to period based on the timing of costs incurred and related rate changes to recover these costs. The variance in Energy Efficiency Programs expense is due primarily to the following:

 • The increase at CL&P was due to the deferral adjustment and higher program spending.
 • The decrease at NSTAR Electric was due to the deferral adjustment, partially offset by higher program spending.
 • The increase at PSNH was due to higher program spending, partially offset by the deferral adjustment.

 Taxes Other Than Income Taxes - the variance is due primarily to the following:

 • The increase at CL&P was due to higher Connecticut gross earnings taxes and higher property taxes as a result of higher utility plant balances.
 • The increase at NSTAR Electric was due to higher property taxes as a result of higher utility plant balances and higher assessments.
 • The increase at PSNH was due to higher property taxes as a result of higher utility plant balances.

 Interest Expense - the variance is due primarily to the following:

 • The increase at CL&P was due to higher interest on long-term debt as a result of debt issuances ($26.0 million), an increase in interest expense on regulatory deferrals ($5.8 million), higher interest on short-term notes payable due to increased borrowings ($4.6 million) and higher amortization of debt discounts and premiums, net ($0.9 million), partially offset by an increase in capitalized AFUDC related to debt funds ($0.4 million).
 • The increase at NSTAR Electric was due to higher interest on long-term debt as a result of debt issuances ($23.2 million), an increase in interest expense on regulatory deferrals ($11.8 million), higher interest on short-term notes payable due to increased borrowings ($7.8 million) and higher amortization of debt discounts and premiums, net ($0.6 million), partially offset by an increase in capitalized AFUDC related to debt funds ($10.0 million).
 • The increase at PSNH was due primarily to higher interest on long-term debt as a result of a debt issuance ($14.8 million), partially offset by a decrease in interest expense on regulatory deferrals ($4.3 million), an increase in capitalized AFUDC related to debt funds ($2.8 million), a decrease in RRB interest expense ($1.4 million), lower interest on short-term notes payable ($0.8 million) and lower amortization of debt discounts and premiums, net ($0.6 million).

 Other Income, Net - the variance is due primarily to the following:

 • The increase at CL&P was due primarily to an increase in interest income primarily on regulatory deferrals ($19.3 million), an increase in capitalized AFUDC related to equity funds ($2.4 million) and a decrease in investment losses driven by market volatility ($1.0 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($6.7 million).
 • The increase at NSTAR Electric was due primarily to an increase in interest income primarily on regulatory deferrals ($16.4 million), an increase in capitalized AFUDC related to equity funds ($13.1 million) and investment income in 2024 compared to investment losses in 2023 driven by market volatility ($2.1 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($4.6 million).
 • The increase at PSNH was due primarily to an increase in interest income primarily on regulatory deferrals ($4.3 million), an increase in capitalized AFUDC related to equity funds ($1.6 million) and a decrease in investment losses driven by market volatility ($0.2 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($1.3 million).

 Income Tax Expense - the variance is due primarily to the following:

 • The increase at CL&P was due primarily to higher pre-tax earnings ($3.7 million), a decrease in amortization of EDIT ($1.3 million), an increase in valuation allowances ($8.8 million), higher share-based payment tax deficiency ($0.6 million), and an increase in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($10.6 million), partially offset by lower state taxes ($0.2 million), and lower return to provision adjustments ($1.2 million).
 • The increase at NSTAR Electric was due primarily to higher pre-tax earnings ($27.3 million), higher state taxes ($7.4 million), higher share-based payment tax deficiency ($0.6 million), and a decrease in amortization of EDIT ($8.4 million), partially offset by lower return to provision adjustments ($1.4 million) and a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($4.7 million).
 • The increase at PSNH was due primarily to higher pre-tax earnings ($6.4 million), a decrease in amortization of EDIT ($0.3 million), higher state taxes ($1.5 million), and higher return to provision adjustments ($3.0 million).

 EARNINGS SUMMARY

 CL&P's earnings decreased $6.1 million in 2024, as compared to 2023, due primarily to higher interest expense, a higher effective tax rate, higher depreciation expense, higher operations and maintenance expense, and higher property tax expense. The earnings decrease was partially offset by higher revenues from its capital tracking mechanism due to increased electric system improvements, an increase in transmission earnings driven primarily by a higher transmission rate base, and an increase in interest income primarily on regulatory deferrals.

 NSTAR Electric's earnings increased $91.9 million in 2024, as compared to 2023, due primarily to higher revenues as a result of the base distribution rate increase effective January 1, 2024, an increase in transmission earnings driven primarily by a higher transmission rate base, an increase in interest income primarily on regulatory deferrals, higher revenues from its capital tracking mechanisms due to increased investments, a lower effective tax rate, and higher AFUDC equity income. The earnings increase was partially offset by higher operations and maintenance expense, higher interest expense, higher property tax expense, and higher depreciation expense.

 PSNH's earnings increased $19.2 million in 2024, as compared to 2023, due primarily to higher revenues as a result of the base distribution rate increase effective August 1, 2024 and an increase in transmission earnings driven primarily by a higher transmission rate base. The earnings increase was partially offset by the absence of a prior year benefit related to the establishment of a new regulatory tracking mechanism that allowed for the recovery of previously incurred operating expenses associated with poles acquired on May 1, 2023, higher operations and maintenance expense, higher depreciation expense, higher interest expense, and a higher effective tax rate.

 LIQUIDITY

 Cash Flows: CL&P had cash flows provided by operating activities of $683.4 million in 2024, as compared to $449.6 million in 2023. The increase in operating cash flows was due primarily to an improvement in regulatory recoveries driven primarily by the timing of collections for the non-bypassable FMCC and other regulatory tracking mechanisms partially offset by the unfavorable impact in the timing of collections for energy supply costs, the timing of cash payments made on our accounts payable, a $19.9 million decrease in cost of removal expenditures, an $18.9 million decrease in cash payments to vendors for storm costs, and a $3.3 million increase in income tax refunds received in 2024 compared to 2023. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization of Regulatory Assets/(Liabilities) on the statements of cash flows. These favorable impacts were partially offset by the timing of cash collections on our accounts receivable and the timing of other working capital items.

 NSTAR Electric had cash flows provided by operating activities of $687.6 million in 2024, as compared to $713.6 million in 2023. The decrease in operating cash flows was due primarily to the timing of cash collections on our accounts receivable, an $87.4 million increase in income tax payments made, an increase in regulatory under-recoveries driven by the timing of collections for energy efficiency, residential assistance and other regulatory tracking mechanisms partially offset by the favorable impact in the timing of collections for net metering costs, and the timing of cash payments made on our accounts payable. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization of Regulatory Assets on the statements of cash flows. These unfavorable impacts were partially offset by a $9.1 million decrease in cost of removal expenditures and the timing of other working capital items.

 PSNH had cash flows provided by operating activities of $321.3 million in 2024, as compared to $32.0 million in 2023. The increase in operating cash flows was due primarily to an improvement in regulatory recoveries driven by the timing of collections for stranded costs, net metering and other regulatory tracking mechanisms, the timing of cash payments made on our accounts payable, and the timing of other working capital items. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization of Regulatory Assets/(Liabilities) on the statements of cash flows. These favorable impacts were partially offset by the timing of cash collections on our accounts receivable, a $23.9 million decrease in income tax refunds received in 2024 compared to 2023, a $5.6 million increase in cash payments to vendors for storm costs, and a $2.5 million increase in cost of removal expenditures.

 For further information on CL&P's, NSTAR Electric's and PSNH's liquidity and capital resources, see "Liquidity" and "Business Development and Capital Expenditures" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations.

 Item 7A. Quantitative and Qualitative Disclosures about Market Risk

 Market Risk Information

 Commodity Price Risk Management: Our regulated companies enter into energy contracts to serve our customers, and the economic impacts of those contracts are passed on to our customers. Accordingly, the regulated companies have no exposure to loss of future earnings or fair values due to these market risk-sensitive instruments. Eversource's Energy Supply Risk Committee, comprised of senior officers, reviews and approves all large-scale energy related transactions entered into by its regulated companies.

 Other Risk Management Activities

 We have an Enterprise Risk Management (ERM) program for identifying the principal risks of the Company. Our ERM program involves the application of a well-defined, enterprise-wide methodology designed to allow our Risk Committee, comprised of our senior officers of the Company, to identify, categorize, prioritize, and mitigate the principal risks to the Company. The ERM program is integrated with other assurance functions throughout the Company including Compliance, Auditing, and Insurance to ensure appropriate coverage of risks that could impact the Company. In addition to known risks, ERM identifies emerging risks to the Company, through participation in industry groups, discussions with management and in consultation with outside advisers. Our management then analyzes risks to determine materiality, likelihood and impact, and develops mitigation strategies. Management broadly considers our business model, the utility industry, the global economy, climate change, sustainability and the current environment to identify risks. The Finance Committee of the Board of Trustees is responsible for oversight of the Company's ERM program and enterprise-wide risks as well as specific risks associated with insurance, credit, financing, investments, pensions and overall system security including cyber security. The findings of the ERM process are periodically discussed with the Finance Committee of our Board of Trustees, as well as with other Board Committees or the full Board of Trustees, as appropriate, including reporting on how these issues are being measured and managed. However, there can be no assurances that the ERM process will identify or manage every risk or event that could impact our financial position, results of operations or cash flows.

 Interest Rate Risk Management: Interest rate risk is associated with changes in interest rates for our outstanding long-term debt. Our interest rate risk is significantly reduced as typically all or most of our debt financings have fixed interest rates. As of December 31, 2024, all of our long-term debt was at a fixed interest rate.

 Credit Risk Management: Credit risk relates to the risk of loss that we would incur as a result of non-performance by counterparties pursuant to the terms of our contractual obligations. We serve a wide variety of customers and transact with suppliers that include IPPs, industrial companies, natural gas and electric utilities, oil and natural gas producers, financial institutions, and other energy marketers. Margin accounts exist within this diverse group, and we realize interest receipts and payments related to balances outstanding in these margin accounts. This wide customer and supplier mix generates a need for a variety of contractual structures, products and terms that, in turn, require us to manage the portfolio of market risk inherent in those transactions in a manner consistent with the parameters established by our risk management process.

 Our regulated companies are subject to credit risk from certain long-term or high-volume supply contracts with energy marketing companies. Our regulated companies manage the credit risk with these counterparties in accordance with established credit risk practices and monitor contracting risks, including credit risk. As of December 31, 2024, our regulated companies held collateral (letters of credit or cash) of $15 million from counterparties related to our standard service contracts. As of December 31, 2024, Eversource had $21.4 million of cash posted with ISO-NE related to energy transactions.

 If the respective unsecured debt ratings of Eversource or its subsidiaries were reduced to below investment grade by either Moody's, S&P or Fitch, certain of Eversource's contracts would require additional collateral in the form of cash or letters of credit to be provided to counterparties and independent system operators. Eversource would have been and remains able to provide that collateral.

 Item 8. Financial Statements and Supplementary Data

 Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34)

 Consolidated Financial Statements

 CL&P

 Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)

 Financial Statements

 Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)

 Consolidated Financial Statements

 PSNH

 Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34)

 Consolidated Financial Statements

 Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Eversource Energy and subsidiaries (Eversource or the Company) and of other sections of this annual report. Eversource's internal controls over financial reporting were audited by Deloitte & Touche LLP.

 Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.

 Under the supervision and with the participation of the principal executive officer and principal financial officer, Eversource conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2024.

 To the Board of Trustees and Shareholders of Eversource Energy:
 Opinion on Internal Control over Financial Reporting
 We have audited the internal control over financial reporting of Eversource Energy and subsidiaries (the "Company") as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). In our opinion, the Company maintained, in all material respects, effective internal control over financial reporting as of December 31, 2024, based on criteria established in Internal Control - Integrated Framework (2013) issued by COSO.
 We have also audited, in accordance with the standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the consolidated financial statements as of and for the year ended December 31, 2024, of the Company and our report dated February 14, 2025, expressed an unqualified opinion on those financial statements.
 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 Management's Report on Internal Controls 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 included obtaining an understanding of internal control over financial reporting, assessing the risk that a material weakness exists, testing and evaluating the design and operating effectiveness of internal control based on the assessed risk, and 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.

 To the Board of Trustees and Shareholders of Eversource Energy:
 Opinion on the Financial Statements
 We have audited the accompanying consolidated balance sheets of Eversource Energy and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, common shareholders' equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedules listed in the Index at Item 15 of Part IV (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

 We have also audited, in accordance with standards of the Public Company Accounting Oversight Board (United States) (PCAOB), the Company's internal control over financial reporting as of December 31, 2024, 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 14, 2025, expressed an unqualified opinion on the Company's internal control over financial reporting.

 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's 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 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 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 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 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 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 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 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.

 Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements

 The Company is subject to regulation by federal, Connecticut, Massachusetts, and New Hampshire utility regulatory agencies (the "Commissions"), which have jurisdiction with respect to the rates of the Company's electric, natural gas, and water distribution companies. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs, including storm costs, regulatory tracking mechanisms and benefit costs, amongst others. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment.

 We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets.

 Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets.

 • We evaluated the Company's disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements.

 • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.

 • For regulatory matters in process, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.

 • We performed audit procedures on deferred storm restoration costs for completeness and accuracy.

 • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management's assertion that amounts are probable of recovery.

 Investments in Unconsolidated Affiliates – Impact of Offshore Wind Investment Divestiture - Refer to Note 6 to the Financial Statements

 In the third quarter of 2024, Eversource sold its interests in the Revolution Wind project, the South Fork Wind project, and the Sunrise Wind project. Eversource's offshore wind business continues to hold a noncontrolling tax equity investment in the South Fork Wind project through a 100 percent ownership in the Class A shares of South Fork Wind Holdings, LLC.

 Upon sale, Eversource recorded a loss of approximately $524 million. As part of the sale, Eversource agreed to make certain post-closing purchase price adjustment payments, which could further impact the final purchase price. The Company recorded a liability of $365 million reflecting its estimate of the future obligations under the sale terms, which primarily include a cost overrun sharing obligation, an expected obligation to maintain the buyer's internal rate of return and obligations for other future costs.

 We identified the evaluation of the offshore wind investment divestiture as a critical audit matter because of the extensive effort required to audit the subjective and complex judgments associated with the determination of the loss on sale and related contingent liability.

 Our audit procedures related to the offshore wind investment divestiture included the following, among others:

 • We tested the effectiveness of management's controls over loss considerations including the recording and disclosure of the loss on the offshore wind investments, including estimates and assumptions used to measure the loss. We tested the effectiveness of management's controls over the loss recognition on the investments.

 • We evaluated the Company's disclosures related to the offshore wind transactions in the financial statements.

 • We evaluated management's assumptions utilized in recording the loss on investments.

 • We evaluated the sufficiency of the contingent liability based on facts and circumstances that existed as of the reporting date.

 • We made inquiries of management and evaluated management's analysis that supported the project forecast, the timing of the loss, and the assumptions made in the recording of the loss on investments, including the contingent liability.

 We have served as the Company's auditor since 2002.

 CONSOLIDATED BALANCE SHEETS

 2024
 2023

 Cash
 $
 26,656
 $
 53,873

 Receivables, Net (net of allowance for uncollectible accounts of $ 556,164 and $ 554,455 as of December 31, 2024 and
 2023, respectively)

 1,651,325
 1,431,531

 242,169
 225,325

 Materials, Supplies, Natural Gas and REC Inventory
 594,568
 507,307

 2,189,660
 1,674,196

 Current Assets Held for Sale
 56,327
 —

 315,368
 355,762

 5,076,073
 4,247,994

 40,986,578
 39,498,607

 4,880,974
 4,714,970

 Goodwill
 3,571,333
 4,532,100

 Investments in Unconsolidated Affiliates
 168,652
 660,473

 1,336,633
 1,028,207

 Marketable Securities
 320,272
 337,814

 Long-Term Assets Held for Sale
 2,611,145
 —

 642,869
 592,080

 13,531,878
 11,865,644

 $
 59,594,529
 $
 55,612,245

 Notes Payable
 $
 2,042,793
 $
 1,930,422

 Long-Term Debt – Current Portion
 1,003,150
 824,847

 Rate Reduction Bonds – Current Portion
 43,210
 43,210

 1,736,880
 1,869,187

 Accrued Interest
 341,558
 260,577

 632,282
 591,750

 Current Liabilities Held for Sale
 52,593
 —

 868,491
 821,404

 6,720,957
 6,341,397

 5,411,206
 5,303,730

 4,032,564
 4,022,923

 Asset Retirement Obligations
 590,890
 505,844

 Accrued SERP and PBOP
 95,400
 123,754

 Long-Term Liabilities Held for Sale
 398,859
 —

 1,123,999
 1,029,238

 11,652,918
 10,985,489

 25,701,627
 23,588,616

 Rate Reduction Bonds
 324,072
 367,282

 Noncontrolling Interest - Preferred Stock of Subsidiaries
 155,568
 155,569

 Common Shareholders' Equity:

 Common Shares
 1,878,622
 1,799,920

 Capital Surplus, Paid In
 9,428,905
 8,460,876

 3,929,141
 4,142,515

 Accumulated Other Comprehensive Loss
 ( 26,472)
 ( 33,737)

 Treasury Stock
 ( 170,809)
 ( 195,682)

 Common Shareholders' Equity
 15,039,387
 14,173,892

 Commitments and Contingencies (Note 13)

 $
 59,594,529
 $
 55,612,245

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

 CONSOLIDATED STATEMENTS OF INCOME/(LOSS)

 (Thousands of Dollars, Except Share Information)
 2024
 2023
 2022

 $
 11,900,809
 $
 11,910,705
 $
 12,289,336

 Purchased Power, Purchased Natural Gas and Transmission
 3,736,078
 5,168,241
 5,014,074

 2,012,926
 1,895,703
 1,865,328

 1,433,503
 1,305,840
 1,194,246

 Amortization
 342,864
 ( 490,117)
 448,892

 671,828
 691,344
 658,051

 997,901
 940,359
 910,591

 297,000
 —
 —

 9,492,100
 9,511,370
 10,091,182

 2,408,709
 2,399,335
 2,198,154

 1,111,336
 855,441
 678,274

 Losses on Offshore Wind Investments
 464,019
 2,167,000
 —

 410,482
 348,069
 346,088

 Income/(Loss) Before Income Tax Expense
 1,243,836
 ( 275,037)
 1,865,968

 424,664
 159,684
 453,574

 7,519
 7,519
 7,519

 Net Income/(Loss) Attributable to Common Shareholders
 $
 811,653
 $
 ( 442,240)
 $
 1,404,875

 Basic Earnings/(Loss) Per Common Share
 $
 2.27
 $
 ( 1.27)
 $
 4.05

 Diluted Earnings/(Loss) Per Common Share
 $
 2.27
 $
 ( 1.26)
 $
 4.05

 Weighted Average Common Shares Outstanding:

 Basic
 357,482,965
 349,580,638
 346,783,444

 Diluted
 357,779,408
 349,840,481
 347,246,768

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

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

 2024
 2023
 2022

 $
 $
 $

 Other Comprehensive Income, Net of Tax:

 Qualified Cash Flow Hedging Instruments

 —
 1,252
 ( 1,636)

 Changes in Funded Status of Pension, SERP and PBOP Benefit Plans
 7,245
 4,412
 4,470

 Other Comprehensive Income, Net of Tax
 7,265
 5,684
 2,854

 Comprehensive Income Attributable to Noncontrolling Interests

 Comprehensive Income/(Loss) Attributable to Common Shareholders
 $
 818,918
 $
 ( 436,556)
 $
 1,407,729

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

 CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY

 Common Shares
 Capital
Surplus,
Paid In
 Accumulated Other Comprehensive Loss
 Treasury Stock
 Total Common Shareholders' Equity

 (Thousands of Dollars, Except Share Information)
 Shares

 344,403,196
 $
 1,789,092
 $
 8,098,514
 $
 5,005,391
 $
 ( 42,275)
 $
 ( 250,878)
 $
 14,599,844

 Dividends on Common Shares - $ 2.55 Per Share

 ( 883,113)

 ( 883,113)

 Issuance of Common Shares - $ 5 par value

 2,165,671
 10,828
 189,077
 199,905

 Capital Stock Expense
 ( 2,847)
 ( 2,847)

 Long-Term Incentive Plan Activity

 8,335

 8,335

 Issuance of Treasury Shares
 949,724
 53,822
 17,350
 71,172

 Issuance of Treasury Shares for Acquisition of
 The Torrington Water Company
 925,264
 54,830
 17,303
 72,133

 2,854

 2,854

 348,443,855
 1,799,920
 8,401,731
 5,527,153
 ( 39,421)
 ( 216,225)
 15,473,158

 Net Loss

 Dividends on Common Shares - $ 2.70 Per Share

 ( 942,398)

 ( 942,398)

 Long-Term Incentive Plan Activity

 1,375

 1,375

 Issuance of Treasury Shares
 1,096,411
 57,770
 20,543
 78,313

 5,684

 5,684

 349,540,266
 1,799,920
 8,460,876
 4,142,515
 ( 33,737)
 ( 195,682)
 14,173,892

 Dividends on Common Shares - $ 2.86 Per Share

 ( 1,025,027)

 ( 1,025,027)

 Issuance of Common Shares - $ 5 par value

 15,740,294
 78,702
 921,387
 1,000,089

 Capital Stock Expense
 ( 10,642)
 ( 10,642)

 Long-Term Incentive Plan Activity
 ( 6,557)
 ( 6,557)

 Issuance of Treasury Shares
 1,327,492

 63,841

 24,873
 88,714

 7,265

 7,265

 366,608,052
 $
 1,878,622
 $
 9,428,905
 $
 3,929,141
 $
 ( 26,472)
 $
 ( 170,809)
 $
 15,039,387

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2024
 2023
 2022

 $
 $
 $

 Adjustments to Reconcile Net Income/(Loss) to Net Cash Flows Provided by Operating Activities:

 1,433,503
 1,305,840
 1,194,246

 435,889
 85,405
 346,779

 74,069
 72,468
 61,876

 Pension, SERP and PBOP Income, Net
 ( 73,564)
 ( 90,706)
 ( 160,857)

 Pension and PBOP Contributions
 ( 5,915)
 ( 6,860)
 ( 83,148)

 Regulatory Under Recoveries, Net
 ( 919,359)
 ( 151,548)
 ( 205,294)

 Customer Credits at CL&P related to PURA Settlement Agreement and Storm
 Performance Penalty
 —
 —
 ( 72,041)

 Amortization
 342,864
 ( 490,117)
 448,892

 Cost of Removal Expenditures
 ( 294,984)
 ( 315,699)
 ( 303,755)

 Payment in 2022 of Withheld Property Taxes
 —
 —
 ( 78,446)

 Losses on Offshore Wind Investments
 464,019
 2,167,000
 —

 297,000
 —
 —

 Other
 ( 102,450)
 ( 53,026)
 ( 39,192)

 Receivables and Unbilled Revenues, Net
 ( 432,620)
 ( 124,393)
 ( 470,593)

 55,502
 36,357
 18,358

 47,082
 ( 287,637)
 377,657

 19,529
 ( 66,202)
 ( 45,583)

 2,159,737
 1,646,161
 2,401,293

 Investments in Property, Plant and Equipment
 ( 4,480,529)
 ( 4,336,849)
 ( 3,441,852)

 Proceeds from Sales of Marketable Securities
 268,164
 395,604
 457,612

 Purchases of Marketable Securities
 ( 242,959)
 ( 336,779)
 ( 424,174)

 Investments in Unconsolidated Affiliates
 ( 929,688)
 ( 1,680,473)
 ( 742,496)

 Proceeds from Unconsolidated Affiliates
 862,713
 1,090,662
 —

 ( 13,365)
 ( 2,897)
 20,420

 ( 4,535,664)
 ( 4,870,732)
 ( 4,130,490)

 Issuance of Common Shares, Net of Issuance Costs
 989,447
 —
 197,058

 Cash Dividends on Common Shares
 ( 1,001,488)
 ( 918,995)
 ( 860,033)

 Cash Dividends on Preferred Stock

 (Decrease)/Increase in Notes Payable
 ( 94,959)
 695,552
 ( 78,170)

 Repayment of Rate Reduction Bonds

 4,501,623
 5,198,345
 4,045,000

 ( 1,949,995)
 ( 2,008,470)
 ( 1,175,000)

 ( 57,082)
 ( 46,466)
 ( 48,185)

 Net Cash Flows Provided by Financing Activities
 2,336,817
 2,869,237
 2,029,941

 Net (Decrease)/Increase in Cash, Cash Equivalents and Restricted Cash
 ( 39,110)
 ( 355,334)
 300,744

 Cash, Cash Equivalents and Restricted Cash - Beginning of Year
 166,418
 521,752
 221,008

 Cash, Cash Equivalents and Restricted Cash - End of Year
 $
 127,308
 $
 166,418
 $
 521,752

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

 Management is responsible for the preparation, integrity, and fair presentation of the accompanying financial statements of The Connecticut Light and Power Company (CL&P or the Company) and of other sections of this annual report.

 Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.

 Under the supervision and with the participation of the principal executive officer and principal financial officer, CL&P conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2024.

 To the Board of Directors and Stockholder of The Connecticut Light and Power Company:

 Opinion on the Financial Statements

 We have audited the accompanying balance sheets of The Connecticut Light and Power Company (the "Company") as of December 31, 2024 and 2023, the related statements of income, comprehensive income, common stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedule listed in the Index at Item 15 of Part IV (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's 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 financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

 Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

 Critical Audit Matter

 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the 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 financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

 Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements

 The Company is subject to regulation by federal and Connecticut utility regulatory agencies (the "Commissions"), which have jurisdiction with respect to the rates of the Company's electric distribution business. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs, including storm costs, regulatory tracking mechanisms and benefit costs, amongst others. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment.

 We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets.

 Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets.

 • We evaluated the Company's disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements.

 • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.

 • For regulatory matters in process, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.

 • We performed audit procedures on deferred storm restoration costs for completeness and accuracy.

 • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management's assertion that amounts are probable of recovery.

 We have served as the Company's auditor since 2002.

 BALANCE SHEETS

 2024
 2023

 Cash
 $
 1,093
 $
 10,213

 Receivables, Net (net of allowance for uncollectible accounts of $ 279,108 and $ 296,030 as of December 31, 2024 and
 2023, respectively)

 663,171
 558,993

 Accounts Receivable from Affiliated Companies
 68,723
 60,450

 59,759
 57,403

 Materials, Supplies and REC Inventory
 217,316
 156,467

 638,529
 480,369

 51,688
 94,789

 1,700,279
 1,418,684

 13,002,193
 12,340,192

 1,687,029
 1,662,778

 182,483
 129,801

 267,861
 298,169

 2,137,373
 2,090,748

 $
 16,839,845
 $
 15,849,624

 Notes Payable to Eversource Parent
 $
 280,000
 $
 249,670

 Long-Term Debt – Current Portion

 2,944
 —

 548,100
 622,055

 Accounts Payable to Affiliated Companies
 137,150
 134,726

 Obligations to Third Party Suppliers
 63,840
 75,753

 124,122
 102,239

 Derivative Liabilities
 71,090
 81,944

 170,854
 127,703

 1,398,100
 1,394,090

 2,052,806
 1,860,122

 1,395,883
 1,315,928

 204,801
 258,185

 3,653,490
 3,434,235

 5,108,173
 4,814,429

 Preferred Stock Not Subject to Mandatory Redemption
 116,200
 116,200

 Common Stockholder's Equity:

 Capital Surplus, Paid In
 3,684,265
 3,384,265

 2,819,107
 2,645,868

 Accumulated Other Comprehensive Income

 Common Stockholder's Equity
 6,563,882
 6,090,670

 Commitments and Contingencies (Note 13)

 $
 16,839,845
 $
 15,849,624

 STATEMENTS OF INCOME

 2024
 2023
 2022

 $
 4,614,977
 $
 4,578,804
 $
 4,817,744

 Purchased Power and Transmission
 1,836,911
 2,612,949
 2,110,253

 815,345
 733,287
 707,162

 406,540
 376,904
 355,511

 104,446
 ( 500,367)
 335,636

 171,690
 133,453
 134,222

 419,575
 401,135
 384,746

 3,754,507
 3,757,361
 4,027,530

 860,470
 821,443
 790,214

 231,004
 193,361
 169,348

 77,591
 61,560
 83,252

 707,057
 689,642
 704,118

 194,459
 170,909
 171,198

 $
 $
 $

 STATEMENTS OF COMPREHENSIVE INCOME

 2024
 2023
 2022

 $
 $
 $

 Other Comprehensive (Loss)/Income, Net of Tax:

 Qualified Cash Flow Hedging Instruments
 ( 27)
 ( 26)
 ( 26)

 —
 ( 56)

 Other Comprehensive (Loss)/Income, Net of Tax
 ( 27)
 ( 82)

 Comprehensive Income
 $
 512,571
 $
 518,749
 $
 532,838

 STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 Capital
Surplus,
Paid In
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income
 Total
Common
Stockholder's
Equity

 (Thousands of Dollars, Except Stock Information)
 Stock

 $
 $
 3,010,765
 $
 2,228,133
 $
 $
 5,299,501

 ( 292,400)

 ( 292,400)

 ( 82)
 ( 82)

 3,260,765
 2,463,094
 5,784,380

 ( 330,400)

 ( 330,400)

 123,500

 123,500

 3,384,265
 2,645,868
 6,090,670

 ( 333,800)
 ( 333,800)

 ( 27)
 ( 27)

 $
 $
 3,684,265
 $
 2,819,107
 $
 $
 6,563,882

 STATEMENTS OF CASH FLOWS

 2024
 2023
 2022

 $
 $
 $

 Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

 406,540
 376,904
 355,511

 175,424
 184,037
 45,381

 17,190
 11,675
 15,578

 Pension, SERP and PBOP Income, Net
 ( 12,019)
 ( 18,316)
 ( 28,971)

 Regulatory (Under)/Over Recoveries, Net
 ( 257,561)
 157,200
 ( 144,793)

 Customer Credits related to PURA Settlement Agreement and Storm Performance Penalty
 —
 —
 ( 72,041)

 104,446
 ( 500,367)
 335,636

 Cost of Removal Expenditures
 ( 60,536)
 ( 80,479)
 ( 71,596)

 Other
 ( 47,680)
 ( 16,194)
 ( 25,927)

 Receivables and Unbilled Revenues, Net
 ( 175,162)
 ( 100,684)
 ( 256,338)

 64,914
 25,633

 4,232
 ( 88,040)
 207,698

 ( 48,973)
 ( 20,535)
 ( 24,308)

 683,413
 449,567
 869,647

 Investments in Property, Plant and Equipment
 ( 978,532)
 ( 1,093,121)
 ( 876,740)

 —

 ( 978,532)
 ( 1,092,948)
 ( 876,149)

 Cash Dividends on Common Stock
 ( 333,800)
 ( 330,400)
 ( 292,400)

 Cash Dividends on Preferred Stock

 (Decrease)/Increase in Notes Payable to Eversource Parent
 ( 177,000)
 457,000
 —

 650,000
 800,000
 —

 ( 139,800)
 ( 400,000)
 —

 123,500

 ( 8,856)
 ( 9,244)
 —

 Net Cash Flows Provided by/(Used In) Financing Activities
 284,985
 635,297
 ( 47,959)

 Net Decrease in Cash and Restricted Cash
 ( 10,134)
 ( 8,084)
 ( 54,461)

 Cash and Restricted Cash - Beginning of Year
 12,243
 20,327
 74,788

 Cash and Restricted Cash - End of Year
 $
 2,109
 $
 12,243
 $
 20,327

 Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of NSTAR Electric Company and subsidiary (NSTAR Electric or the Company) and of other sections of this annual report.

 Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.

 Under the supervision and with the participation of the principal executive officer and principal financial officer, NSTAR Electric conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control – Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2024.

 To the Board of Directors and Stockholder of NSTAR Electric Company:

 Opinion on the Financial Statements

 We have audited the accompanying consolidated balance sheets of NSTAR Electric Company and subsidiary (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedule listed in the Index at Item 15 of Part IV (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024 in conformity with accounting principles generally accepted in the United States of America.

 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's 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 financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

 Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

 Critical Audit Matter

 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the 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 financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

 Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements

 The Company is subject to regulation by federal and Massachusetts utility regulatory agencies (the "Commissions"), which have jurisdiction with respect to the rates of the Company's electric distribution business. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment.

 We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets.

 Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets.

 • We evaluated the Company's disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements.

 • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.

 • For regulatory matters in process, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.

 • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management's assertion that amounts are probable of recovery.

 We have served as the Company's auditor since 2012.

 CONSOLIDATED BALANCE SHEETS

 2024
 2023

 Cash
 $
 $
 6,740

 Receivables, Net (net of allowance for uncollectible accounts of $ 114,910 and $ 97,026 as of December 31, 2024 and
 2023, respectively)

 614,563
 487,707

 Accounts Receivable from Affiliated Companies
 82,921
 74,634

 59,079
 49,897

 Materials, Supplies and REC Inventory
 220,621
 173,770

 902,770
 676,083

 72,986
 41,464

 1,953,851
 1,510,295

 14,037,828
 12,753,787

 1,204,337
 1,281,836

 724,661
 608,617

 154,571
 116,978

 2,083,569
 2,007,431

 $
 18,075,248
 $
 16,271,513

 Notes Payable
 $
 504,782
 $
 365,847

 Long-Term Debt – Current Portion

 —

 534,868
 599,696

 Accounts Payable to Affiliated Companies
 153,672
 144,622

 Obligations to Third Party Suppliers
 163,711
 139,823

 Renewable Portfolio Standards Compliance Obligations
 106,399
 116,010

 436,312
 368,070

 95,798
 84,688

 2,245,542
 1,818,756

 2,005,439
 1,849,613

 1,643,079
 1,585,311

 377,462
 327,388

 4,025,980
 3,762,312

 4,844,920
 4,496,947

 Preferred Stock Not Subject to Mandatory Redemption
 43,000
 43,000

 Common Stockholder's Equity:

 —
 —

 Capital Surplus, Paid In
 3,788,842
 3,013,842

 3,127,105
 3,136,612

 Accumulated Other Comprehensive (Loss)/Income
 ( 141)

 Common Stockholder's Equity
 6,915,806
 6,150,498

 Commitments and Contingencies (Note 13)

 $
 18,075,248
 $
 16,271,513

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

 CONSOLIDATED STATEMENTS OF INCOME

 2024
 2023
 2022

 $
 3,720,877
 $
 3,515,539
 $
 3,583,070

 Purchased Power and Transmission
 1,045,306
 1,154,013
 1,264,824

 735,019
 668,466
 640,834

 407,699
 372,578
 361,969

 Amortization of Regulatory Assets, Net
 130,869
 16,150
 83,855

 263,405
 325,593
 332,247

 280,261
 256,090
 246,705

 2,862,559
 2,792,890
 2,930,434

 858,318
 722,649
 652,636

 222,794
 189,254
 162,892

 191,405
 164,129
 142,661

 826,929
 697,524
 632,405

 190,576
 152,996
 139,977

 $
 $
 $

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

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2024
 2023
 2022

 $
 $
 $

 Other Comprehensive Loss, Net of Tax:

 Changes in Funded Status of SERP Benefit Plan
 ( 205)
 ( 272)
 ( 221)

 Qualified Cash Flow Hedging Instruments

 —
 ( 16)

 Other Comprehensive Loss, Net of Tax
 ( 185)
 ( 240)
 ( 217)

 Comprehensive Income
 $
 636,168
 $
 544,288
 $
 492,211

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

 CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 Capital
Surplus,
Paid In
 Retained
Earnings
 Accumulated
Other
Comprehensive
Income/(Loss)
 Total
Common
Stockholder's
Equity

 (Thousands of Dollars, Except Stock Information)
 Stock

 $
 —
 $
 2,253,942
 $
 2,718,576
 $
 $
 4,973,019

 ( 287,600)

 ( 287,600)

 525,000

 525,000

 ( 217)
 ( 217)

 —
 2,778,942
 2,921,444
 5,700,670

 ( 327,400)

 ( 327,400)

 234,900

 234,900

 ( 240)
 ( 240)

 —
 3,013,842
 3,136,612
 6,150,498

 ( 643,900)

 ( 643,900)

 775,000

 775,000

 ( 185)
 ( 185)

 $
 —
 $
 3,788,842
 $
 3,127,105
 $
 ( 141)
 $
 6,915,806

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2024
 2023
 2022

 $
 $
 $

 Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

 407,699
 372,578
 361,969

 111,177
 96,224
 78,039

 33,607
 22,791
 21,550

 Pension, SERP and PBOP Income, Net
 ( 36,104)
 ( 41,554)
 ( 55,830)

 Pension Contributions
 —
 —
 ( 15,000)

 Regulatory Under Recoveries, Net
 ( 271,689)
 ( 141,865)
 ( 88,220)

 Amortization of Regulatory Assets, Net
 130,869
 16,150
 83,855

 Cost of Removal Expenditures
 ( 59,187)
 ( 68,290)
 ( 57,339)

 Payment in 2022 of Withheld Property Taxes
 —
 —
 ( 76,311)

 Other
 ( 25,876)
 ( 2,123)
 ( 14,294)

 Receivables and Unbilled Revenues, Net
 ( 179,783)
 ( 82,659)
 ( 23,757)

 ( 37,779)
 27,394
 35,143

 1,412
 11,357
 8,815

 ( 23,137)
 ( 40,974)
 20,430

 687,562
 713,557
 771,478

 Investments in Property, Plant and Equipment
 ( 1,563,326)
 ( 1,376,135)
 ( 954,281)

 —

 ( 1,563,326)
 ( 1,376,087)
 ( 954,116)

 Cash Dividends on Common Stock
 ( 643,900)
 ( 327,400)
 ( 287,600)

 Cash Dividends on Preferred Stock

 Increase/(Decrease) in Notes Payable
 138,935
 365,847
 ( 162,500)

 775,000
 234,900
 525,000

 600,000
 150,000
 850,000

 —
 ( 80,000)
 ( 400,000)

 ( 6,073)
 ( 1,365)
 ( 13,188)

 Net Cash Flows Provided by Financing Activities
 862,002
 340,022
 509,752

 Net (Decrease)/Increase in Cash, Cash Equivalents and Restricted Cash
 ( 13,762)
 ( 322,508)
 327,114

 Cash, Cash Equivalents and Restricted Cash - Beginning of Year
 22,785
 345,293
 18,179

 Cash, Cash Equivalents and Restricted Cash - End of Year
 $
 9,023
 $
 22,785
 $
 345,293

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

 Management is responsible for the preparation, integrity, and fair presentation of the accompanying consolidated financial statements of Public Service Company of New Hampshire and subsidiaries (PSNH or the Company) and of other sections of this annual report.

 Management is responsible for establishing and maintaining adequate internal controls over financial reporting. The Company's internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with accounting principles generally accepted in the United States of America. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment.

 Under the supervision and with the participation of the principal executive officer and principal financial officer, PSNH conducted an evaluation of the effectiveness of internal controls over financial reporting based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting were effective as of December 31, 2024.

 To the Board of Directors and Stockholder of Public Service Company of New Hampshire:

 Opinion on the Financial Statements

 We have audited the accompanying consolidated balance sheets of Public Service Company of New Hampshire and subsidiaries (the "Company") as of December 31, 2024 and 2023, the related consolidated statements of income, comprehensive income, common stockholder's equity, and cash flows, for each of the three years in the period ended December 31, 2024, and the related notes and the schedule listed in the Index at Item 15 of Part IV (collectively referred to as the "financial statements"). In our opinion, the financial statements present fairly, in all material respects, the financial position of the Company as of December 31, 2024 and 2023, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2024, in conformity with accounting principles generally accepted in the United States of America.

 These financial statements are the responsibility of the Company's management. Our responsibility is to express an opinion on the Company's 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 financial statements are free of material misstatement, whether due to error or fraud. The Company is not required to have, nor were we engaged to perform, an audit of its internal control over financial reporting. As part of our audits, we are required to obtain an understanding of internal control over financial reporting but not for the purpose of expressing an opinion on the effectiveness of the Company's internal control over financial reporting. Accordingly, we express no such opinion.

 Our audits included performing procedures to assess the risks of material misstatement of the 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 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 financial statements. We believe that our audits provide a reasonable basis for our opinion.

 Critical Audit Matter

 The critical audit matter communicated below is a matter arising from the current-period audit of the financial statements that was communicated or required to be communicated to the audit committee and that (1) relates to accounts or disclosures that are material to the 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 financial statements, taken as a whole, and we are not, by communicating the critical audit matter below, providing a separate opinion on the critical audit matter or on the accounts or disclosures to which it relates.

 Regulatory Accounting - Impact of Rate Regulation on the Financial Statements - Refer to Note 2 to the Financial Statements

 The Company is subject to regulation by federal and New Hampshire utility regulatory agencies (the "Commissions"), which have jurisdiction with respect to the rates of the Company's electric distribution business. Management has determined it meets the criteria for the application of regulated operations accounting in preparing its financial statements under accounting principles generally accepted in the United States of America. Judgment can be required to determine if otherwise recognizable incurred costs qualify to be presented as a regulatory asset and deferred because such costs are probable of future recovery in customer rates. As discussed in Note 2, regulatory proceedings in recent years have focused on the recoverability of costs. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. As a result, assessing the potential outcomes of future regulatory orders requires management judgment.

 We identified the impact of rate regulation related to regulatory assets as a critical audit matter due to the judgments made by management, including assumptions regarding the outcome of future decisions by the Commissions to support its assertions on the likelihood of future recovery for deferred costs. Given that management's accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments required specialized knowledge of accounting for rate regulation and the ratemaking process due to its inherent complexities as it relates to regulatory assets.

 Our audit procedures related to the uncertainty of future decisions by the Commissions included the following, among others:

 • We tested the effectiveness of management's controls over the evaluation of the likelihood of the recovery in future rates of costs deferred as regulatory assets.

 • We evaluated the Company's disclosures related to the applicability and impacts of rate regulation, including the balances recorded and regulatory developments disclosed in the financial statements.

 • We read relevant regulatory orders issued by the Commissions for the Company and other public utilities, regulatory statutes, interpretations, procedural memorandums, filings made by intervenors, and other publicly available information to assess the likelihood of recovery in future rates based on precedents of the Commissions' treatment of similar costs under similar circumstances. We also evaluated the external information and compared it to management's recorded regulatory asset and liability balances for completeness.

 • For regulatory matters in process, we inspected the Company's filings with the Commissions and the filings with the Commissions by intervenors that may impact the Company's future rates, for any evidence that might contradict management's assertions.

 • We made inquiries of management, including legal counsel, and obtained the regulatory orders and analysis from management that support the probability of recovery in rates for regulatory assets to assess management's assertion that amounts are probable of recovery.

 We have served as the Company's auditor since 2002.

 CONSOLIDATED BALANCE SHEETS

 2024
 2023

 Cash
 $
 1,431
 $

 Receivables, Net (net of allowance for uncollectible accounts of $ 14,090 and $ 14,322 as of December 31, 2024 and
 2023, respectively)

 163,063
 152,276

 Accounts Receivable from Affiliated Companies
 27,285
 18,214

 57,226
 55,012

 Materials, Supplies and REC Inventory
 75,778
 77,066

 173,267
 189,450

 Special Deposits
 32,668
 31,586

 15,916
 45,635

 546,634
 569,479

 5,089,943
 4,574,652

 892,411
 773,783

 91,005
 58,979

 21,948
 16,558

 1,005,364
 849,320

 $
 6,641,941
 $
 5,993,451

 Notes Payable to Eversource Parent
 $
 131,100
 $
 233,000

 Rate Reduction Bonds – Current Portion

 43,210
 43,210

 226,074
 205,744

 Accounts Payable to Affiliated Companies
 45,141
 41,272

 121,058
 117,515

 92,018
 72,328

 658,601
 713,069

 781,559
 691,532

 394,982
 393,574

 43,859
 42,484

 1,220,400
 1,127,590

 1,732,066
 1,431,591

 Rate Reduction Bonds
 324,072
 367,282

 Common Stockholder's Equity:

 —
 —

 Capital Surplus, Paid In
 1,898,134
 1,698,134

 808,668
 655,785

 Common Stockholder's Equity
 2,706,802
 2,353,919

 Commitments and Contingencies (Note 13)

 $
 6,641,941
 $
 5,993,451

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

 CONSOLIDATED STATEMENTS OF INCOME

 2024
 2023
 2022

 $
 1,294,493
 $
 1,447,873
 $
 1,474,799

 Purchased Power and Transmission
 244,351
 604,983
 665,478

 288,342
 284,442
 255,991

 154,072
 140,417
 127,962

 136,113
 ( 16,343)
 42,867

 42,871
 39,618
 37,434

 96,969
 93,894
 95,301

 962,718
 1,147,011
 1,225,033

 331,775
 300,862
 249,766

 77,770
 72,786
 59,548

 31,123
 26,597
 32,666

 285,128
 254,673
 222,884

 70,245
 59,014
 51,314

 $
 $
 $

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

 CONSOLIDATED STATEMENTS OF COMPREHENSIVE INCOME

 2024
 2023
 2022

 $
 $
 $

 Other Comprehensive Income/(Loss), Net of Tax:

 —
 ( 96)

 Other Comprehensive Income/(Loss), Net of Tax
 —
 ( 96)

 Comprehensive Income
 $
 $
 195,732
 $
 171,474

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

 CONSOLIDATED STATEMENTS OF COMMON STOCKHOLDER'S EQUITY

 Capital
Surplus,
Paid In
 Retained
Earnings
 Accumulated Other
Comprehensive
Income/(Loss)
 Total
Common
Stockholder's
Equity

 (Thousands of Dollars, Except Stock Information)
 Stock

 $
 —
 $
 1,088,134
 $
 504,556
 $
 $
 1,592,713

 ( 104,000)
 ( 104,000)

 210,000
 210,000

 ( 96)
 ( 96)

 —
 1,298,134
 572,126
 ( 73)
 1,870,187

 ( 112,000)
 ( 112,000)

 400,000
 400,000

 —
 1,698,134
 655,785
 —
 2,353,919

 ( 62,000)

 ( 62,000)

 $
 —
 $
 1,898,134
 $
 808,668
 $
 —
 $
 2,706,802

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

 CONSOLIDATED STATEMENTS OF CASH FLOWS

 2024
 2023
 2022

 $
 $
 $

 Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

 154,072
 140,417
 127,962

 77,082
 118,970
 15,765

 4,688
 3,989
 9,211

 Pension, SERP and PBOP Income, Net
 ( 8,759)
 ( 10,484)
 ( 16,421)

 Regulatory (Under)/Over Recoveries, Net
 ( 227,943)
 ( 273,472)
 53,181

 136,113
 ( 16,343)
 42,867

 Cost of Removal Expenditures
 ( 42,507)
 ( 39,976)
 ( 39,895)

 Other
 10,391
 8,691

 Receivables and Unbilled Revenues, Net
 ( 29,875)
 ( 5,434)
 ( 62,078)

 30,443
 ( 23,492)

 ( 7,204)
 ( 55,957)
 81,046

 20,255
 ( 36,637)
 ( 6,908)

 321,301
 32,039
 361,499

 Investments in Property, Plant and Equipment
 ( 608,812)
 ( 605,109)
 ( 485,611)

 —
 1,013

 ( 608,812)
 ( 604,813)
 ( 484,598)

 Cash Dividends on Common Stock
 ( 62,000)
 ( 112,000)
 ( 104,000)

 (Decrease)/Increase in Notes Payable to Eversource Parent
 ( 101,900)
 59,700
 62,700

 600,000
 —

 —
 ( 325,000)
 —

 Repayment of Rate Reduction Bonds

 400,000
 210,000

 ( 3,140)
 ( 8,524)
 ( 705)

 Net Cash Flows Provided by Financing Activities
 289,750
 570,966
 124,785

 Net Increase/(Decrease) in Cash and Restricted Cash
 2,239
 ( 1,808)
 1,686

 Cash and Restricted Cash - Beginning of Year
 35,004
 36,812
 35,126

 Cash and Restricted Cash - End of Year
 $
 37,243
 $
 35,004
 $
 36,812

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

 COMBINED NOTES TO FINANCIAL STATEMENTS

 Refer to the Glossary of Terms included in this combined Annual Report on Form 10-K for abbreviations and acronyms used throughout the combined notes to the financial statements.

 1. SUMMARY OF SIGNIFICANT ACCOUNTING POLICIES

 A. About Eversource, CL&P, NSTAR Electric and PSNH
 Eversource Energy is a public utility holding company primarily engaged, through its wholly-owned regulated utility subsidiaries, in the energy delivery business. Eversource Energy's wholly-owned regulated utility subsidiaries consist of CL&P, NSTAR Electric and PSNH (electric utilities), Yankee Gas, NSTAR Gas and EGMA (natural gas utilities), and Aquarion (water utilities). Eversource provides energy delivery and/or water service to approximately 4.6 million electric, natural gas and water customers through twelve regulated utilities in Connecticut, Massachusetts and New Hampshire.

 Eversource, CL&P, NSTAR Electric and PSNH are reporting companies under the Securities Exchange Act of 1934. Eversource Energy is a public utility holding company under the Public Utility Holding Company Act of 2005. Arrangements among the regulated electric companies and other Eversource companies, outside agencies and other utilities covering interconnections, interchange of electric power and sales of utility property are subject to regulation by the FERC. Eversource's regulated companies are subject to regulation of rates, accounting and other matters by the FERC and/or applicable state regulatory commissions (the PURA for CL&P, Yankee Gas and Aquarion, the DPU for NSTAR Electric, NSTAR Gas, EGMA and Aquarion, and the NHPUC for PSNH and Aquarion).

 CL&P, NSTAR Electric and PSNH furnish franchised retail electric service in Connecticut, Massachusetts and New Hampshire, respectively. NSTAR Gas and EGMA are engaged in the distribution and sale of natural gas to customers within Massachusetts and Yankee Gas is engaged in the distribution and sale of natural gas to customers within Connecticut. Aquarion is engaged in the collection, treatment and distribution of water in Connecticut, Massachusetts and New Hampshire. CL&P, NSTAR Electric and PSNH's results include the operations of their respective distribution and transmission businesses. The distribution business also includes the results of NSTAR Electric's solar power facilities.

 Eversource Service, Eversource's service company, and several wholly-owned real estate subsidiaries of Eversource, provide support services to Eversource, including its regulated companies.

 B. Basis of Presentation
 The consolidated financial statements of Eversource, NSTAR Electric and PSNH include the accounts of each of their respective subsidiaries. Intercompany transactions have been eliminated in consolidation. The accompanying consolidated financial statements of Eversource, NSTAR Electric and PSNH and the financial statements of CL&P are herein collectively referred to as the "financial statements."

 The preparation of the financial statements in conformity with GAAP requires management to make estimates and assumptions that affect the reported amounts of assets and liabilities and the disclosure of contingent liabilities as of the date of the financial statements and the reported amounts of revenues and expenses during the reporting period. Actual results could differ from those estimates.

 CYAPC and YAEC are inactive regional nuclear power companies engaged in the long-term storage of their spent nuclear fuel. Eversource consolidates the operations of CYAPC and YAEC because CL&P's, NSTAR Electric's and PSNH's combined ownership and voting interests in each of these entities is greater than 50 percent. Intercompany transactions between CL&P, NSTAR Electric, PSNH and the CYAPC and YAEC companies have been eliminated in consolidation of the Eversource financial statements.

 Eversource holds equity ownership interests that are not consolidated and are accounted for under the equity method. In the third quarter of 2024, Eversource sold its 50 percent equity ownership interests in three offshore wind projects that had been accounted for under the equity method. See Note 6, "Investments in Unconsolidated Affiliates," for further information.

 In accordance with accounting guidance on noncontrolling interests in consolidated financial statements, the Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric, which are not owned by Eversource or its consolidated subsidiaries and are not subject to mandatory redemption, have been presented as noncontrolling interests in the financial statements of Eversource. The Preferred Stock of CL&P and the Preferred Stock of NSTAR Electric are considered to be temporary equity and have been classified between liabilities and permanent shareholders' equity on the balance sheets of Eversource, CL&P and NSTAR Electric due to a provision in the preferred stock agreements of both CL&P and NSTAR Electric that grant preferred stockholders the right to elect a majority of the CL&P and NSTAR Electric Boards of Directors, respectively, should certain conditions exist, such as if preferred dividends are in arrears for a specified amount of time. The Net Income reported in the statements of income and cash flows represents net income prior to apportionment to noncontrolling interests, which is represented by dividends on preferred stock of CL&P and NSTAR Electric.

 Eversource's utility subsidiaries' electric, natural gas and water distribution and transmission businesses are subject to rate-regulation that is based on cost recovery and meets the criteria for application of accounting guidance for entities with rate-regulated operations, which considers the effect of regulation on the differences in the timing of the recognition of certain revenues and expenses from those of other businesses and industries. See Note 2, "Regulatory Accounting," for further information.

 As of December 31, 2024 and 2023, Eversource's carrying amount of goodwill was $ 3.57 billion and $ 4.53 billion, respectively. Eversource performs an assessment for possible impairment of its goodwill at least annually. Eversource completed its annual goodwill impairment assessment for each of its reporting units as of October 1, 2024, and performed an interim goodwill impairment test in the fourth quarter of 2024. Eversource recorded a goodwill impairment charge of $ 297 million in 2024 as a result of the likely sale of Aquarion at a loss. See Note 25, "Goodwill," for further information. The assets and liabilities of the Aquarion water distribution business, including remaining goodwill of $ 662.5 million, met the criteria to be classified as held for sale as of December 31, 2024. Unless otherwise specified, the amounts and information in the notes presented do not include assets and liabilities that have been reclassified as held for sale. See Note 24, "Assets Held for Sale," for further information.

 Certain reclassifications of prior year data were made in the accompanying financial statements to conform to the current year presentation.

 C. Accounting Standards
 Accounting Standards Recently Adopted: On January 1, 2025, the Company retrospectively adopted Accounting Standards Update (ASU) 2023-07, Segment Reporting (Topic 280): Improvements to Reportable Segment Disclosures, which requires entities to disclose significant segment expenses, other segment items, and the title and position of the chief operating decision maker (CODM). Additionally, the ASU requires entities to disclose how the CODM assesses segment performance and allocates resources, among certain other required disclosures. Furthermore, current annual disclosures will be required in interim periods. The modified disclosures are included in Note 23, "Segment Information."

 D. Cash
 Cash includes cash on hand. At the end of each reporting period, any overdraft amounts are reclassified from Cash to Accounts Payable on the balance sheets.

 E. Allowance for Uncollectible Accounts
 Receivables, Net on the balance sheets primarily includes trade receivables from retail customers and customers related to wholesale transmission contracts, wholesale market sales, sales of RECs, and property rentals. Receivables, Net also includes customer receivables for the purchase of electricity from a competitive third party supplier, the current portion of customer energy efficiency loans, property damage receivables and other miscellaneous receivables. There is no material concentration of receivables.

 Receivables are recorded at amortized cost, net of a credit loss provision (or allowance for uncollectible accounts). The current expected credit loss (CECL) model is applied to receivables for purposes of calculating the allowance for uncollectible accounts. This model is based on expected losses and results in the recognition of estimated expected credit losses, including uncollectible amounts for both billed and unbilled revenues, over the life of the receivable at the time a receivable is recorded.

 The allowance for uncollectible accounts is determined based upon a variety of judgments and factors, including an aging-based quantitative assessment that applies an estimated uncollectible percentage to each receivable aging category. Factors in determining credit loss include historical collection, write-off experience, analysis of delinquency statistics, and management's assessment of collectability from customers, including current economic conditions, customer payment trends, the impact on customer bills because of energy usage trends and changes in rates, flexible payment plans and financial hardship arrearage management programs offered to customers, reasonable forecasts, and expectations of future collectability and collection efforts. Management continuously assesses the collectability of receivables and adjusts estimates based on actual experience and future expectations based on economic conditions, collection efforts and other factors. Management also monitors the aging analysis of receivables to determine if there are changes in the collections of accounts receivable. Receivable balances are written off against the allowance for uncollectible accounts when the customer accounts are no longer in service and these balances are deemed to be uncollectible. Management concluded that the reserve balance as of December 31, 2024 adequately reflected the collection risk and net realizable value for its receivables.

 The PURA allows CL&P and Yankee Gas to accelerate the recovery of accounts receivable balances attributable to qualified customers under financial or medical duress (uncollectible hardship accounts receivable) outstanding for greater than 180 days and 90 days, respectively. The DPU allows NSTAR Electric, NSTAR Gas and EGMA to recover in rates amounts associated with certain uncollectible hardship accounts receivable. These uncollectible hardship customer account balances are included in Regulatory Assets or Other Long-Term Assets on the balance sheets. Hardship customers are protected from shut-off in certain circumstances, and historical collection experience has reflected a higher default risk as compared to the rest of the receivable population. Management uses a higher credit risk profile for this pool of trade receivables as compared to non-hardship receivables. The allowance for uncollectible hardship accounts is included in the total uncollectible allowance balance.

 The total allowance for uncollectible accounts is included in Receivables, Net on the balance sheets. The activity in the allowance for uncollectible accounts by portfolio segment is as follows:

 CL&P
 PSNH

 Hardship Accounts
 Retail (Non-Hardship),
Wholesale, and Other
 Total Allowance
 Hardship Accounts
 Retail (Non-Hardship),
Wholesale, and Other
 Total Allowance
 Hardship Accounts
 Retail (Non-Hardship),
Wholesale, and Other
 Total Allowance
 Total Allowance (3)

 $
 226.1
 $
 191.3
 $
 417.4
 $
 144.6
 $
 36.7
 $
 181.3
 $
 43.3
 $
 53.7
 $
 97.0
 $
 24.3

 —
 61.9
 61.9
 —
 15.6
 15.6
 —
 21.6
 21.6
 9.2

 Uncollectible Costs Deferred (1)

 77.8
 34.7
 112.5
 58.3
 1.2
 59.5
 1.5
 10.9
 12.4
 2.5

 Write-Offs
 ( 21.3)
 ( 102.7)
 ( 124.0)
 ( 15.3)
 ( 23.0)
 ( 38.3)
 ( 1.1)
 ( 41.2)
 ( 42.3)
 ( 7.7)

 Recoveries Collected
 1.8
 16.7
 18.5
 1.3
 5.9
 7.2
 —
 6.3
 6.3
 0.9

 $
 284.4
 $
 201.9
 $
 486.3
 $
 188.9
 $
 36.4
 $
 225.3
 $
 43.7
 $
 51.3
 $
 95.0
 $
 29.2

 —
 72.5
 72.5
 —
 11.7
 11.7
 —
 22.8
 22.8
 4.0

 Uncollectible Costs Deferred (1)

 137.0
 21.2
 158.2
 114.4
 12.0
 126.4
 1.5
 16.0
 17.5
 ( 8.7)

 Write-Offs
 ( 55.9)
 ( 122.2)
 ( 178.1)
 ( 44.7)
 ( 28.5)
 ( 73.2)
 ( 1.6)
 ( 41.7)
 ( 43.3)
 ( 10.9)

 Recoveries Collected
 1.3
 14.3
 15.6
 1.1
 4.7
 5.8
 —
 5.0
 5.0
 0.7

 $
 366.8
 $
 187.7
 $
 554.5
 $
 259.7
 $
 36.3
 $
 296.0
 $
 43.6
 $
 53.4
 $
 97.0
 $
 14.3

 —
 74.1
 74.1
 —
 17.2
 17.2
 —
 33.6
 33.6
 4.7

 Uncollectible Costs Deferred (1)

 71.4
 48.3
 119.7
 35.5
 11.3
 46.8
 16.2
 21.5
 37.7
 5.1

 Write-Offs
 ( 74.3)
 ( 129.5)
 ( 203.8)
 ( 55.1)
 ( 30.9)
 ( 86.0)
 ( 52.4)
 ( 57.0)
 ( 10.9)

 Recoveries Collected
 0.7
 13.3
 14.0
 0.6
 4.5
 5.1
 —
 3.6
 3.6
 0.9

 Decrease due to Assets Held
 for Sale (2)

 —
 ( 2.3)
 ( 2.3)
 —
 —
 —
 —
 —
 —
 —

 $
 364.6
 $
 191.6
 $
 556.2
 $
 240.7
 $
 38.4
 $
 279.1
 $
 55.2
 $
 59.7
 $
 114.9
 $
 14.1

 (1) These expected credit losses are deferred as regulatory costs on the balance sheets, as these amounts are ultimately recovered in rates. Amounts include uncollectible costs for hardship accounts and other customer receivables, including uncollectible amounts related to uncollectible energy supply costs.

 (2) As of December 31, 2024, the allowance for uncollectible accounts attributable to the Aquarion water distribution business has been reclassified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2023, this balance was recorded within Receivables, Net on the Eversource balance sheet. For further information, see Note 24, "Assets Held for Sale."

 (3) In connection with PSNH's pole purchase agreement on May 1, 2023, the purchase price included the forgiveness of previously reserved receivables for reimbursement of operation and maintenance and vegetation management costs.

 F. Transfer of Energy Efficiency Loans
 CL&P transferred a portion of its energy efficiency customer loan portfolio to outside lenders in order to make additional loans to customers. CL&P remains the servicer of the loans and will transmit customer payments to the lenders, with a maximum amount outstanding under this program of $ 70 million. The amounts of the loans are included in Receivables, Net and Other Long-Term Assets, and are offset by Other Current Liabilities and Other Long-Term Liabilities on CL&P's balance sheet. The current and long-term portions totaled $ 9.4 million and $ 17.3 million, respectively, as of December 31, 2024, and $ 8.5 million and $ 14.5 million, respectively, as of December 31, 2023.

 G. Materials, Supplies, Natural Gas and REC Inventory
 Materials, Supplies, Natural Gas and REC Inventory include materials and supplies purchased primarily for construction or operation and maintenance purposes, natural gas purchased for delivery to customers, and RECs. Inventory is valued at the lower of cost or net realizable value. RECs are purchased from suppliers of renewable sources of generation and are used to meet state mandated Renewable Portfolio Standards requirements. The carrying amounts of materials and supplies, natural gas inventory, and RECs, which are included in Current Assets on the balance sheets, were as follows:

 2024
 2023

 CL&P
 PSNH
 CL&P
 PSNH

 Materials and Supplies
 $
 498.6
 $
 217.3
 $
 177.8
 $
 72.1
 $
 397.9
 $
 156.2
 $
 130.8
 $
 76.5

 49.5
 —
 —
 —
 65.5
 —
 —
 —

 RECs
 46.5
 —
 42.8
 3.7
 43.9
 0.3
 43.0
 0.6

 Total
 $
 594.6
 $
 217.3
 $
 220.6
 $
 75.8
 $
 507.3
 $
 156.5
 $
 173.8
 $
 77.1

 As of December 31, 2024, the materials and supplies attributable to the Aquarion water distribution business have been reclassified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2023, these balances were recorded within Materials, Supplies, Natural Gas and REC Inventory on the Eversource balance sheet. For further information, see Note 24, "Assets Held for Sale."

 H. Fair Value Measurements
 Fair value measurement guidance is applied to derivative contracts that are not elected or designated as "normal purchases" or "normal sales" (normal) and to marketable securities held in trusts. Fair value measurement guidance is also applied to valuations of the investments used to calculate the funded status of pension and PBOP plans, the nonrecurring fair value measurements of nonfinancial assets such as goodwill, long-lived assets, equity method investments, AROs, and in the valuation of business combinations and asset acquisitions. The fair value measurement guidance was also applied in estimating the fair value of preferred stock, long-term debt and RRBs.

 Fair Value Hierarchy: In measuring fair value, Eversource uses observable market data when available in order to minimize the use of unobservable inputs. Inputs used in fair value measurements are categorized into three fair value hierarchy levels for disclosure purposes. The entire fair value measurement is categorized based on the lowest level of input that is significant to the fair value measurement. Eversource evaluates the classification of assets and liabilities measured at fair value on a quarterly basis.

 The levels of the fair value hierarchy are described below:

 Level 1 - Inputs are quoted prices (unadjusted) in active markets for identical assets or liabilities as of the reporting date. Active markets are those in which transactions for the asset or liability occur in sufficient frequency and volume to provide pricing information on an ongoing basis.

 Level 2 - Inputs are quoted prices for similar instruments in active markets, quoted prices for identical or similar instruments in markets that are not active, and model-derived valuations in which all significant inputs are observable.

 Level 3 - Quoted market prices are not available. Fair value is derived from valuation techniques in which one or more significant inputs or assumptions are unobservable. Where possible, valuation techniques incorporate observable market inputs that can be validated to external sources such as industry exchanges, including prices of energy and energy-related products.

 Uncategorized - Investments that are measured at net asset value are not categorized within the fair value hierarchy.

 Determination of Fair Value: The valuation techniques and inputs used in Eversource's fair value measurements are described in Note 4, "Derivative Instruments," Note 5, "Marketable Securities," Note 6, "Investments in Unconsolidated Affiliates," Note 7, "Asset Retirement Obligations," Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," Note 15, "Fair Value of Financial Instruments," and Note 25, "Goodwill," to the financial statements.

 I. Derivative Accounting
 Many of the electric and natural gas companies' contracts for the purchase and sale of energy or energy-related products are derivatives. The accounting treatment for energy contracts entered into varies and depends on the intended use of the particular contract and on whether or not the contract is a derivative.

 The application of derivative accounting is complex and requires management judgment in the following respects: identification of derivatives and embedded derivatives, election and designation of a contract as normal, and determination of the fair value of derivative contracts. All of these judgments can have a significant impact on the financial statements. The judgment applied in the election of a contract as normal (and resulting accrual accounting) includes the conclusion that it is probable at the inception of the contract and throughout its term that it will result in physical delivery of the underlying product and that the quantities will be used or sold by the business in the normal course of business. If facts and circumstances change and management can no longer support this conclusion, then a contract cannot be considered normal, accrual accounting is terminated, and fair value accounting is applied prospectively.

 The fair value of derivative contracts is based upon the contract terms and conditions and the underlying market price or fair value per unit. When quantities are not specified in the contract, the Company determines whether the contract has a determinable quantity by using amounts referenced in default provisions and other relevant sections of the contract. The fair value of derivative assets and liabilities with the same counterparty are offset and recorded as a net derivative asset or liability on the balance sheets.

 Regulatory assets or regulatory liabilities are recorded to offset the fair values of these derivative contracts related to energy and energy-related products, as contract settlements are recovered from, or refunded to, customers in future rates. All changes in the fair value of these derivative contracts are recorded as regulatory assets or liabilities and do not impact net income.

 For further information regarding derivative contracts, see Note 4, "Derivative Instruments," to the financial statements.

 J. Operating Expenses
 The cost of natural gas included in Purchased Power, Purchased Natural Gas and Transmission on the statements of income was as follows:

 2024
 2023
 2022

 Eversource - Cost of Natural Gas
 $
 689.6
 $
 792.2
 $
 1,010.2

 K. Allowance for Funds Used During Construction
 AFUDC represents the cost of borrowed and equity funds used to finance construction and is included in the cost of the electric, natural gas and water companies' utility plant on the balance sheet. The portion of AFUDC attributable to borrowed funds is recorded as a reduction of Interest Expense, and the AFUDC related to equity funds is recorded as Other Income, Net on the statements of income. AFUDC costs are recovered from customers over the service life of the related plant in the form of increased revenue collected as a result of higher depreciation expense.

 The average AFUDC rate is based on a FERC-prescribed formula using the cost of a company's short-term financings and capitalization (preferred stock, long-term debt and common equity), as appropriate. The average rate is applied to average eligible CWIP amounts to calculate AFUDC.

 AFUDC costs and the weighted-average AFUDC rates were as follows:

 (Millions of Dollars, except percentages)
 2024
 2023
 2022

 Borrowed Funds
 $
 64.4
 $
 44.6
 $
 21.8

 Equity Funds
 97.8
 78.1
 47.3

 Total AFUDC
 $
 162.2
 $
 122.7
 $
 69.1

 Average AFUDC Rate
 6.5
 %
 5.8
 %
 4.7
 %

 2024
 2023
 2022

 (Millions of Dollars,
except percentages)
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Borrowed Funds
 $
 8.1
 $
 27.2
 $
 8.9
 $
 7.7
 $
 17.2
 $
 6.1
 $
 4.8
 $
 10.7
 $
 1.4

 Equity Funds
 22.4
 58.8
 7.0
 20.0
 45.7
 5.4
 13.6
 24.6
 2.5

 Total AFUDC
 $
 30.5
 $
 86.0
 $
 15.9
 $
 27.7
 $
 62.9
 $
 11.5
 $
 18.4
 $
 35.3
 $
 3.9

 Average AFUDC Rate
 6.7
 %
 7.0
 %
 5.5
 %
 6.7
 %
 5.9
 %
 5.1
 %
 6.6
 %
 5.4
 %
 2.6
 %

 L. Other Income, Net
 The components of Other Income, Net on the statements of income were as follows:

 2024
 2023
 2022

 Pension, SERP and PBOP Non-Service Income Components,
 Net of Deferred Portion (1)

 $
 115.4
 $
 132.9
 $
 219.8

 AFUDC Equity
 97.8
 78.1
 47.3

 Equity in Earnings of Unconsolidated Affiliates (2)

 51.9
 15.5
 22.9

 Investment Income/(Loss)
 0.6
 ( 4.9)
 1.9

 138.2
 94.2
 50.5

 Other (2)

 6.6
 32.3
 3.7

 Total Other Income, Net
 $
 410.5
 $
 348.1
 $
 346.1

 2024
 2023
 2022

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Pension, SERP and PBOP Non-Service Income Components, Net of Deferred Portion (1)

 $
 28.2
 $
 52.8
 $
 14.9
 $
 34.9
 $
 57.4
 $
 16.2
 $
 64.4
 $
 85.5
 $
 26.8

 AFUDC Equity
 22.4
 58.8
 7.0
 20.0
 45.7
 5.4
 13.6
 24.6
 2.5

 Investment (Loss)/Income
 ( 1.4)
 1.9
 ( 2.4)
 1.2
 0.2

 28.3
 77.0
 9.6
 9.0
 60.6
 5.3
 6.5
 30.7
 3.1

 Other
 0.1
 0.9
 0.1
 0.1
 0.6
 0.4
 0.1
 0.7
 0.1

 Total Other Income, Net
 $
 77.6
 $
 191.4
 $
 31.1
 $
 61.6
 $
 164.1
 $
 26.6
 $
 83.3
 $
 142.7
 $
 32.7

 (1) See Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for the components of net periodic benefit income/expense for the Pension, SERP and PBOP Plans. The non-service related components of pension, SERP and PBOP benefit income/expense, after capitalization or deferral, are presented as non-operating income and recorded in Other Income, Net on the statements of income.

 (2) Equity in Earnings of Unconsolidated Affiliates includes $ 23.4 million of pre-tax income recorded at Eversource in the second quarter of 2024 from Eversource's wind equity method investment, North East Offshore, as a result of a vendor settlement agreement payment received by the joint venture. In the third quarter of 2024, Eversource sold its equity method investments in three offshore wind projects. In March 2023, Eversource's equity method investment in a renewable energy fund was liquidated. Liquidation proceeds in excess of the carrying value were recorded in 2023 within Other in the table above. For the year ended December 31, 2022, pre-tax income of $ 12.2 million associated with the renewable energy fund investment was included in Equity in Earnings of Unconsolidated Affiliates within Other Income, Net in the table above. See Note 6, "Investments in Unconsolidated Affiliates," for further information on the 2024 sales of the offshore wind investments and the 2023 liquidation of the renewable energy fund.

 M. Other Taxes
 Eversource's companies that serve customers in Connecticut collect gross receipts taxes levied by the state of Connecticut from their customers. These gross receipts taxes are recorded separately with collections in Operating Revenues and with payments in Taxes Other Than Income Taxes on the statements of income as follows:

 2024
 2023
 2022

 $
 209.4
 $
 202.9
 $
 194.7

 CL&P
 185.1
 174.9
 166.1

 As agents for state and local governments, Eversource's companies that serve customers in Connecticut and Massachusetts collect certain sales taxes that are recorded on a net basis with no impact on the statements of income.

 N. Supplemental Cash Flow Information

 As of and For the Years Ended December 31,

 2024
 2023
 2022

 Cash Paid/(Received) During the Year for:

 Interest, Net of Amounts Capitalized
 $
 1,014.4
 $
 783.2
 $
 636.2

 Income Taxes
 ( 69.6)
 39.2
 77.9

 Non-Cash Investing Activities:

 Plant Additions Included in Accounts Payable (As of)
 472.5
 564.1
 586.9

 As of and For the Years Ended December 31,

 2024
 2023
 2022

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Cash Paid/(Received) During the Year for:

 Interest, Net of Amounts Capitalized
 $
 216.8
 $
 215.1
 $
 78.4
 $
 176.8
 $
 182.8
 $
 62.8
 $
 167.2
 $
 152.8
 $
 58.3

 Income Taxes
 ( 47.4)
 118.7
 ( 36.0)
 ( 44.1)
 31.3
 ( 59.9)
 117.6
 23.8
 58.3

 Non-Cash Investing Activities:

 Plant Additions Included in Accounts
 Payable (As of)
 95.8
 155.4
 77.7
 139.8
 178.9
 65.9
 131.8
 184.3
 76.2

 The following table reconciles cash as reported on the balance sheets to the cash and restricted cash balance as reported on the statements of cash flows:

 2024
 2023

 CL&P
 PSNH
 CL&P
 PSNH

 Cash as reported on the Balance Sheets
 $
 26.7
 $
 1.1
 $
 0.9
 $
 1.4
 $
 53.9
 $
 10.2
 $
 6.7
 $
 0.2

 Restricted cash included in:

 Special Deposits
 75.8
 1.0
 8.1
 32.7
 81.5
 2.0
 16.1
 31.6

 Assets Held for Sale, Current
 5.8
 —
 —
 —
 —
 —
 —
 —

 Marketable Securities
 10.0
 —
 —
 —
 13.7
 —
 —
 —

 9.0
 —
 —
 3.1
 17.3
 —
 —
 3.2

 Cash and Restricted Cash as reported on the
 Statements of Cash Flows
 $
 127.3
 $
 2.1
 $
 9.0
 $
 37.2
 $
 166.4
 $
 12.2
 $
 22.8
 $
 35.0

 Special Deposits represent cash collections related to the PSNH RRB customer charges that are held in trust, required ISO-NE cash deposits, cash held in escrow accounts, and CYAPC and YAEC cash balances. Special Deposits are included in Current Assets on the balance sheets. Restricted cash included in Marketable Securities represents money market funds held in restricted trusts to fund CYAPC and YAEC's spent nuclear fuel storage obligations.

 Eversource's restricted cash also includes an Energy Relief Fund for energy efficiency and clean energy measures in the Merrimack Valley established under the terms of the EGMA 2020 settlement agreement. This restricted cash held in escrow accounts included $ 20.0 million recorded as short-term in Special Deposits as of both December 31, 2024 and December 31, 2023, and $ 5.9 million and $ 14.1 million recorded in Other Long-Term Assets on the balance sheets as of December 31, 2024 and December 31, 2023, respectively.

 O. Related Parties
 Eversource Service, Eversource's service company, provides centralized accounting, administrative, engineering, financial, information technology, legal, operational, planning, purchasing, tax, and other services to Eversource's companies. The Rocky River Realty Company and Properties, Inc., two other Eversource subsidiaries, construct, acquire or lease some of the property and facilities used by Eversource's companies.

 Included in the CL&P, NSTAR Electric and PSNH balance sheets as of December 31, 2024 and 2023 were Accounts Receivable from Affiliated Companies and Accounts Payable to Affiliated Companies relating to transactions between CL&P, NSTAR Electric and PSNH and other subsidiaries that are wholly-owned by Eversource. These amounts have been eliminated in consolidation on the Eversource financial statements.

 Included in the CL&P and PSNH balance sheets as of December 31, 2024 and 2023 were Notes Payable to Eversource Parent. These amounts have been eliminated in consolidation on the Eversource financial statements. See Note 8, "Short-Term Debt" for intercompany borrowing amounts.

 The Eversource Energy Foundation is an independent not-for-profit charitable entity and is not included in the consolidated financial statements of Eversource as the Company does not have title to, and cannot receive contributions back from, the Eversource Energy Foundation's assets. Eversource made contributions to the Eversource Energy Foundation of $ 20.0 million in 2023, and $ 8.0 million in 2022. Eversource did not make any contributions in 2024.

 2. REGULATORY ACCOUNTING

 Eversource's utility companies are subject to rate regulation that is based on cost recovery and meets the criteria for application of accounting guidance for rate-regulated operations, which considers the effect of regulation on the timing of the recognition of certain revenues and expenses. The regulated companies' financial statements reflect the effects of the rate-making process. The rates charged to the customers of Eversource's regulated companies are designed to collect each company's costs to provide service, plus a return on investment.

 The application of accounting guidance for rate-regulated enterprises results in recording regulatory assets and liabilities. Regulatory assets represent the deferral of incurred costs that are probable of future recovery in customer rates. Regulatory assets are amortized as the incurred costs are recovered through customer rates. Regulatory liabilities represent either revenues received from customers to fund expected costs that have not yet been incurred or probable future refunds to customers.

 Management believes it is probable that each of the regulated companies will recover its respective investments in long-lived assets and the regulatory assets that have been recorded. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises, or if management could not conclude it is probable that costs would be recovered from customers in future rates, the applicable costs would be charged to net income in the period in which the determination is made.

 Regulatory Assets: The components of regulatory assets were as follows:

 2024
 2023

 CL&P
 PSNH
 CL&P
 PSNH

 Storm Costs, Net
 $
 2,039.4
 $
 971.1
 $
 609.8
 $
 458.5
 $
 1,785.9
 $
 896.6
 $
 609.1
 $
 280.2

 Regulatory Tracking Mechanisms
 1,781.6
 507.7
 650.0
 162.8
 1,319.2
 354.5
 482.9
 182.2

 Benefit Costs
 967.4
 168.8
 293.6
 65.6
 1,117.3
 197.4
 336.7
 79.3

 Income Taxes, Net
 968.4
 521.0
 145.4
 20.7
 912.4
 512.6
 128.6
 16.4

 Securitized Stranded Costs
 349.3
 —
 —
 349.3
 392.5
 —
 —
 392.5

 Goodwill-related
 247.2
 —
 212.3
 —
 264.1
 —
 226.7
 —

 Asset Retirement Obligations
 150.2
 41.2
 78.3
 5.1
 137.9
 38.5
 72.3
 4.7

 Derivative Liabilities
 57.2
 57.2
 —
 —
 120.9
 120.9
 —
 —

 Other Regulatory Assets
 510.0
 58.5
 117.7
 3.7
 339.0
 22.7
 101.6
 8.0

 Total Regulatory Assets
 7,070.7
 2,325.5
 2,107.1
 1,065.7
 6,389.2
 2,143.2
 1,957.9
 963.3

 Less: Current Portion
 2,189.7
 638.5
 902.8
 173.3
 1,674.2
 480.4
 676.1
 189.5

 Total Long-Term Regulatory Assets
 $
 4,881.0
 $
 1,687.0
 $
 1,204.3
 $
 892.4
 $
 4,715.0
 $
 1,662.8
 $
 1,281.8
 $
 773.8

 As of December 31, 2024, the Regulatory Assets attributable to the Aquarion water distribution business have been reclassified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2023, these balances were recorded within Regulatory Assets on the Eversource balance sheet. For further information, see Note 24, "Assets Held for Sale."

 Storm Costs, Net: The storm cost deferrals relate to costs incurred for storm events at CL&P, NSTAR Electric and PSNH that each company expects to recover from customers. A storm must meet certain criteria to qualify for deferral and recovery with the criteria specific to each state jurisdiction and utility company. Once a storm qualifies for recovery, all qualifying expenses incurred during storm restoration efforts are deferred and recovered from customers. Costs for storms that do not meet the specific criteria are expensed as incurred. In addition to storm restoration costs, CL&P and PSNH are each allowed to recover pre-staging storm costs. Management believes all storm costs deferred were prudently incurred and meet the criteria for specific cost recovery in Connecticut, Massachusetts and New Hampshire, and that recovery from customers is probable through the applicable regulatory recovery processes. Each electric utility company either recovers a carrying charge on its deferred storm cost regulatory asset balance or the regulatory asset balance is included in rate base.

 Multiple tropical and severe storms over the past several years have caused extensive damage to Eversource's electric distribution systems resulting in significant numbers and durations of customer outages, along with significant pre-staging costs. Storms in 2024 that qualified for future recovery resulted in deferred storm restoration costs and pre-staging costs totaling $ 410 million at Eversource, including $ 134 million at CL&P, $ 85 million at NSTAR Electric, and $ 191 million at PSNH. Management believes that all of these storm costs were prudently incurred and meet the criteria for specific cost recovery. Of Eversource's total deferred storm costs, $ 2.10 billion either have yet to be filed with the applicable regulatory commission, are pending regulatory approval, or are subject to prudency review (including $ 1.12 billion at CL&P, $ 551 million at NSTAR Electric and $ 440 million at PSNH) as of December 31, 2024. These storm cost totals exclude storm funding amounts that are collected in rates, which are recorded as a reduction to the deferred storm cost regulatory asset balance.

 CL&P, NSTAR Electric and PSNH are seeking approval of their deferred storm restoration costs through the applicable regulatory recovery process. As part of CL&P's October 1, 2021 settlement agreement, CL&P agreed to freeze its current base distribution rates (including storm costs) until no earlier than January 1, 2024. On March 28, 2024, PURA established a prudency review proceeding for the purpose of receiving and reviewing evidence of the costs reported by CL&P in response to catastrophic storms and pre-staging events totaling approximately $ 634 million that occurred between January 1, 2018 and December 31, 2021. On December 31, 2024, CL&P filed a supplement to its March 2024 prudency review application to request that PURA evaluate the prudence of its costs for nine additional catastrophic storms and two additional pre-staging events for the period January 1, 2022 through January 31, 2023 totaling approximately $ 173 million. Although we cannot predict the ultimate outcome of this matter, we continue to believe these deferred storm restoration costs were prudently incurred and are probable of recovery.

 CL&P's storm events include the August 4, 2020 Tropical Storm Isaias, which resulted in deferred storm restoration costs of approximately $ 232 million at CL&P as of December 31, 2024. Although in 2021 PURA found that CL&P's performance in its preparation for, and response to, Tropical Storm Isaias fell below applicable performance standards in certain instances, CL&P believes it presented in its 2023 storm filing, credible evidence demonstrating there is no reasonably close causal connection between the alleged sub-standard performance and the storm costs incurred. While it is possible that some amount of storm costs may be disallowed by PURA, any such amount cannot be estimated at this time. CL&P continues to believe that these storm restoration costs associated with Tropical Storm Isaias were prudently incurred and meet the criteria for cost recovery.

 Regulatory Tracking Mechanisms: The regulated companies' approved rates are designed to recover costs incurred to provide service to customers. The regulated companies recover certain of their costs on a fully-reconciling basis through regulatory commission-approved tracking mechanisms. The differences between the costs incurred (or the rate recovery allowed) and the actual revenues are recorded as regulatory assets (for undercollections) or as regulatory liabilities (for overcollections) to be included in future customer rates each year. Carrying charges are recovered in rates on all material regulatory tracking mechanisms.

 The electric and natural gas distribution companies recover, on a fully reconciling basis, the costs associated with the procurement of energy and natural gas supply, state mandated energy purchase agreements and other energy-related costs, electric transmission related costs from FERC-approved transmission tariffs, energy efficiency programs, low income assistance programs, certain uncollectible accounts receivable for hardship customers, restructuring and stranded costs as a result of deregulation (including securitized RRB charges), certain capital tracking mechanisms for infrastructure improvements, and additionally for the Massachusetts utilities, pension and PBOP benefits, net metering for distributed generation, and solar-related programs.

 CL&P, NSTAR Electric, Yankee Gas, NSTAR Gas, EGMA and the Aquarion Water Company of Connecticut each have a regulatory commission approved revenue decoupling mechanism. Distribution revenues are decoupled from customer sales volumes, where applicable, which breaks the relationship between sales volumes and revenues. Each company reconciles its annual base distribution rate recovery amount to the pre-established levels of baseline distribution delivery service revenues. Any difference between the allowed level of distribution revenue and the actual amount realized during a 12-month period is adjusted through rates in the following period.

 Benefit Costs: Deferred benefit costs represent unrecognized actuarial losses and gains and unrecognized prior service costs and credits attributable to Eversource's Pension, SERP and PBOP Plans. The regulated companies record actuarial losses and gains and prior service costs and credits arising at the December 31st remeasurement date of the funded status of the benefit plans as a regulatory asset or regulatory liability in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. The regulatory asset or regulatory liability is amortized with the recognition of actuarial losses and gains and prior service costs and credits to net periodic benefit expense/income over the estimated average future employee service period using the corridor approach. Regulatory accounting is also applied to the portions of Eversource's service company costs that support the regulated companies, as these amounts are also recoverable. As these regulatory assets or regulatory liabilities do not represent a cash outlay for the regulated companies, no carrying charge is recovered from customers. See Note 11A, "Employee Benefits - Pension Benefits and Postretirement Benefits Other Than Pension," for further information on regulatory benefit plan amounts arising and amortized during the year.

 Eversource, CL&P, NSTAR Electric, and PSNH recover benefit costs related to their distribution and transmission operations from customers in rates as allowed by their applicable regulatory commissions. NSTAR Electric, NSTAR Gas and EGMA recover qualified pension and PBOP expenses related to their distribution operations through a rate reconciling mechanism that fully tracks the change in net pension and PBOP expenses each year. The electric transmission companies' rates provide for an annual true-up of estimated to actual costs, which include pension and PBOP expenses as allowed by FERC.

 Income Taxes, Net: The tax effect of temporary book-tax differences (differences between the periods in which transactions affect income in the financial statements and the periods in which they affect the determination of taxable income, including those differences relating to uncertain tax positions) is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and accounting guidance for income taxes. Differences in income taxes between the accounting guidance and the rate-making treatment of the applicable regulatory commissions are recorded as regulatory assets. As these assets are offset by deferred income tax liabilities, no carrying charge is collected. The amortization period of these assets varies depending on the nature and/or remaining life of the underlying assets and liabilities. For further information regarding income taxes, see Note 12, "Income Taxes," to the financial statements.

 Securitized Stranded Costs: In 2018, a subsidiary of PSNH issued $ 635.7 million of securitized RRBs to finance PSNH's unrecovered remaining costs associated with the divestiture of its generation assets. Securitized regulatory assets, which are not earning an equity return, are being recovered over the amortization period of the associated RRBs. The PSNH RRBs are expected to be repaid by February 1, 2033. For further information, see Note 10, "Rate Reduction Bonds and Variable Interest Entities," to the financial statements.

 Goodwill-related: The goodwill regulatory asset originated from a 1999 transaction, and the DPU allowed its recovery in NSTAR Electric and NSTAR Gas rates. This regulatory asset is currently being amortized and recovered from customers in rates without a carrying charge over a 40 -year period, and as of December 31, 2024, there were 15 years of amortization remaining.

 Asset Retirement Obligations: The costs associated with the depreciation of the regulated companies' ARO assets and accretion of the ARO liabilities are recorded as regulatory assets in accordance with regulatory accounting guidance. The regulated companies' ARO assets, regulatory assets, and ARO liabilities offset and are excluded from rate base. These costs are being recovered over the life of the underlying property, plant and equipment.

 Derivative Liabilities: Regulatory assets are recorded as an offset to derivative liabilities and relate to the fair value of contracts used to purchase energy and energy-related products that will be recovered from customers in future rates. These assets are excluded from rate base and are being recovered as the actual settlements occur over the duration of the contracts. See Note 4, "Derivative Instruments," to the financial statements for further information on these contracts.

 Other Regulatory Assets: Other Regulatory Assets primarily include environmental remediation costs, certain uncollectible accounts receivable for hardship customers, contractual obligations associated with the spent nuclear fuel storage costs of the CYAPC, YAEC and MYAPC decommissioned nuclear power facilities, removal costs incurred that exceed amounts collected from customers, electric vehicle program costs, certain exogenous property taxes and merger-related costs allowed for recovery, losses associated with the reacquisition or redemption of long-term debt, and various other items.

 Regulatory Costs in Other Long-Term Assets: Eversource's regulated companies had $ 221.0 million (including $ 116.3 million for CL&P, $ 41.1 million for NSTAR Electric and $ 4.5 million for PSNH) and $ 241.7 million (including $ 166.7 million for CL&P, $ 21.9 million for NSTAR Electric and $ 1.2 million for PSNH) of additional regulatory costs not yet specifically approved as of December 31, 2024 and 2023, respectively, that were included in Other Long-Term Assets on the balance sheets. These amounts will be reclassified to Regulatory Assets upon approval by the applicable regulatory agency. Based on regulatory policies or past precedent on similar costs, management believes it is probable that these costs will ultimately be approved and recovered from customers in rates. As of December 31, 2024 and 2023, these regulatory costs included $ 92.5 million (including $ 47.2 million for CL&P and $ 24.4 million for NSTAR Electric) and $ 82.1 million (including $ 64.0 million for CL&P and $ 7.3 million for NSTAR Electric), respectively, of deferred uncollectible hardship costs.

 Equity Return on Regulatory Assets: For rate-making purposes, the regulated companies recover the carrying costs related to their regulatory assets. For certain regulatory assets, the carrying cost recovered includes an equity return component. This equity return is not recorded on the balance sheets. The equity return for PSNH was $ 22.5 million and $ 10.2 million as of December 31, 2024 and 2023, respectively. These carrying costs will be recovered from customers in future rates.

 Regulatory Liabilities: The components of regulatory liabilities were as follows:

 2024
 2023

 CL&P
 PSNH
 CL&P
 PSNH

 EDIT due to Tax Cuts and Jobs Act of 2017
 $
 2,442.7
 $
 956.6
 $
 877.6
 $
 330.6
 $
 2,548.6
 $
 969.2
 $
 905.1
 $
 339.3

 Regulatory Tracking Mechanisms
 702.4
 180.3
 413.6
 114.4
 668.3
 154.0
 347.2
 114.4

 Cost of Removal
 684.1
 212.8
 451.3
 20.1
 666.6
 157.9
 420.9
 16.2

 Deferred Portion of Non-Service Income
 Components of Pension, SERP and PBOP
 427.1
 61.6
 211.6
 42.6
 354.0
 49.9
 175.9
 36.6

 AFUDC - Transmission
 154.8
 65.1
 89.7
 —
 124.3
 56.1
 68.2
 —

 Benefit Costs
 69.3
 4.5
 21.4
 3.9
 51.0
 0.6
 22.2
 —

 Other Regulatory Liabilities
 184.5
 39.1
 14.2
 4.5
 201.9
 30.4
 13.9
 4.6

 Total Regulatory Liabilities
 4,664.9
 1,520.0
 2,079.4
 516.1
 4,614.7
 1,418.1
 1,953.4
 511.1

 Less: Current Portion
 632.3
 124.1
 436.3
 121.1
 591.8
 102.2
 368.1
 117.5

 Total Long-Term Regulatory Liabilities
 $
 4,032.6
 $
 1,395.9
 $
 1,643.1
 $
 395.0
 $
 4,022.9
 $
 1,315.9
 $
 1,585.3
 $
 393.6

 As of December 31, 2024, the Regulatory Liabilities attributable to the Aquarion water distribution business have been reclassified to Liabilities Held for Sale on the Eversource balance sheet. As of December 31, 2023, these balances were recorded within Regulatory Liabilities on the Eversource balance sheet. For further information, see Note 24, "Assets Held for Sale."

 EDIT due to Tax Cuts and Jobs Act of 2017: Pursuant to the Tax Cuts and Jobs Act of 2017, Eversource had remeasured its existing deferred federal income tax balances to reflect the decrease in the U.S. federal corporate income tax rate from 35 percent to 21 percent. The remeasurement resulted in provisional regulated excess accumulated deferred income tax (excess ADIT or EDIT) liabilities that will benefit customers in future periods and were recognized as regulatory liabilities on the balance sheet. EDIT liabilities related to property, plant, and equipment are subject to IRS normalization rules and will be returned to customers using the same timing as the remaining useful lives of the underlying assets that gave rise to the ADIT liabilities. Eversource's regulated companies are in the process of refunding the EDIT liabilities to customers based on orders issued by applicable state and federal regulatory commissions.

 Cost of Removal: Eversource's regulated companies currently recover amounts in rates for future costs of removal of plant assets over the lives of the assets. The estimated cost to remove utility assets from service is recognized as a component of depreciation expense, and the cumulative amount collected from customers but not yet expended is recognized as a regulatory liability. Expended removal costs that exceed amounts collected from customers are recognized as regulatory assets, as they are probable of recovery in future rates.

 Deferred Portion of Non-Service Income Components of Pension, SERP and PBOP: Regulatory liabilities were recorded for the deferred portion of the non-service related components of net periodic benefit expense/(income) for the Pension, SERP and PBOP Plans. These regulatory liabilities will be amortized over the remaining useful lives of the various classes of utility property, plant and equipment.

 AFUDC - Transmission: Regulatory liabilities were recorded by CL&P and NSTAR Electric for AFUDC accrued on certain reliability-related transmission projects to reflect local rate base recovery. These regulatory liabilities will be amortized over the depreciable life of the related transmission assets.

 Other Regulatory Liabilities: Other Regulatory Liabilities primarily include EGMA's acquired regulatory liability as a result of the 2020 DPU-approved rate settlement agreement and the CMA asset acquisition on October 9, 2020, and various other items.

 FERC ROE Complaints: As of December 31, 2024 and 2023, Eversource has a reserve established for the second ROE complaint period in the pending FERC ROE complaint proceedings, which was recorded as a regulatory liability and is reflected within Regulatory Tracking Mechanisms in the table above. The cumulative pre-tax reserve (excluding interest) as of December 31, 2024 and 2023 totaled $ 39.1 million for Eversource (including $ 21.4 million for CL&P, $ 14.6 million for NSTAR Electric and $ 3.1 million for PSNH). See Note 13E, "Commitments and Contingencies – FERC ROE Complaints," for further information on developments in the pending ROE complaint proceedings.

 Regulatory Developments:

 CL&P RAM Filing: On April 17, 2024, PURA issued an interim decision in CL&P's RAM filing and approved rates for six RAM components, with rates effective July 1, 2024 through April 30, 2025. The rate approvals include the recovery of NBFMCC and SBC net underrecoveries as of December 31, 2023 of $ 264.9 million and $ 86.2 million, respectively, and the recovery of expected net costs of $ 388.5 million for the NBFMCC and $ 254.4 million for the SBC for the period July 1, 2024 through April 30, 2025. The NBFMCC rate adjustment is primarily driven by long-term nuclear power purchase agreements required by state policy (Millstone and Seabrook) and the SBC rate adjustment is primarily driven by costs associated with accounts receivable hardship customer protection and the new low-income discount rate effective December 2023. On August 14, 2024, PURA issued a final decision that approved a further adjustment to the NBFMCC rate to include the recovery of incurred and deferred electric vehicle program costs from 2021 through May 31, 2024 of $ 44.4 million and expected electric vehicle program costs from June 1, 2024 through December 31, 2024 of $ 24.3 million. The $ 44.4 million, plus $ 5.4 million in carrying costs, will be recovered over a 20-month period of September 1, 2024 through April 30, 2026, and the $ 24.3 million will be recovered over an eight-month period of September 1, 2024 through April 30, 2025. In addition, PURA approved an incremental $ 3.5 million of 2024 Innovative Energy Solutions program costs and

 $ 1.5 million of Connecticut Green Bank program costs over an eight-month period of September 1, 2024 through April 30, 2025. These amounts are included in the "Public Benefits" portion of the customer bills in Connecticut.

 Yankee Gas Distribution Rate Case: On November 12, 2024, Yankee Gas filed an application with PURA to amend its existing distribution rates for effect on November 1, 2025. Yankee Gas's rate application requested approval of a distribution rate increase of $ 209 million, which included a base distribution rate increase of $ 274 million partially offset by a reduction of $ 65 million in the combined Gas System Improvements and System Expansion Reconciliation rates. In addition, Yankee Gas requested approval to implement a rate credit of $ 37.4 million to offset the PGA rate for non-firm margin credits over one year beginning November 1, 2025. As part of the rate case, Yankee Gas proposed to implement a multi-year performance-based rate making plan with a four-year initial term from November 1, 2025 to October 31, 2029 that would adjust rates annually and includes performance metrics. A final decision by PURA is expected in October 2025.

 NSTAR Electric Distribution Rates: NSTAR Electric's performance based regulation (PBR) mechanism allows for an annual adjustment to base distribution rates for inflation, exogenous events and future capital additions based on a historical five-year average of total capital additions. On September 16, 2024, NSTAR Electric submitted its annual PBR Adjustment filing for a $ 55.8 million increase to base distribution rates, for effect on January 1, 2025. The requested base distribution rate increase is comprised of a $ 35.3 million inflation-based adjustment and a $ 20.5 million adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement. On December 23, 2024, the DPU approved this filing.

 NSTAR Electric submitted its first annual PBR Adjustment filing on September 15, 2023 and on December 26, 2023, the DPU approved a $ 104.9 million increase to base distribution rates effective January 1, 2024. The base distribution rate increase was comprised of a $ 50.6 million inflation-based adjustment and a $ 54.3 million adjustment for capital additions based on the difference between the historical five-year average of total capital additions and the base capital revenue requirement.

 NSTAR Gas Distribution Rates: NSTAR Gas' PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. On September 16, 2024, NSTAR Gas submitted its annual PBR Adjustment filing for a $ 12.7 million increase to base distribution rates for effect on November 1, 2024. On October 30, 2024, the DPU approved this filing.

 NSTAR Gas submitted its third annual PBR Adjustment filing on September 15, 2023 and on October 30, 2023, the DPU approved a $ 25.4 million increase to base distribution rates, of which, $ 15.5 million was associated with a base rate adjustment and the remainder for a prior period exogenous cost adjustment, for effect on November 1, 2023.

 EGMA Distribution Rates: On November 4, 2024, EGMA submitted a revised filing for its first rate base reset for rates to be effective November 1, 2024, in accordance with an October 7, 2020 EGMA Rate Settlement Agreement approved by the DPU. The compliance filing was ordered by the DPU on October 31, 2024. The rate base reset occurring on November 1, 2024 adjusted distribution rates to account for capital additions (including the roll-in of GSEP capital additions), depreciation expense, property taxes, and return on rate base for capital additions placed into service through December 31, 2023. The total revenue requirement calculated for the first rate base reset is an increase to base distribution rates of $ 147.8 million, of which $ 34.0 million is associated with GSEP investments through December 31, 2023. Under the terms of the Rate Settlement Agreement, EGMA applied a cap on the revenue change effective November 1, 2024, and the amount in excess of the cap will be deferred for recovery through the Local Distribution Adjustment Clause (LDAC) on May 1, 2025, including carrying charges. After adjusting for the cap, the increase to base distribution rates is $ 85.6 million effective November 1, 2024 (of which $ 8.8 million is offset by a reduction in the GSEP revenue requirement and GSEP rate also taking effect on November 1, 2024 for a net distribution rate change on November 1, 2024 of $ 76.8 million). Base distribution rates will be increased effective November 1, 2025 to incorporate the $ 62.2 million remaining revenue requirement. On November 7, 2024, the DPU approved this filing.

 PSNH Distribution Rate Case: On June 11, 2024, PSNH filed an application with the NHPUC for approval of a temporary annual base distribution rate increase. On July 31, 2024, the NHPUC approved a settlement agreement that was reached by PSNH, New Hampshire Department of Energy, and the Office of the Consumer Advocate to implement a temporary annual base distribution rate increase of $ 61.2 million effective August 1, 2024.

 Also on June 11, 2024, PSNH filed an application with the NHPUC to request an increase in permanent base distribution rates of $ 181.9 million, which is inclusive of the temporary rate increase, and proposed to take effect August 1, 2025. The temporary rates are subject to reconciliation based on the outcome of the permanent rate case back to the date when temporary rates took effect. The permanent rate increase request includes $ 247 million in unrecovered storm costs to be recovered over a five-year period. As part of the rate case, PSNH proposed to implement a performance-based rate making plan that would adjust rates annually over a four-year term, with a commitment to not file another rate case for at least four years. The plan includes a revenue-cap formula adjusted for inflation, a supplemental capital adjustment formula to support PSNH's planned capital infrastructure improvements, an exogenous events recovery mechanism, performance metrics and an earnings sharing mechanism, among others. If the NHPUC approves the performance-based rate making plan as proposed, the previously established RRA and PPAM rate reconciling mechanisms and lost base revenues will be eliminated. The NHPUC is permitted up to twelve months to investigate the proposed rates and issue a final order. A decision by the NHPUC on permanent rates is expected by August 1, 2025.

 2023 PSNH Pole Acquisition Approval: On November 18, 2022, the NHPUC issued a decision that approved a proposed purchase agreement between PSNH and Consolidated Communications, in which, PSNH would acquire both jointly-owned and solely-owned poles and pole assets. The NHPUC also authorized PSNH to recover certain expenses associated with the operation and maintenance of the transferred poles, pole inspections, and vegetation management expenses through a new cost recovery mechanism, the Pole Plant Adjustment Mechanism (PPAM), subject to consummation of the purchase agreement. The purchase agreement was finalized on May 1, 2023 for a purchase price of $ 23.3 million. Upon consummation of the purchase agreement, PSNH established a regulatory asset of $ 16.9 million for operation and maintenance expenses and vegetation management expenses associated with the purchased poles incurred from February 10, 2021 through April 30, 2023 that PSNH is authorized to collect through the PPAM regulatory tracking mechanism. The establishment of the PPAM regulatory asset resulted in a pre-tax benefit recorded in Amortization expense on the PSNH statement of income in 2023.

 3. PROPERTY, PLANT AND EQUIPMENT AND ACCUMULATED DEPRECIATION

 Utility property, plant and equipment is recorded at original cost. Original cost includes materials, labor, construction overheads and AFUDC for regulated property. The cost of repairs and maintenance is charged to Operations and Maintenance expense as incurred.

 The following tables summarize property, plant and equipment by asset category:

 2024
 2023

 Distribution - Electric
 $
 21,144.1
 $
 19,656.5

 Distribution - Natural Gas
 8,922.2
 8,155.3

 Transmission - Electric
 16,130.9
 14,666.8

 Distribution - Water (1)

 —
 2,280.1

 Solar
 201.0
 201.1

 Utility
 46,398.2
 44,959.8

 Other (2)

 2,254.1
 2,006.8

 Property, Plant and Equipment, Gross
 48,652.3
 46,966.6

 Less: Accumulated Depreciation

 Utility
 ( 9,636.5)
 ( 9,670.1)

 Other
 ( 1,044.1)
 ( 869.6)

 Total Accumulated Depreciation
 ( 10,680.6)
 ( 10,539.7)

 37,971.7
 36,426.9

 Construction Work in Progress
 3,014.9
 3,071.7

 Total Property, Plant and Equipment, Net
 $
 40,986.6
 $
 39,498.6

 2024
 2023

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Distribution - Electric
 $
 8,437.9
 $
 9,782.3
 $
 2,964.2
 $
 7,897.1
 $
 9,000.5
 $
 2,799.2

 Transmission - Electric
 6,937.7
 6,375.2
 2,819.6
 6,548.2
 5,630.8
 2,489.5

 Solar
 —
 201.0
 —
 —
 201.1
 —

 Property, Plant and Equipment, Gross
 15,375.6
 16,358.5
 5,783.8
 14,445.3
 14,832.4
 5,288.7

 Less: Accumulated Depreciation
 ( 2,928.0)
 ( 3,782.0)
 ( 1,032.3)
 ( 2,670.5)
 ( 3,585.9)
 ( 984.0)

 12,447.6
 12,576.5
 4,751.5
 11,774.8
 11,246.5
 4,304.7

 Construction Work in Progress
 554.6
 1,461.3
 338.4
 565.4
 1,507.3
 270.0

 Total Property, Plant and Equipment, Net
 $
 13,002.2
 $
 14,037.8
 $
 5,089.9
 $
 12,340.2
 $
 12,753.8
 $
 4,574.7

 (1)As of December 31, 2024, the property, plant and equipment balance, net of accumulated depreciation, attributable to the Aquarion water distribution business has been reclassified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2023, this balance was recorded within Property, Plant and Equipment, Net on the Eversource balance sheet. For further information, see Note 24, "Assets Held for Sale."

 (2)These assets are primarily comprised of computer software, hardware and equipment at Eversource Service and buildings at The Rocky River Realty Company.

 Depreciation: Depreciation of utility assets is calculated on a straight-line basis using composite rates based on the estimated remaining useful lives of the various classes of property (estimated useful life for PSNH distribution and the water utilities). The composite rates, which are subject to approval by the appropriate state regulatory agency, include a cost of removal component, which is collected from customers over the lives of the plant assets and is recognized as a regulatory liability. Depreciation rates are applied to property from the time it is placed in service.

 Upon retirement from service, the cost of the utility asset is charged to the accumulated provision for depreciation. The actual incurred removal costs are applied against the related regulatory liability.

 The depreciation rates for the various classes of utility property, plant and equipment aggregate to composite rates as follows:

 (Percent)
 2024
 2023
 2022

 3.2
 %
 3.1
 %
 3.0
 %

 CL&P
 2.9
 %
 2.8
 %
 2.8
 %

 2.8
 %
 2.7
 %
 2.7
 %

 PSNH
 3.0
 %
 3.0
 %
 3.0
 %

 The following table summarizes average remaining useful lives of depreciable assets:

 As of December 31, 2024

 (Years)
 CL&P
 PSNH

 Distribution - Electric
 33.4
 34.7
 33.4
 29.9

 Distribution - Natural Gas
 34.7
 —
 —
 —

 Transmission - Electric
 39.7
 35.8
 45.1
 39.8

 Distribution - Water
 45.2
 —
 —
 —

 Solar
 22.8
 —
 22.8
 —

 Other (1)

 9.9
 —
 —
 —

 (1)The estimated useful life of computer software, hardware and equipment primarily ranges from 5 to 15 years and of buildings is 40 years.

 4. DERIVATIVE INSTRUMENTS

 The electric and natural gas companies purchase and procure energy and energy-related products, which are subject to price volatility, for their customers. The costs associated with supplying energy to customers are recoverable from customers in future rates. These regulated companies manage the risks associated with the price volatility of energy and energy-related products through the use of derivative and non-derivative contracts. Many of the derivative contracts meet the definition of, and are designated as, normal and qualify for accrual accounting under the applicable accounting guidance. The costs and benefits of derivative contracts that meet the definition of normal are recognized in Operating Expenses on the statements of income as electricity or natural gas is delivered.

 Derivative contracts that are not designated as normal are recorded at fair value as derivative assets or liabilities on the balance sheets. For the electric and natural gas companies, regulatory assets or regulatory liabilities are recorded to offset the fair values of derivatives, as contract settlement amounts are recovered from, or refunded to, customers in their respective energy supply rates.

 The gross fair values of derivative assets and liabilities with the same counterparty are offset and reported as net Derivative Assets or Derivative Liabilities, with current and long-term portions, on the balance sheets. The following table presents the gross fair values of contracts, categorized by risk type, and the net amounts recorded as current or long-term derivative assets or liabilities:

 2024
 2023

 CL&P

 Fair Value Hierarchy
 Commodity Supply
and Price Risk
Management
 Netting (1)

 Net Amount
Recorded as
a Derivative
 Commodity Supply
and Price Risk
Management
 Netting (1)

 Net Amount
Recorded as
a Derivative

 Current Derivative Assets
 $
 14.2
 $
 $
 13.9
 $
 16.4
 $
 $
 15.9

 Long-Term Derivative Assets
 —
 —
 —
 13.6
 13.1

 Current Derivative Liabilities
 ( 71.1)
 —
 ( 71.1)
 ( 81.9)
 —
 ( 81.9)

 Long-Term Derivative Liabilities
 —
 —
 —
 ( 68.0)
 —
 ( 68.0)

 (1) Amounts represent derivative assets and liabilities that Eversource elected to record net on the balance sheets. These amounts are subject to master netting agreements or similar agreements for which the right of offset exists.

 The business activities that result in the recognition of derivative assets also create exposure to various counterparties. As of December 31, 2024, CL&P's derivative assets were exposed to counterparty credit risk and contracted with investment grade entities.

 Derivative Contracts at Fair Value with Offsetting Regulatory Amounts
 Commodity Supply and Price Risk Management: As required by regulation, CL&P, along with UI, has capacity-related contracts with generation facilities. CL&P has a sharing agreement with UI, with 80 percent of the costs or benefits of each contract borne by or allocated to CL&P and 20 percent borne by or allocated to UI. The combined capacities of these contracts as of December 31, 2024 and 2023 were 610 MW and 682 MW, respectively. The capacity contracts extend through 2026 and obligate both CL&P and UI to make or receive payments on a monthly basis to or from the generation facilities based on the difference between a set capacity price and the capacity market price received in the ISO-NE capacity markets.

 For the years ended December 31, 2024, 2023 and 2022, there were losses of $ 3.8 million, losses of $ 3.9 million and gains of $ 10.1 million, respectively. These changes in fair value associated with CL&P's derivative contracts are deferred in Regulatory Assets on the balance sheet.

 Fair Value Measurements of Derivative Instruments
 The fair value of derivative contracts utilizes both observable and unobservable inputs. The fair value is modeled using income techniques, such as discounted cash flow valuations adjusted for assumptions related to exit price. Valuations of derivative contracts using a discounted cash flow methodology include assumptions regarding the timing and likelihood of scheduled capacity payments and also reflect non-performance risk, including credit, using the default probability approach based on the counterparty's credit rating for assets and the Company's credit rating for liabilities. Significant observable inputs for valuations of these contracts include energy-related product prices in future years for which quoted prices in an active market exist. Valuations incorporate estimates of premiums or discounts that would be required by a market participant to arrive at an exit price, using historical market transactions adjusted for the terms of the contract. Fair value measurements were prepared by individuals with expertise in valuation techniques, pricing of energy-related products, and accounting requirements. All derivative contracts were classified as Level 2 in the fair value hierarchy as of both December 31, 2024 and 2023.

 The following table presents changes in the Level 3 category of derivative assets and derivative liabilities measured at fair value on a recurring basis. The derivative assets and liabilities are presented on a net basis.

 CL&P

 For the Year Ended

 December 31, 2023

 Derivatives, Net:

 Fair Value as of Beginning of Period
 $
 ( 181.8)

 Net Realized/Unrealized Losses Included in Regulatory Assets
 ( 3.9)

 Settlements
 64.8

 Transfers out of Level 3 (1)

 120.9

 Fair Value as of End of Period
 $
 —

 (1) Transfers out of Level 3 pertain to certain significant valuation inputs becoming observable as well as certain unobservable inputs no longer being significant to the fair value of the derivative contracts. Eversource's policy is to recognize transfers between levels of the fair value hierarchy as of the end of the reporting period.

 5. MARKETABLE SECURITIES

 Eversource's marketable securities include the CYAPC and YAEC legally restricted trusts that each hold equity and available-for-sale debt securities to fund the spent nuclear fuel removal obligations of their nuclear fuel storage facilities. Eversource also holds trusts that are not subject to regulatory oversight by state or federal agencies that are primarily used to fund certain non-qualified executive benefits. The marketable securities within the non-qualified executive benefit trusts were sold in 2023. Equity and available-for-sale debt marketable securities are recorded at fair value, with the current portion recorded in Prepayments and Other Current Assets and the long-term portion recorded in Marketable Securities on the balance sheets. CYAPC and YAEC's spent nuclear fuel trusts are restricted and are classified in long-term Marketable Securities on the balance sheets.

 Equity Securities: Eversource's equity securities include CYAPC's and YAEC's marketable securities held in spent nuclear fuel trusts, which had fair values of $ 163.1 million and $ 173.6 million as of December 31, 2024 and 2023, respectively. Unrealized gains and losses for these spent nuclear fuel trusts are subject to regulatory accounting treatment and are recorded in Marketable Securities with the corresponding offset to long-term liabilities on the balance sheets, with no impact on the statements of income.

 Unrealized gains and losses on equity securities held in other trusts are recorded in Other Income, Net on the statements of income. The equity securities within Eversource's non-qualified executive benefits trusts were sold during 2023 and resulted in a $ 1.1 million gain recorded in Other Income, Net for the year ended December 31, 2023. The remaining equity securities held in Eversource's trusts as of December 31, 2024 of $ 4.1 million were reclassified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2023, these equity securities totaled $ 3.3 million and there were unrealized gains of $ 0.6 million recorded in Other Income, Net in 2023. For further information, see Note 24, "Assets Held for Sale."

 Available-for-Sale Debt Securities: The following is a summary of available-for-sale debt securities, which are held in CYAPC's and YAEC's spent nuclear fuel trusts:

 2024
 2023

 Amortized
Cost
 Pre-Tax
Gains
 Pre-Tax
Losses
 Fair Value
 Amortized
Cost
 Pre-Tax
Gains
 Pre-Tax
Losses
 Fair Value

 Debt Securities
 $
 163.2
 $
 0.1
 $
 ( 6.1)
 $
 157.2
 $
 169.5
 $
 1.4
 $
 ( 6.6)
 $
 164.3

 Unrealized gains and losses for available-for-sale debt securities included in the CYAPC and YAEC spent nuclear fuel trusts are subject to regulatory accounting treatment and are recorded in Marketable Securities with the corresponding offset to long-term liabilities on the balance sheets, with no impact on the statements of income.

 Any unrealized gains and losses on available-for-sale debt securities held in other trusts are recorded in Accumulated Other Comprehensive Income, excluding amounts related to credit losses or losses on securities intended to be sold, which are recorded in Other Income, Net. The debt securities within Eversource's non-qualified executive benefits trusts were sold during 2023. There were $ 1.2 million of realized losses recorded on securities sold for the year ended December 31, 2023 that were reclassified out of Accumulated Other Comprehensive Income and recorded in Other Income, Net. There were no credit losses for the years ended December 31, 2024 and 2023, and no allowance for credit losses as of December 31, 2024. Factors considered in determining whether a credit loss exists include adverse conditions specifically affecting the issuer, the payment history, ratings and rating changes of the security, and the severity of the impairment. For asset-backed debt securities, underlying collateral and expected future cash flows are also evaluated.

 As of December 31, 2024, the contractual maturities of available-for-sale debt securities were as follows:

 Amortized
Cost
 Fair
Value

 Less than one year
 $
 11.3
 $
 11.7

 One to five years
 35.6
 35.6

 Six to ten years
 43.5
 42.6

 Greater than ten years
 72.8
 67.3

 Total Debt Securities
 $
 163.2
 $
 157.2

 Realized Gains and Losses: Realized gains and losses are offset in long-term liabilities for CYAPC and YAEC and are recorded in Other Income, Net for Eversource's benefit trusts. Eversource utilizes the average cost basis method for the CYAPC and YAEC spent nuclear fuel trusts and the specific identification basis method for the Eversource non-qualified benefit trusts to compute the realized gains and losses on the sale of marketable securities.

 Fair Value Measurements: The following table presents the marketable securities recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

 2024
 2023

 Level 1:

 Mutual Funds and Equities
 $
 163.1
 $
 176.9

 Money Market Funds
 10.0
 13.7

 Total Level 1
 $
 173.1
 $
 190.6

 Level 2:

 U.S. Government Issued Debt Securities (Agency and Treasury)
 $
 92.0
 $
 90.1

 Corporate Debt Securities
 32.5
 34.0

 Asset-Backed Debt Securities
 7.8
 5.6

 Municipal Bonds
 6.8
 9.8

 Other Fixed Income Securities
 8.1
 11.1

 Total Level 2
 $
 147.2
 $
 150.6

 Total Marketable Securities
 $
 320.3
 $
 341.2

 U.S. government issued debt securities are valued using market approaches that incorporate transactions for the same or similar bonds and adjustments for yields and maturity dates. Corporate debt securities are valued using a market approach, utilizing recent trades of the same or similar instruments and also incorporating yield curves, credit spreads and specific bond terms and conditions. Asset-backed debt securities include collateralized mortgage obligations, commercial mortgage backed securities, and securities collateralized by auto loans, credit card loans or receivables. Asset-backed debt securities are valued using recent trades of similar instruments, prepayment assumptions, yield curves, issuance and maturity dates, and tranche information. Municipal bonds are valued using a market approach that incorporates reported trades and benchmark yields. Other fixed income securities are valued using pricing models, quoted prices of securities with similar characteristics, and discounted cash flows.

 6. INVESTMENTS IN UNCONSOLIDATED AFFILIATES

 Investments in entities that are not consolidated are included in long-term assets on the balance sheets. Investments in affiliates where Eversource has the ability to exercise significant influence, but not control, over an investee are initially recognized as an equity method investment at cost. Earnings impacts from these equity investments are included in Other Income, Net on the statements of income. Eversource's investments accounted for under the equity method include the following:

 Investment Balance as of December 31,

 Ownership Interest
 2024
 2023

 Offshore Wind Business
 50 %
 -
 100 %
 $
 22.2
 $
 515.5

 Natural Gas Pipeline - Algonquin Gas Transmission, LLC
 15 %
 112.6
 116.0

 Other
 various
 33.9
 29.0

 Total Investments in Unconsolidated Affiliates
 $
 168.7
 $
 660.5

 For the years ended December 31, 2024, 2023 and 2022, Eversource had equity in earnings of unconsolidated affiliates of $ 51.9 million, $ 15.5 million, and $ 22.9 million, respectively. Eversource received dividends from its equity method investees (excluding proceeds received from sale or liquidation of investments) of $ 20.5 million, $ 20.1 million, and $ 26.2 million, respectively, for the years ended December 31, 2024, 2023 and 2022.

 Offshore Wind Business: Eversource's previous offshore wind business included 50 percent ownership interests in each of North East Offshore and South Fork Class B Member, LLC. During 2024, Eversource sold its interest in these entities, and in doing so, sold its interests in the Revolution Wind project, the South Fork Wind project, and the Sunrise Wind project. Eversource's current offshore wind business is now comprised only of a noncontrolling tax equity investment in South Fork Wind through a 100 percent ownership in South Fork Wind Holdings, LLC Class A interests.

 On May 25, 2023, Eversource announced that it had completed a strategic review of its offshore wind investments and determined that it would pursue the sale of its offshore wind investments. On September 7, 2023, Eversource completed the sale of its 50 percent interest in an uncommitted lease area consisting of approximately 175,000 developable acres located 25 miles off the south coast of Massachusetts to rsted for $ 625 million in an all-cash transaction.

 In September of 2023, Eversource made a $ 528 million investment in a tax equity interest for South Fork Wind. South Fork Wind was restructured as a tax equity investment, with Eversource purchasing 100 percent ownership of a new Class A tax equity membership interest. This investment will result in Eversource receiving cash flow benefits from investment tax credits (ITC) and other future cash flow benefits as well. As of December 31, 2024, $ 459 million of expected investment tax credits and other expected tax benefits were reclassified from the South Fork Wind tax equity investment balance reported in Investments in Unconsolidated Affiliates as a decrease in Accumulated Deferred Income Taxes on the Eversource balance sheet, which represented a non-cash reclassification. As a result of these investment tax credits, Eversource expects lower federal income tax payments from 2025 to 2027. As of December 31, 2024, the tax equity interest in South Fork Wind totaled $ 22.2 million.

 On January 24, 2024, Eversource entered into an agreement with rsted to sell Eversource's 50 percent share of Sunrise Wind, subject to certain conditions and regulatory approvals. On April 18, 2024, Eversource and rsted executed an equity and asset purchase agreement and on July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to rsted. In accordance with the equity and asset purchase agreement and after adjustment for a reduction in capital spending compared to forecasted amounts, adjusted proceeds totaled $ 152 million. rsted paid Eversource $ 118 million at the closing of the sale transaction, which was used to repay parent company debt. Remaining proceeds of $ 34 million will be paid after onshore construction is completed and certain other construction milestones are achieved. The remaining expected proceeds have been recorded in Other Long-Term Assets on Eversource's balance sheet as of December 31, 2024. Eversource recorded a pre-tax gain on the sale of Sunrise Wind of $ 377 million in 2024. With completion of the sale, Eversource does not have any ongoing financial obligations associated with Sunrise Wind.

 On February 13, 2024, Eversource executed an agreement to sell its 50 percent interests in the South Fork Wind and Revolution Wind projects to Global Infrastructure Partners (GIP) for an initial gross purchase price of approximately $ 1.1 billion. The initial purchase price was subject to adjustment based on, among other things, the progress, timing and the construction cost of Revolution Wind, including changes in actual versus forecasted capital spending between signing the agreement and closing of the transaction. On September 30, 2024, Eversource completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to GIP for adjusted gross proceeds of $ 745 million, which were received at closing. Adjusted gross proceeds from the sale were approximately $ 375 million lower than the previously estimated purchase price. This reduction reflects approximately $ 150 million resulting from lower capital spending between signing the agreement and closing, and approximately $ 225 million related to the final terms of the sale transaction, primarily due to the delay of the commercial operations date of Revolution Wind. Proceeds from the transaction were used to repay parent company debt.

 As part of the Revolution Wind and South Fork Wind sale, Eversource and GIP agreed to make certain post-closing purchase price adjustment payments, which could further impact the final purchase price. The post-closing purchase price adjustment payments include cost sharing obligations that require Eversource to share equally with GIP in GIP's funding obligations up to an effective cap of approximately $ 240 million of incremental capital expenditure overruns incurred during the construction phase for Revolution Wind, after which Eversource will have responsibility for GIP's obligations for any additional capital expenditure overruns in excess of this amount. The purchase price is also subject to post-closing adjustments as a result of final project economics, which includes Eversource's obligation to maintain GIP's internal rate of return through the construction period for each project as specified in the agreement. Post-closing purchase price adjustment payments will be made following the commercial operation date of Revolution Wind. South Fork Wind has achieved commercial operation, and Eversource is in the process of finalizing the construction cost post-close purchase price adjustment payment related to this project, which is not expected to be material.

 Upon the completion of both sale transactions in 2024, the total proceeds were compared to the carrying value of the investments, including an estimate of liability for post-closing adjustment payments to GIP, and Eversource recognized an aggregate, net after-tax loss on the sales of its offshore wind investments of $ 524 million. The aggregate, net after-tax loss is comprised of (1) the lower proceeds related to final terms of the sale transaction to GIP of approximately $ 225 million related to non-construction costs for the Revolution Wind and South Fork Wind projects, primarily due to a purchase price reduction of $ 150 million resulting from the delay of the commercial operations date of Revolution Wind, (2) recently identified forecasted construction costs as a result of a delay in the anticipated commercial operation date related to Revolution Wind of approximately $ 350 million, which includes an estimate for the anticipated post-closing adjustment to GIP related to Eversource's expected cost overrun sharing obligation, and (3) approximately $ 326 million, which includes an estimate for the anticipated post-closing adjustment related to Eversource's expected obligations to GIP as a result of final economics of the Revolution Wind and South Fork Wind projects and other future

 costs, as well as a net $ 60 million increase in income tax expense including an increase in the valuation allowance for unused capital losses. These losses were partially offset by the $ 377 million gain on the sale of Sunrise Wind.

 Upon sale, Eversource recorded a contingent liability of $ 365 million, reflecting its estimate of the future obligations under the GIP sale terms, which include the expected cost overrun sharing obligation, expected obligation to maintain GIP's internal rate of return, and obligation for other future costs. The majority of this liability is expected to be settled upon the completion of the Revolution Wind project. The long-term portion of the liability of $ 350 million is recorded in Other Long-Term Liabilities, and $ 15 million is recorded in Other Current Liabilities on Eversource's balance sheet as of December 31, 2024.

 Contingencies are evaluated using the best information available at the time the financial statements are prepared, and this assessment involves judgments and assumptions about future events. Factors that could increase the post-closing adjustment payments owed to GIP include the ultimate cost of construction and extent of cost overruns for Revolution Wind, delays in construction, which would impact the economics associated with the purchase price adjustment, and Revolution Wind's eligibility for federal investment tax credits at a lower value than assumed and included in the purchase price.

 The purchase price included the sales value related to a 40 percent level of federal investment tax credits, 10 percent of which is the energy community investment tax credit (ITC) adder included in the Inflation Reduction Act of approximately $ 170 million related to Revolution Wind. Although management believes the ITC adder value is realizable, there is some uncertainty at this time as to whether those ITC adders can be achieved, and management continues to evaluate the project's qualifications and to monitor guidance issued by the United States Treasury Department. A change in the expected value or qualification of ITC adders could result in a significant loss in a future period.

 New information or future developments that arise as construction progresses and as cost estimates are reviewed and revised will require a reassessment of the estimated liability for the post-closing adjustment payments. The Company is currently aware that construction of the offshore foundations, offshore substation and turbine tower installations could result in increased cost overruns in the future. Only preliminary construction cost projections are available for these cost overruns, and there is insufficient updated information at this point in order for Eversource to change its estimate with reasonably estimable information. Eversource will continue to assess the potential exposure and adjust the liability as needed. It is expected that updated costs estimates will become available in the first half of 2025, and adverse changes in facts and circumstances could result in additional losses that could be material. The Company believes it is reasonably possible that there is an additional loss in excess of the liability recorded, but management cannot reasonably estimate a range of loss beyond the $ 365 million recorded at this time.

 Total net proceeds could also be adjusted for a benefit due to Eversource if there are lower operation costs or higher availability of the projects through the period that is four years following the commercial operation of Revolution Wind.

 Under the agreement with GIP, Eversource's existing and certain additional credit support obligations for Revolution Wind are expected to roll off as the project completes construction. Under the agreement with rsted, Eversource's existing credit support obligations for Sunrise Wind were either terminated or indemnified by rsted as a result of the sale. Eversource has entered into separate construction management agreements to manage Sunrise Wind's and Revolution Wind's onshore electric substation construction through completion. In this role, Eversource will be solely a service provider to Sunrise Wind and Revolution Wind.

 2023 Impairments: Equity method investments are assessed for impairment when conditions exist as of the balance sheet date that indicate that the fair value of the investment may be less than book value. Eversource continually monitors and evaluates its equity method investments to determine if there are indicators of an other-than-temporary impairment. If the decline in value is considered to be other-than-temporary, the investment is written down to its estimated fair value, which establishes a new cost basis in the investment. Impairment evaluations are based on best information available at the impairment assessment date. Subsequent declines or recoveries after the reporting date are not considered in the impairment recognized. Investments that are other-than-temporarily impaired and written down to their estimated fair value cannot subsequently be written back up for increases in estimated fair value. Impairment evaluations involve a significant degree of judgment and estimation, including identifying circumstances that indicate an impairment may exist at the equity method investment level, selecting discount rates used to determine fair values, and developing an estimate of discounted future cash flows expected from investment operations or the sale of the investment.

 During 2023, in connection with the process to divest its offshore wind business, Eversource identified indicators for impairment in both the second and fourth quarters of 2023. In each impairment assessment, Eversource evaluated its investments and determined that the carrying value of the equity method offshore wind investments exceeded the fair value of the investments and that the decline in fair value was other-than-temporary. The completion of the strategic review in the second quarter of 2023 resulted in Eversource recording a pre-tax other-than-temporary impairment charge of $ 401 million ($ 331 million after-tax) to reflect the investment at estimated fair value based on the expected sales price at that time. This established a new cost basis in the investments. Negative developments in the fourth quarter of 2023, including a lower expected sales price, additional projected construction cost increases, and the October 2023 OREC pricing denial for Sunrise Wind, resulted in Eversource conducting an impairment evaluation and recognizing an additional pre-tax other-than-temporary impairment charge of $ 1.77 billion ($ 1.62 billion after-tax) and establishing a new cost basis in the investments as of December 31, 2023. The Eversource statement of income for the year ended 2023 reflects a total pre-tax other-than-temporary impairment charge of $ 2.17 billion ($ 1.95 billion after-tax) in its offshore wind investments. The impairment charges were non-cash charges and did not impact Eversource's cash position at the time of the impairment. Eversource's offshore wind investments did not meet the criteria to qualify for presentation as a discontinued operation.

 The 2023 impairment evaluations involved judgments in developing the estimates and timing of the future cash flows arising from the expected sales price of Eversource's 50 percent interest in the wind projects, including expected sales value from investment tax credit adder amounts, less estimated costs to sell, and uncertainties related to the Sunrise Wind re-bid process in New York's offshore wind solicitation in 2024. Additional assumptions in the fourth quarter 2023 assessment included revised projected construction costs and estimated project cost overruns, management's assumption that the Sunrise Wind project would ultimately be abandoned, estimated termination costs, salvage values of Sunrise Wind assets, and the value of the tax equity ownership interest. The assumptions used in the discounted cash flow analyses were subject to inherent uncertainties and subjectivity. All significant inputs into the impairment evaluations were Level 3 fair value measurements.

 A summary of the significant estimates and assumptions included in the 2023 impairment charges is as follows:

 Second Quarter 2023

 Fourth Quarter 2023

 Total

 Lower expected sales proceeds across all three wind projects

 $
 $
 $

 Expected cost overruns not recovered in the sales price

 —

 Loss of sales value from the sale price offered by GIP, including loss of ITC adders value, cancellation costs and other impacts assuming Sunrise Wind project is abandoned

 —

 Impairment Charges, pre-tax
 1,766
 2,167

 Tax Benefit
 ( 70)
 ( 144)
 ( 214)

 Impairment Charges, after-tax
 $
 $
 1,622
 1,953

 A summary of the carrying value by investee and by project as of December 31, 2023 is as follows:

 Investments Expected to be Disposed of
 Investment to be Held

 North East Offshore
 South Fork Class B Member, LLC

 South Fork Wind Holdings, LLC Class A

 Total Offshore Wind Investments

 Sunrise Wind
 Revolution Wind

 Carrying Value as of December 31, 2023, before
 Impairment Charge
 $
 $
 $
 $
 $
 2,282

 Fourth Quarter 2023 Impairment Charge
 ( 1,218)
 ( 544)
 —
 ( 4)
 ( 1,766)

 Carrying Value as of December 31, 2023
 $
 ( 519)
 $
 $
 $
 $

 During 2024, Eversource sold its interest in the North East Offshore and South Fork Class B, Member LLC equity method investments and recognized an aggregate, net after-tax loss on the sale of its offshore wind investments of $ 524 million.

 Capital contributions in the offshore wind investments, including the 2023 contribution for the tax equity investment in South Fork Wind, were included in Investments in Unconsolidated Affiliates on the statements of cash flows. Proceeds received from the sale of the investments in 2024, and proceeds received from the 2023 sale of the unused lease area and from an October 2023 distribution of $ 318 million received primarily as a result of being a 50 percent joint owner in the Class B shares of South Fork Wind which was restructured as a tax equity investment, were included in Proceeds from Unconsolidated Affiliates on the statements of cash flows.

 Liquidation of Renewable Energy Investment Fund: On March 21, 2023, Eversource's equity method investment in a renewable energy investment fund was liquidated by the fund's general partner in accordance with the partnership agreement. Proceeds received from the liquidation totaled $ 147.6 million and were included in Proceeds from Unconsolidated Affiliates on the statement of cash flows for the year ended December 31, 2023. A portion of the proceeds was used to make a charitable contribution to the Eversource Energy Foundation (a related party) of $ 20.0 million in 2023. The liquidation benefit received in excess of the investment's carrying value and the charitable contribution were included in Other Income, Net on the statement of income.

 NSTAR Electric: As of December 31, 2024 and 2023, NSTAR Electric's investments included a 14.5 percent ownership interest in two companies that transmit hydro-electricity imported from the Hydro-Quebec system in Canada of $ 11.5 million and $ 9.6 million, respectively.

 7. ASSET RETIREMENT OBLIGATIONS

 Eversource, including CL&P, NSTAR Electric and PSNH, recognizes a liability for the fair value of an ARO on the obligation date if the liability's fair value can be reasonably estimated, even if it is conditional on a future event. Settlement dates and future costs are reasonably estimated when sufficient information becomes available. Management has identified various categories of AROs, primarily CYAPC's and YAEC's obligation to dispose of spent nuclear fuel and high level waste, and also certain assets containing asbestos and hazardous contamination. Management has performed fair value calculations reflecting expected probabilities for settlement scenarios.

 The fair value of an ARO is recorded as a long-term liability with a corresponding amount included in Property, Plant and Equipment, Net on the balance sheets. The ARO assets are depreciated, and the ARO liabilities are accreted over the estimated life of the obligation and the corresponding credits are recorded as accumulated depreciation and ARO liabilities, respectively. As the electric and natural gas companies are rate-regulated on a cost-of-service basis, these companies apply regulatory accounting guidance and both the depreciation and accretion costs associated with these companies' AROs are recorded as increases to Regulatory Assets on the balance sheets.

 A reconciliation of the beginning and ending carrying amounts of ARO liabilities is as follows:

 2024
 2023

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Balance as of Beginning of Year
 $
 505.8
 $
 39.9
 $
 104.8
 $
 5.2
 $
 502.7
 $
 37.4
 $
 101.3
 $
 4.9

 Liabilities Settled During the Year
 ( 24.6)
 —
 —
 —
 ( 24.9)
 —
 —
 —

 Accretion
 29.5
 2.6
 4.5
 0.4
 29.2
 2.5
 4.3
 0.3

 Revisions in Estimated Cash Flows
 80.2
 —
 —
 —
 —
 ( 0.8)
 —

 Balance as of End of Year
 $
 590.9
 $
 42.5
 $
 109.3
 $
 5.6
 $
 505.8
 $
 39.9
 $
 104.8
 $
 5.2

 Eversource's amounts include CYAPC and YAEC's AROs of $ 391.7 million and $ 315.8 million as of December 31, 2024 and 2023, respectively. The fair value of the ARO for CYAPC and YAEC includes uncertainties of the fuel off-load dates related to the DOE's timing of performance regarding its obligation to dispose of the spent nuclear fuel and high level waste and other assumptions, including discount rates. The incremental asset recorded as an offset to the ARO liability was fully depreciated since the plants have no remaining useful life. Any changes in the ARO liability are recorded with a corresponding offset to the related regulatory asset. The assets held in the CYAPC and YAEC spent nuclear fuel trusts are restricted for settling the ARO and all other nuclear fuel storage obligations. For further information on the assets held in the spent nuclear fuel trusts, see Note 5, "Marketable Securities," to the financial statements.

 The increase in the ARO balance at Eversource for the year ended December 31, 2024 was due primarily to updated cost estimates that extended the end of life date from 2039 to 2044 for CYAPC and YAEC. These updated cost estimates were approved by FERC in November 2024.

 8. SHORT-TERM DEBT

 Short-Term Debt - Borrowing Limits: The amount of short-term borrowings that may be incurred by CL&P and NSTAR Electric is subject to periodic approval by the FERC. Because the NHPUC has jurisdiction over PSNH's short-term debt, PSNH is not currently required to obtain FERC approval for its short-term borrowings. On November 30, 2023, the FERC granted authorization that allows CL&P to issue total short-term borrowings in an aggregate principal amount not to exceed $ 600 million outstanding at any one time, through December 31, 2025. On December 18, 2023, the FERC granted authorization that allows NSTAR Electric to issue total short-term borrowings in an aggregate principal amount not to exceed $ 655 million outstanding at any one time, through December 31, 2025.

 PSNH is authorized by regulation of the NHPUC to incur short-term borrowings up to 10 percent of net fixed plant plus an additional $ 60 million until further ordered by the NHPUC. As of December 31, 2024, PSNH's short-term debt authorization under the 10 percent of net fixed plant test plus $ 60 million totaled $ 526.7 million.

 CL&P's certificate of incorporation contains preferred stock provisions restricting the amount of unsecured debt that CL&P may incur, including limiting unsecured indebtedness with a maturity of less than 10 years to 10 percent of total capitalization. As of December 31, 2024, CL&P had $ 901.0 million of unsecured debt capacity available under this authorization.

 Yankee Gas, NSTAR Gas and EGMA are not required to obtain approval from any state or federal authority to incur short-term debt.

 Short-Term Debt - Commercial Paper Programs and Credit Agreements: Eversource parent has a $ 2.00 billion commercial paper program allowing Eversource parent to issue commercial paper as a form of short-term debt. Eversource parent, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut are parties to a five-year $ 2.00 billion revolving credit facility, which terminates on October 11, 2029. This revolving credit facility serves to backstop Eversource parent's $ 2.00 billion commercial paper program.

 NSTAR Electric has a $ 650 million commercial paper program allowing NSTAR Electric to issue commercial paper as a form of short-term debt. NSTAR Electric is also a party to a five-year $ 650 million revolving credit facility, which terminates on October 11, 2029, that serves to backstop NSTAR Electric's $ 650 million commercial paper program.

 The amount of borrowings outstanding and available under the commercial paper programs were as follows:

 Borrowings Outstanding
 as of December 31,
 Available Borrowing Capacity as of December 31,
 Weighted-Average Interest Rate as of December 31,

 2024
 2023
 2024
 2023
 2024
 2023

 Eversource Parent Commercial Paper Program
 $
 1,538.0
 $
 1,771.9
 $
 462.0
 $
 228.1
 4.76
 %
 5.60
 %

 NSTAR Electric Commercial Paper Program
 504.8
 365.8
 145.2
 284.2
 4.55
 %
 5.40
 %

 There were no borrowings outstanding on the revolving credit facilities as of December 31, 2024 or 2023.

 CL&P and PSNH have uncommitted line of credit agreements totaling $ 375 million and $ 250 million, respectively, all of which will expire in either May 2025, September 2025 or October 2025. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2024.

 Amounts outstanding under the commercial paper programs are included in Notes Payable and classified in current liabilities on the Eversource and NSTAR Electric balance sheets, as all borrowings are outstanding for no more than 364 days at one time. As a result of the CL&P long-term debt issuance in January 2024, $ 207.3 million of commercial paper borrowings under the Eversource parent commercial paper program were reclassified to Long-Term Debt on Eversource parent's balance sheet as of December 31, 2023.

 Under the credit facilities described above, Eversource and its subsidiaries, including CL&P, NSTAR Electric, PSNH, NSTAR Gas, EGMA, Yankee Gas, and Aquarion Water Company of Connecticut, must comply with certain financial and non-financial covenants, including a consolidated debt to total capitalization ratio. As of December 31, 2024 and 2023, Eversource and its subsidiaries were in compliance with these covenants. If Eversource or its subsidiaries were not in compliance with these covenants, an event of default would occur requiring all outstanding borrowings by such borrower to be repaid, and additional borrowings by such borrower would not be permitted under its respective credit facility.

 Intercompany Borrowings: Eversource parent uses its available capital resources to provide loans to its subsidiaries to assist in meeting their short-term borrowing needs. Eversource parent records intercompany interest income from its loans to subsidiaries, which is eliminated in consolidation. Intercompany loans from Eversource parent to its subsidiaries are eliminated in consolidation on Eversource's balance sheets. As of December 31, 2024, there were intercompany loans from Eversource parent to CL&P of $ 280.0 million and to PSNH of $ 131.1 million. As of December 31, 2023, there were intercompany loans from Eversource parent to CL&P of $ 457.0 million and to PSNH of $ 233.0 million. Eversource parent charges interest on these intercompany loans at the same weighted-average interest rate as its commercial paper program. Intercompany loans from Eversource parent are included in Notes Payable to Eversource Parent and classified in current liabilities on the respective subsidiary's balance sheets, as these intercompany borrowings are outstanding for no more than 364 days at one time. As a result of the CL&P long-term debt issuance in January 2024, $ 207.3 million of CL&P's intercompany borrowings were reclassified to Long-Term Debt on CL&P's balance sheet as of December 31, 2023.

 Sources and Uses of Cash: The Company expects the future operating cash flows of Eversource, CL&P, NSTAR Electric and PSNH, along with existing borrowing availability and access to both debt and equity markets, will be sufficient to meet any working capital and future operating requirements, and capital investment forecasted opportunities.

 9. LONG-TERM DEBT

 Details of long-term debt outstanding are as follows:

 CL&P

 2024
 2023

 First Mortgage Bonds:

 1994 Series D due 2024
 7.875
 %
 $
 —
 $
 139.8

 2004 Series B due 2034
 5.750
 %
 130.0
 130.0

 2005 Series B due 2035
 5.625
 %
 100.0
 100.0

 2006 Series A due 2036
 6.350
 %
 250.0
 250.0

 2007 Series B due 2037
 5.750
 %
 150.0
 150.0

 2007 Series D due 2037
 6.375
 %
 100.0
 100.0

 2014 Series A due 2044
 4.300
 %
 475.0
 475.0

 2015 Series A due 2045
 4.150
 %
 350.0
 350.0

 2017 Series A due 2027
 3.200
 %
 500.0
 500.0

 2018 Series A due 2048
 4.000
 %
 800.0
 800.0

 2020 Series A due 2025
 0.750
 %
 400.0
 400.0

 2021 Series A due 2031
 2.050
 %
 425.0
 425.0

 2023 Series A due 2053
 5.250
 %
 500.0
 500.0

 2023 Series B due 2033
 4.900
 %
 300.0
 300.0

 2024 Series A due 2029
 4.650
 %
 350.0
 —

 2024 Series B due 2034
 4.950
 %
 300.0
 —

 Total First Mortgage Bonds
 5,130.0
 4,619.8

 Less Amounts due Within One Year
 ( 400.0)
 ( 139.8)

 Current Portion Classified as Long-Term Debt (1)

 397.1
 139.8

 Commercial Paper Classified as Long-Term Debt (See Note 8, Short-Term Debt)
 —
 207.3

 Unamortized Premiums and Discounts, Net
 14.3
 18.0

 Unamortized Debt Issuance Costs
 ( 33.2)
 ( 30.7)

 CL&P Long-Term Debt
 $
 5,108.2
 $
 4,814.4

 2024
 2023

 Debentures:

 2006 Debentures due 2036
 5.750
 %
 $
 200.0
 $
 200.0

 2010 Debentures due 2040
 5.500
 %
 300.0
 300.0

 2014 Debentures due 2044
 4.400
 %
 300.0
 300.0

 2015 Debentures due 2025
 3.250
 %
 250.0
 250.0

 2016 Debentures due 2026
 2.700
 %
 250.0
 250.0

 2017 Debentures due 2027
 3.200
 %
 700.0
 700.0

 2019 Debentures due 2029
 3.250
 %
 400.0
 400.0

 2020 Debentures due 2030
 3.950
 %
 400.0
 400.0

 2021 Debentures due 2051
 3.100
 %
 300.0
 300.0

 2021 Debentures due 2031
 1.950
 %
 300.0
 300.0

 2022 Debentures due 2052
 4.550
 %
 450.0
 450.0

 2022 Debentures due 2052
 4.950
 %
 400.0
 400.0

 2023 Debentures due 2028
 5.600
 %
 150.0
 150.0

 2024 Debentures due 2034
 5.400
 %
 600.0
 —

 Total Debentures
 5,000.0
 4,400.0

 Notes:

 2004 Senior Notes Series B due 2034
 5.900
 %
 50.0
 50.0

 2007 Senior Notes Series D due 2037
 6.700
 %
 40.0
 40.0

 2016 Senior Notes Series H due 2026
 2.750
 %
 50.0
 50.0

 Total Notes
 140.0
 140.0

 Less Amounts due Within One Year
 ( 250.0)
 —

 Unamortized Premiums and Discounts, Net
 ( 14.0)
 ( 14.0)

 Unamortized Debt Issuance Costs
 ( 31.1)
 ( 29.1)

 NSTAR Electric Long-Term Debt
 $
 4,844.9
 $
 4,496.9

 PSNH

 2024
 2023

 First Mortgage Bonds:

 2005 Series M due 2035
 5.600
 %
 $
 50.0
 $
 50.0

 2019 Series T due 2049
 3.600
 %
 300.0
 300.0

 2020 Series U due 2050
 2.400
 %
 150.0
 150.0

 2021 Series V due 2031
 2.200
 %
 350.0
 350.0

 2023 Series W due 2053
 5.150
 %
 300.0
 300.0

 2023 Series X due 2033
 5.350
 %
 600.0
 300.0

 Total First Mortgage Bonds
 1,750.0
 1,450.0

 Unamortized Premiums and Discounts, Net
 ( 2.6)
 ( 4.9)

 Unamortized Debt Issuance Costs
 ( 15.3)
 ( 13.5)

 PSNH Long-Term Debt
 $
 1,732.1
 $
 1,431.6

 OTHER

 2024
 2023

 Eversource Parent - Senior Notes due 2025 - 2050
 0.800
 %
 -
 5.950 %
 $
 11,350.0
 $
 10,300.0

 Yankee Gas - First Mortgage Bonds due 2025 - 2051
 1.380
 %
 -
 5.740 %
 1,095.0
 1,015.0

 NSTAR Gas - First Mortgage Bonds due 2025 - 2051
 2.250
 %
 -
 7.110 %
 905.0
 705.0

 EGMA - First Mortgage Bonds due 2028 - 2052
 2.110
 %
 -
 5.730 %
 808.0
 708.0

 Aquarion - Senior Notes due 2024
 4.000 %
 —
 360.0

 Aquarion - Unsecured Notes due 2028 - 2052 (2)

 3.000
 %
 -
 6.430 %
 596.8
 527.0

 Aquarion - Secured Debt due 2027 - 2045 (2)

 1.296
 %
 -
 9.290 %
 40.7
 39.0

 Pre-1983 Spent Nuclear Fuel Obligation (CYAPC)
 5.6
 12.5

 Fair Value Adjustment (3)

 —
 19.3

 Less Fair Value Adjustment - Current Portion (3)

 —
 ( 5.5)

 Less Amounts due in One Year
 ( 750.3)
 ( 1,810.2)

 Current Portion Classified as Long-Term Debt (1)

 —
 990.9

 Unamortized Premiums and Discounts, Net
 41.7
 49.7

 Unamortized Debt Issuance Costs
 ( 76.1)
 ( 65.0)

 Total Other Long-Term Debt
 $
 14,016.4
 $
 12,845.7

 Total Eversource Long-Term Debt
 $
 25,701.6
 $
 23,588.6

 (1) As a result of the CL&P long-term debt issuance in January 2025, $ 397.1 million of current portion of long-term debt was reclassified to Long-Term Debt on Eversource's and CL&P's balance sheets as of December 31, 2024. As a result of the CL&P and Eversource parent long-term debt issuances in January 2024, $ 139.8 million and $ 990.9 million, respectively, of current portion of long-term debt were reclassified to Long-Term Debt on CL&P's and Eversource parent's balance sheets as of December 31, 2023.

 (2) In January 2025, Eversource entered into an agreement to sell Aquarion. Upon close of the sale, Aquarion's long-term debt will be repaid by Eversource and has therefore not been classified as held for sale. The sale is expected to close in late 2025.

 (3) The fair value adjustment amount is the purchase price adjustments, net of amortization, required to record long-term debt at fair value on the dates of the 2012 merger with NSTAR and the 2017 acquisition of Aquarion. As of December 31, 2024, the fair value adjustments were only related to the Aquarion acquisition and were reclassified to Liabilities Held for Sale.

 Availability under Long-Term Debt Issuance Authorizations: On May 1, 2024, the DPU approved NSTAR Electric's request for authorization to issue up to $ 2.40 billion in long-term debt through December 31, 2026. On July 24, 2024, PURA approved CL&P's request for authorization to issue up to $ 1.00 billion in long-term debt through December 31, 2025. On August 12, 2024, the DPU approved EGMA's request for authorization to issue up to $ 325 million in long-term debt through December 31, 2026. On December 18, 2024, the DPU approved NSTAR Gas' request for authorization to issue up to $ 475 million in long-term debt through December 31, 2027. On January 28, 2025, Yankee Gas submitted an application to PURA requesting authorization to issue up to $ 360 million in long-term debt through December 31, 2026. PSNH has utilized its long-term debt authorizations in place with NHPUC.

 Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments:

 Issuance/
(Repayment)
 Issue Date or Repayment Date
 Maturity Date
 Use of Proceeds for Issuance/
Repayment Information

 CL&P 2024 Series A First Mortgage Bonds
 4.65
 %
 $
 350.0
 January 2029

 CL&P Series B First Mortgage Bonds
 4.95
 %
 300.0
 August 2034
 Repaid Series D Bonds, repaid short-term debt, and working capital

 CL&P Series D First Mortgage Bonds
 7.875
 %
 ( 139.8)

 CL&P 2025 Series A First Mortgage Bonds
 4.95
 %
 400.0
 January 2030

 NSTAR Electric Debentures
 5.40
 %
 600.0
 May 2024
 June 2034

 PSNH Series X First Mortgage Bonds
 5.35
 %
 300.0
 October 2033

 Eversource Parent Series DD Senior Notes
 5.00
 %
 350.0
 January 2027
 Repaid short-term debt

 Eversource Parent Series EE Senior Notes
 5.50
 %
 650.0
 January 2034
 Repaid short-term debt

 Eversource Parent Series FF Senior Notes
 5.85
 %
 700.0
 April 2031
 Repaid Series X Senior Notes and Aquarion's 2014 Senior Notes at maturity and short-term debt

 Eversource Parent Series GG Senior Notes
 5.95
 %
 700.0
 July 2034
 Repaid Series X Senior Notes and Aquarion's 2014 Senior Notes at maturity and short-term debt

 Eversource Parent Series X Senior Notes
 4.20
 %
 ( 900.0)

 Eversource Parent Series L Senior Notes
 2.90
 %
 ( 450.0)

 Eversource Parent Series H Senior Notes
 3.15
 %
 ( 300.0)

 NSTAR Gas Series W First Mortgage Bonds
 5.29
 %
 160.0
 June 2029
 Repaid short-term debt, paid capital expenditures and general corporate purposes

 NSTAR Gas Series X First Mortgage Bonds
 5.48
 %
 40.0
 June 2034
 Repaid short-term debt, paid capital expenditures and general corporate purposes

 Yankee Gas Series W First Mortgage Bonds
 5.50
 %
 90.0
 July 2024
 July 2029
 Repaid short-term debt, paid capital expenditures, working capital and repaid Series P bonds at maturity

 Yankee Gas Series X First Mortgage Bonds
 5.74
 %
 90.0
 July 2024
 July 2034
 Repaid short-term debt, paid capital expenditures, working capital and repaid Series P bonds at maturity

 Yankee Gas Series P First Mortgage Bonds
 2.23
 %
 ( 100.0)

 EGMA Series E First Mortgage Bonds
 5.17
 %
 100.0
 November 2034
 Refinanced existing indebtedness, paid capital expenditures and general corporate purposes

 Aquarion Senior Notes
 4.00
 %
 ( 360.0)

 Aquarion Water Company of Connecticut Senior Notes
 5.57
 %
 70.0
 September 2034
 Repaid short-term debt, paid capital expenditures and general corporate purposes

 Long-Term Debt Provisions: The utility plant of CL&P, PSNH, Yankee Gas, NSTAR Gas, EGMA and a portion of Aquarion is subject to the lien of each company's respective first mortgage bond indenture. The Eversource parent, NSTAR Electric and a portion of Aquarion debt is unsecured. Additionally, the long-term debt agreements provide that Eversource and certain of its subsidiaries must comply with certain covenants as are customarily included in such agreements, including equity requirements for NSTAR Electric, NSTAR Gas and Aquarion. Under the equity requirements, NSTAR Electric's and Aquarion's senior notes must maintain a certain consolidated indebtedness to capitalization ratio as of the end of any fiscal quarter and NSTAR Gas' outstanding long-term debt must not exceed equity.

 Certain secured and unsecured long-term debt securities are callable at redemption price or are subject to make-whole provisions.

 No long-term debt defaults have occurred as of December 31, 2024.

 CYAPC's Pre-1983 Spent Nuclear Fuel Obligation: Under the Nuclear Waste Policy Act of 1982, the DOE is responsible for the selection and development of repositories for, and the disposal of, spent nuclear fuel and high-level radioactive waste. CYAPC is obligated to pay the DOE for the costs to dispose of spent nuclear fuel and high-level radioactive waste generated prior to April 7, 1983 (pre-1983 Spent Nuclear Fuel). CYAPC has partially paid this obligation and recorded an accrual for its remaining liability to the DOE. This liability accrues interest costs at the 3-month Treasury bill yield rate. For nuclear fuel used to generate electricity prior to April 7, 1983, payment may be made any time prior to the first delivery of spent fuel to the DOE. As of December 31, 2024 and 2023, as a result of consolidating CYAPC, Eversource has consolidated $ 5.6 million and $ 12.5 million, respectively, in pre-1983 spent nuclear fuel obligations to the DOE. The obligation includes accumulated interest costs of $ 4.3 million and $ 9.5 million as of December 31, 2024 and 2023, respectively. CYAPC maintains a trust to fund amounts due to the DOE for the disposal of pre-1983 spent nuclear fuel. For further information, see Note 5, "Marketable Securities," to the financial statements. Fees for disposal of nuclear fuel burned on or after April 7, 1983 were billed to member companies and paid to the DOE.

 Long-Term Debt Maturities: Long-term debt maturities on debt outstanding for the years 2025 through 2029 and thereafter are shown below. These amounts exclude PSNH rate reduction bonds, CYAPC pre-1983 spent nuclear fuel obligation, and unamortized premiums, discounts, and debt issuance costs as of December 31, 2024:

 CL&P
 PSNH

 2025
 $
 1,400.3
 $
 400.0
 $
 250.0
 $
 —

 2026
 1,390.2
 —
 300.0
 —

 2027
 2,889.2
 500.0
 700.0
 —

 2028
 1,978.5
 —
 150.0
 —

 2029
 2,300.3
 350.0
 400.0
 —

 16,857.0
 3,880.0
 3,340.0
 1,750.0

 Total
 $
 26,815.5
 $
 5,130.0
 $
 5,140.0
 $
 1,750.0

 10. RATE REDUCTION BONDS AND VARIABLE INTEREST ENTITIES

 Rate Reduction Bonds: In May 2018, PSNH Funding, a wholly-owned subsidiary of PSNH, issued $ 635.7 million of securitized RRBs in multiple tranches with a weighted average interest rate of 3.66 percent, and final maturity dates ranging from 2026 to 2035. The RRBs are expected to be repaid by February 1, 2033. RRB payments consist of principal and interest and are paid semi-annually, beginning on February 1, 2019. The RRBs were issued pursuant to a finance order issued by the NHPUC in January 2018 to recover remaining costs resulting from the divestiture of PSNH's generation assets.

 The proceeds were used by PSNH Funding to purchase PSNH's stranded cost asset-recovery property, including its vested property right to bill, collect and adjust a non-bypassable stranded cost recovery charge from PSNH's retail customers. The collections are used to pay principal, interest and other costs in connection with the RRBs. The RRBs are secured by the stranded cost asset-recovery property. Cash collections from the stranded cost recovery charges and funds on deposit in trust accounts are the sole source of funds to satisfy the debt obligation. PSNH is not the owner of the RRBs, and PSNH Funding's assets and revenues are not available to pay PSNH's creditors. The RRBs are non-recourse senior secured obligations of PSNH Funding and are not insured or guaranteed by PSNH or Eversource Energy.

 PSNH Funding was formed solely to issue RRBs to finance PSNH's unrecovered remaining costs associated with the divestiture of its generation assets. PSNH Funding is considered a VIE primarily because the equity capitalization is insufficient to support its operations. PSNH has the power to direct the significant activities of the VIE and is most closely associated with the VIE as compared to other interest holders. Therefore, PSNH is considered the primary beneficiary and consolidates PSNH Funding in its consolidated financial statements.

 The following tables summarize the impact of PSNH Funding on PSNH's balance sheets and income statements:

 PSNH Balance Sheets:
 2024
 2023

 Restricted Cash - Current Portion (included in Special Deposits)
 $
 31.0
 $
 30.0

 Restricted Cash - Long-Term Portion (included in Other Long-Term Assets)
 3.1
 3.2

 Securitized Stranded Cost (included in Regulatory Assets)
 349.3
 392.5

 Other Regulatory Liabilities (included in Regulatory Liabilities)
 6.9
 5.3

 Accrued Interest (included in Other Current Liabilities)
 5.7
 6.3

 Rate Reduction Bonds - Current Portion
 43.2
 43.2

 Rate Reduction Bonds - Long-Term Portion
 324.1
 367.3

PSNH Income Statements:

 2024
 2023
 2022

 Amortization of RRB Principal (included in Amortization of Regulatory Assets/(Liabilities), Net)
 $
 43.2
 $
 43.2
 $
 43.2

 Interest Expense on RRB Principal (included in Interest Expense)
 14.3
 15.7
 17.0

 Estimated principal payments on RRBs as of December 31, 2024, is summarized annually through 2029 and thereafter as follows:

 2025
 2026
 2027
 2028
 2029
 Total

 PSNH
 $
 43.2
 $
 43.2
 $
 43.2
 $
 43.2
 $
 43.2
 $
 151.3
 $
 367.3

 Variable Interest Entities - Other: The Company's variable interests outside of the consolidated group include contracts that are required by regulation and provide for regulatory recovery of contract costs and benefits through customer rates. Eversource, CL&P and NSTAR Electric hold variable interests in VIEs through agreements with certain entities that own single renewable energy or peaking generation power plants, with other independent power producers and with transmission businesses. Eversource, CL&P and NSTAR Electric do not control the activities that are economically significant to these VIEs or provide financial or other support to these VIEs. Therefore, Eversource, CL&P and NSTAR Electric do not consolidate these VIEs.

 11. EMPLOYEE BENEFITS

 A. Pension Benefits and Postretirement Benefits Other Than Pension
 Eversource provides defined benefit retirement plans (Pension Plans) that cover eligible employees and are subject to the provisions of ERISA, as amended by the Pension Protection Act of 2006. Eversource's policy is to annually fund the Pension Plans in an amount at least equal to an amount that will satisfy all federal funding requirements. In addition to the Pension Plans, Eversource maintains non-qualified defined benefit retirement plans (SERP Plans), which provide benefits in excess of Internal Revenue Code limitations to eligible participants consisting of current and retired employees.

 Eversource also provides defined benefit postretirement plans (PBOP Plans) that provide life insurance and a health reimbursement arrangement created for the purpose of reimbursing retirees and dependents for health insurance premiums and certain medical expenses to eligible employees that meet certain age and service eligibility requirements. The benefits provided under the PBOP Plans are not vested, and the Company has the right to modify any benefit provision subject to applicable laws at that time. Eversource annually funds postretirement costs through tax deductible contributions to external trusts.

 In August 2024, Eversource communicated to its employees participating in the Eversource 401k Plan enhanced defined contribution feature (referred to as K-Vantage) that effective January 1, 2025, a Cash Balance Pension Plan is established, which replaces employer K-Vantage contributions. Eversource transferred into the Cash Balance Pension Plan employees who are participants in the K-Vantage plan, with the exception of one union group with ongoing negotiations, and will credit employees a set percentage of an employee's eligible pay based on age and years of service on the employee's behalf. This benefit is a new, additional obligation of the existing Pension Plan and will be funded through the existing assets of the Eversource Pension Plan. This plan amendment did not require a remeasurement in 2024 and the liability will begin to accrue benefits upon the effective date of January 1, 2025.

 Funded Status: The Pension, SERP and PBOP Plans are accounted for under the multiple-employer approach, with each operating company's balance sheet reflecting its share of the funded status of the plans. The SERP Plans do not contain any assets. The following tables provide information on the plan benefit obligations, fair values of plan assets, and funded status:

 2024
 2023

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Change in Benefit Obligation:

 Benefit Obligation as of Beginning of Year
 $
 ( 5,238.4)
 $
 ( 1,048.5)
 $
 ( 1,107.0)
 $
 ( 562.3)
 $
 ( 5,220.1)
 $
 ( 1,030.0)
 $
 ( 1,110.4)
 $
 ( 556.2)

 ( 44.3)
 ( 12.7)
 ( 7.7)
 ( 4.3)
 ( 43.1)
 ( 12.3)
 ( 7.8)
 ( 4.3)

 ( 250.0)
 ( 50.3)
 ( 51.6)
 ( 26.8)
 ( 254.0)
 ( 50.5)
 ( 53.9)
 ( 27.3)

 Actuarial Gain/(Loss)
 280.2
 56.2
 74.1
 30.7
 ( 110.4)
 ( 19.7)
 ( 17.6)
 ( 11.6)

 Benefits Paid - Pension
 320.9
 68.1
 67.1
 38.0
 317.3
 66.1
 76.7
 35.7

 Benefits Paid - Lump Sum
 24.0
 —
 7.6
 0.1
 28.9
 —
 5.3
 1.0

 Benefits Paid - SERP
 19.4
 0.3
 0.2
 0.4
 43.0
 0.3
 0.2
 0.4

 Employee Transfers
 —
 4.0
 13.8
 2.7
 —
 ( 2.4)
 0.5
 —

 Reclassified to Assets Held for Sale
 142.5
 —
 —
 —
 —
 —
 —
 —

 Benefit Obligation as of End of Year
 $
 ( 4,745.7)
 $
 ( 982.9)
 $
 ( 1,003.5)
 $
 ( 521.5)
 $
 ( 5,238.4)
 $
 ( 1,048.5)
 $
 ( 1,107.0)
 $
 ( 562.3)

 Change in Pension Plan Assets:

 Fair Value of Pension Plan Assets as of
 Beginning of Year
 $
 5,775.0
 $
 1,170.0
 $
 1,411.6
 $
 614.0
 $
 5,806.4
 $
 1,172.0
 $
 1,418.8
 $
 618.0

 Employer Contributions
 5.0
 —
 —
 —
 5.0
 —
 —
 —

 Actual Return on Pension Plan Assets
 227.0
 46.5
 55.1
 24.3
 309.8
 61.7
 75.3
 32.7

 Benefits Paid - Pension
 ( 320.9)
 ( 68.1)
 ( 67.1)
 ( 38.0)
 ( 317.3)
 ( 66.1)
 ( 76.7)
 ( 35.7)

 Benefits Paid - Lump Sum
 ( 24.0)
 —
 ( 7.6)
 ( 28.9)
 —
 ( 5.3)
 ( 1.0)

 Employee Transfers
 —
 ( 4.0)
 ( 13.8)
 ( 2.7)
 —
 2.4
 —

 Reclassified to Assets Held for Sale
 ( 148.1)
 —
 —
 —
 —
 —
 —
 —

 Fair Value of Pension Plan Assets as of End of Year
 $
 5,514.0
 $
 1,144.4
 $
 1,378.2
 $
 597.5
 $
 5,775.0
 $
 1,170.0
 $
 1,411.6
 $
 614.0

 Funded Status as of December 31st
 $
 768.3
 $
 161.5
 $
 374.7
 $
 76.0
 $
 536.6
 $
 121.5
 $
 304.6
 $
 51.7

 Actuarial Gain/(Loss): For the year ended December 31, 2024, the actuarial gain was primarily attributable to an increase in the discount rate, which resulted in a decrease to Eversource's Pension and SERP Plans' projected benefit obligation of $ 332.9 million, partially offset by an actuarial loss of $ 42.1 million related to updated census data. For the year ended December 31, 2023, the actuarial loss was primarily attributable to a decrease in the discount rate, which resulted in an increase to Eversource's Pension and SERP Plans' projected benefit obligation of $ 98.9 million.

 As of December 31, 2024 and 2023, the accumulated benefit obligation for the Pension and SERP Plans is as follows:

 CL&P
 PSNH

 2024
 $
 4,617.1
 $
 953.9
 $
 969.5
 $
 507.4

 2023
 4,936.8
 977.8
 1,051.9
 522.1

 PBOP

 2024
 2023

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Change in Benefit Obligation:

 Benefit Obligation as of Beginning of Year
 $
 ( 676.0)
 $
 ( 120.6)
 $
 ( 188.3)
 $
 ( 72.0)
 $
 ( 693.7)
 $
 ( 127.9)
 $
 ( 189.5)
 $
 ( 74.6)

 ( 0.6)
 ( 7.6)

 ( 31.9)
 ( 5.6)
 ( 8.8)
 ( 3.4)
 ( 33.8)
 ( 6.2)
 ( 9.2)
 ( 3.7)

 Actuarial Gain/(Loss)
 41.3
 8.9
 10.7
 3.9
 5.0
 4.4
 ( 5.8)
 0.8

 Benefits Paid
 51.7
 9.4
 15.9
 6.2
 52.7
 10.0
 16.7
 6.1

 Employee Transfers
 —
 —
 0.3
 —
 —
 —
 0.5

 Plan Amendment
 —
 —
 —
 —
 1.4
 0.4
 0.2
 0.2

 Reclassified to Assets Held for Sale
 34.5
 —
 —
 —
 —
 —
 —
 —

 Benefit Obligation as of End of Year
 $
 ( 587.4)
 $
 ( 109.1)
 $
 ( 171.4)
 $
 ( 65.9)
 $
 ( 676.0)
 $
 ( 120.6)
 $
 ( 188.3)
 $
 ( 72.0)

 Change in Plan Assets:

 Fair Value of Plan Assets as of Beginning of Year
 $
 1,024.4
 $
 123.0
 $
 490.4
 $
 74.7
 $
 970.1
 $
 120.6
 $
 456.1
 $
 72.3

 Actual Return on Plan Assets
 92.3
 11.2
 45.8
 7.6
 104.7
 12.6
 52.3
 8.3

 Employer Contributions
 0.9
 —
 —
 —
 1.9
 —
 —
 —

 Benefits Paid
 ( 51.8)
 ( 9.4)
 ( 15.9)
 ( 6.1)
 ( 52.3)
 ( 10.0)
 ( 16.7)
 ( 6.1)

 Employee Transfers
 —
 ( 1.1)
 0.2
 —
 0.2

 Reclassified to Assets Held for Sale
 ( 29.5)
 —
 —
 —
 —
 —
 —
 —

 Fair Value of Plan Assets as of End of Year
 $
 1,036.3
 $
 124.4
 $
 519.2
 $
 76.4
 $
 1,024.4
 $
 123.0
 $
 490.4
 $
 74.7

 Funded Status as of December 31st
 $
 448.9
 $
 15.3
 $
 347.8
 $
 10.5
 $
 348.4
 $
 2.4
 $
 302.1
 $
 2.7

 Actuarial Gain/(Loss): For the year ended December 31, 2024, the actuarial gain was primarily attributable to an increase in the discount rate, which resulted in a decrease to the Eversource PBOP projected benefit obligation of $ 39.8 million. For the year ended December 31, 2023, the actuarial gain was primarily attributable to changes to termination, retirement, and dependency rates that were updated as a result of an experience study performed in 2023, updated census data, changes to plan provisions, and other assumption changes, which resulted in a decrease to the Eversource PBOP projected benefit obligation of $ 17 million. The actuarial gain was partially offset by a decrease in the discount rate, which resulted in an increase to the Eversource PBOP projected benefit obligation of $ 12 million.

 A reconciliation of the prepaid assets and liabilities within the Eversource Pension, SERP and PBOP Plans' funded status to the balance sheets is as follows:

 2024
 2023

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Prepaid Pension (1)

 $
 887.7
 $
 167.2
 $
 376.9
 $
 80.5
 $
 672.2
 $
 127.4
 $
 306.5
 $
 56.3

 Prepaid PBOP
 448.9
 15.3
 347.8
 10.5
 356.0
 2.4
 302.1
 2.7

 $
 1,336.6
 $
 182.5
 $
 724.7
 $
 91.0
 $
 1,028.2
 $
 129.8
 $
 608.6
 $
 59.0

 Accrued SERP (1)

 $
 119.4
 $
 5.7
 $
 2.2
 $
 4.5
 $
 135.6
 $
 5.9
 $
 1.9
 $
 4.6

 Accrued PBOP (1)

 —
 —
 —
 —
 7.6
 —
 —
 —

 Less: Accrued SERP - current portion
 ( 24.0)
 ( 19.4)

 Accrued SERP and PBOP
 $
 95.4
 $
 5.3
 $
 2.0
 $
 4.1
 $
 123.8
 $
 5.6
 $
 1.7
 $
 4.2

 (1) As of December 31, 2024, the Aquarion water distribution business's prepaid pension has been reclassified to Assets Held for Sale and the accrued SERP and PBOP liabilities have been reclassified to Liabilities Held for Sale on the Eversource balance sheet. As of December 31, 2023, these balances were recorded within Prepaid Pension and PBOP and Accrued SERP and PBOP on the Eversource balance sheet. For further information, see Note 24, "Assets Held for Sale."

 The following actuarial assumptions were used in calculating the Pension, SERP and PBOP Plans' year end funded status:

 PBOP

 2024
 2023
 2024
 2023

 Discount Rate
 5.6 %
 —
 5.7 %
 4.9 %
 —
 5.0 %
 5.7 %
 5.0 %
 —
 5.2 %

 Compensation/Progression Rate
 3.5 %
 —
 4.0 %
 3.5 %
 —
 4.0 %
 N/A

 For the Eversource Service PBOP Plan, the health care cost trend rate is not applicable. For the Aquarion PBOP Plan, the health care cost trend rate for pre-65 retirees is 7.5 percent, with an ultimate rate of 5 percent in 2035, and for post-65 retirees, the health care trend rate and ultimate rate is 3.5 percent.

 Expense: Eversource charges net periodic benefit plan expense/(income) for the Pension, SERP and PBOP Plans to its subsidiaries based on the actual participant demographic data for each subsidiary's participants. The actual investment return in the trust is allocated to each of the subsidiaries annually in proportion to the investment return expected to be earned during the year. The Company utilizes the spot rate methodology to estimate the discount rate for the service and interest cost components of benefit plan expense, which provides a relatively precise measurement by matching projected cash flows to the corresponding spot rates on the yield curve.

 The components of net periodic benefit plan expense/(income) for the Pension, SERP and PBOP Plans, prior to amounts capitalized as Property, Plant and Equipment or deferred as regulatory assets/(liabilities) for future recovery or refund, are shown below. The service cost component of net periodic benefit plan expense/(income), less the capitalized portion, is included in Operations and Maintenance expense on the statements of income. The remaining components of net periodic benefit plan expense/(income), less the deferred portion, are included in Other Income, Net on the statements of income. Pension, SERP and PBOP plan expense/(income) reflected in the statements of cash flows for CL&P, NSTAR Electric and PSNH does not include intercompany allocations of net periodic benefit plan expense/(income), as these amounts are cash settled on a short-term basis.

 PBOP

 CL&P
 PSNH
 CL&P
 PSNH

 $
 44.3
 $
 12.7
 $
 7.7
 $
 4.3
 $
 7.0
 $
 1.2
 $
 1.2
 $
 0.6

 250.0
 50.3
 51.6
 26.8
 31.9
 5.6
 8.8
 3.4

 Expected Return on Plan Assets
 ( 462.6)
 ( 93.5)
 ( 112.4)
 ( 48.9)
 ( 81.2)
 ( 9.5)
 ( 39.5)
 ( 5.6)

 Actuarial Loss/(Gain)
 85.9
 12.1
 25.6
 5.0
 —
 —
 —

 Prior Service Cost/(Credit)
 1.3
 —
 0.3
 —
 ( 21.6)
 1.1
 ( 17.0)
 0.4

 Settlement Loss
 4.3
 —
 —
 —
 —
 —
 —
 —

 Total Net Periodic Benefit Plan Income
 $
 ( 76.8)
 $
 ( 18.4)
 $
 ( 27.2)
 $
 ( 12.8)
 $
 ( 64.3)
 $
 ( 1.6)
 $
 ( 46.5)
 $

 Intercompany Income Allocations
 N/A
 $
 ( 1.6)
 $
 $
 N/A
 $
 ( 2.2)
 $
 ( 2.6)
 $

 PBOP

 CL&P
 PSNH
 CL&P
 PSNH

 $
 43.1
 $
 12.3
 $
 7.8
 $
 4.3
 $
 7.6
 $
 1.3
 $
 1.2
 $
 0.7

 254.0
 50.5
 53.9
 27.3
 33.8
 6.2
 9.2
 3.7

 Expected Return on Plan Assets
 ( 465.0)
 ( 94.2)
 ( 113.8)
 ( 49.5)
 ( 77.1)
 ( 9.4)
 ( 36.9)
 ( 5.5)

 Actuarial Loss
 45.8
 2.5
 17.1
 1.5
 —
 —
 —
 —

 Prior Service Cost/(Credit)
 1.3
 —
 0.3
 —
 ( 21.6)
 1.1
 ( 17.0)
 0.4

 Settlement Loss
 12.4
 —
 —
 —
 —
 —
 —
 —

 Total Net Periodic Benefit Plan Income
 $
 ( 108.4)
 $
 ( 28.9)
 $
 ( 34.7)
 $
 ( 16.4)
 $
 ( 57.3)
 $
 ( 0.8)
 $
 ( 43.5)
 $

 Intercompany Income Allocations
 N/A
 $
 ( 4.0)
 $
 ( 3.0)
 $
 ( 0.8)
 N/A
 $
 ( 1.9)
 $
 $

 PBOP

 CL&P
 PSNH
 CL&P
 PSNH

 $
 70.1
 $
 18.7
 $
 13.8
 $
 6.9
 $
 11.6
 $
 2.0
 $
 2.0
 $
 1.1

 154.5
 31.3
 32.8
 16.9
 20.2
 3.7
 5.3
 2.2

 Expected Return on Plan Assets
 ( 523.6)
 ( 106.3)
 ( 128.4)
 ( 56.1)
 ( 89.9)
 ( 11.4)
 ( 42.4)
 ( 6.7)

 Actuarial Loss
 116.0
 16.2
 32.8
 7.9
 —
 —
 —
 —

 Prior Service Cost/(Credit)
 1.4
 —
 0.3
 —
 ( 21.7)
 1.1
 ( 17.0)
 0.4

 Total Net Periodic Benefit Plan Income
 $
 ( 181.6)
 $
 ( 40.1)
 $
 ( 48.7)
 $
 ( 24.4)
 $
 ( 79.8)
 $
 $
 ( 52.1)
 $
 ( 3.0)

 Intercompany Income Allocations
 N/A
 $
 ( 16.0)
 $
 ( 12.4)
 $
 ( 3.6)
 N/A
 $
 ( 3.7)
 $
 ( 3.6)
 $

 The following actuarial assumptions were used to calculate Pension, SERP and PBOP expense amounts:

 PBOP

 2024
 2023
 2022
 2024
 2023
 2022

 Discount Rate
 4.7 %
 —
 5.1 %
 4.9 %
 —
 5.3 %
 2.2 %
 —
 3.2 %
 4.9 %
 —
 5.2 %
 5.1 %
 —
 5.4 %
 2.3 %
 —
 3.3 %

 Expected Long-Term Rate of Return

 Compensation/Progression Rate
 3.5 %
 —
 4.0 %
 3.5 %
 —
 4.0 %
 3.5 %
 —
 4.0 %
 N/A
 N/A
 N/A

 For the Aquarion Pension Plan, the expected long-term rate of return was 8.25 percent and 7.94 percent for the years ended December 31, 2024 and 2023, respectively. For the Aquarion PBOP Plan, the expected long-term rate of return was 7 percent for the years ended December 31, 2024

 and 2023 and the health care cost trend rate was a range of 3.5 percent to 6.75 percent for the year ended December 31, 2024 and 3.5 percent to 7 percent for the year ended December 31, 2023.

 Regulatory Assets and Accumulated Other Comprehensive Income/(Loss) Amounts: The Pension, SERP and PBOP Plans cover eligible employees, including, among others, employees of the regulated companies. The regulated companies record actuarial losses and gains and prior service costs and credits arising at the December 31st remeasurement date of the funded status of the benefit plans as a regulatory asset or regulatory liability in lieu of a charge to Accumulated Other Comprehensive Income/(Loss), reflecting ultimate recovery from customers through rates. Regulatory accounting is also applied to the portions of the Eversource Service retiree benefit costs that support the regulated companies, as these costs are also recovered from customers. Adjustments to the Pension, SERP and PBOP Plans' funded status for the unregulated companies are recorded on an after-tax basis to Accumulated Other Comprehensive Income/(Loss). For further information, see Note 2, "Regulatory Accounting," and Note 16, "Accumulated Other Comprehensive Income/(Loss)," to the financial statements.

 The difference between the actual return and calculated expected return on plan assets for the Pension and PBOP Plans, as well as changes in actuarial assumptions impacting the projected benefit obligation, are recorded as unamortized actuarial gains or losses arising during the year in Regulatory Assets or Accumulated Other Comprehensive Income/(Loss). Unamortized actuarial gains or losses are amortized as a component of pension and PBOP expense over the estimated average future employee service period using the corridor approach.

 The following is a summary of the changes in plan assets and benefit obligations recognized in Regulatory Assets and Other Comprehensive Income (OCI) as well as amounts in Regulatory Assets and OCI that were reclassified as net periodic benefit expense during the years presented:

 PBOP

 OCI
 OCI

 2024
 2023
 2024
 2023
 2024
 2023
 2024
 2023

 Actuarial (Gain)/Loss Arising During the Year
 $
 ( 49.2)
 $
 251.1
 $
 2.3
 $
 14.0
 $
 ( 50.9)
 $
 ( 32.0)
 $
 ( 0.6)
 $

 Actuarial (Loss)/Gain Reclassified as Net Periodic Benefit (Expense)/Income
 ( 79.1)
 ( 38.8)
 ( 6.8)
 0.4
 —
 —
 —

 Actuarial (Loss)/Gain Reclassified as Held for Sale
 ( 16.6)
 —
 —
 —
 7.1
 —
 —
 —

 Settlement Loss
 —
 —
 ( 4.3)
 ( 12.4)
 —
 —
 —
 —

 Prior Service Cost/(Credit) Arising During the Year
 1.3
 —
 —
 —
 —
 —
 —

 Prior Service (Cost)/Credit Reclassified as Net Periodic
 Benefit (Expense)/Income
 21.8
 21.8

 Prior Service Cost Reclassified as Held for Sale
 —
 —
 —
 ( 0.6)
 —
 —
 —

 The following is a summary of the remaining Regulatory Assets and Accumulated Other Comprehensive Income amounts that have not been recognized as components of net periodic benefit expense as of December 31, 2024 and 2023:

 Regulatory Assets as of December 31,
 AOCI as of December 31,

 2024
 2023
 2024
 2023

 Actuarial Loss
 $
 956.1
 $
 1,101.0
 $
 47.7
 $
 56.5

 Prior Service Cost
 1.8
 2.9
 0.2
 0.3

 PBOP

 Actuarial Loss
 $
 6.4
 $
 49.8
 $
 1.8
 $
 2.4

 Prior Service (Credit)/Cost
 ( 66.2)
 ( 87.4)
 0.5
 0.7

 Estimated Future Benefit Payments: The following benefit payments, which reflect expected future service, are expected to be paid by the Pension, SERP and PBOP Plans:

 2025
 2026
 2027
 2028
 2029
 2030 - 2034

 $
 367.3
 $
 363.3
 $
 369.5
 $
 372.9
 $
 375.4
 $
 1,879.4

 PBOP
 51.3
 50.6
 49.8
 48.9
 48.0
 223.3

 Eversource Contributions: Based on the current status of the Pension Plans and federal pension funding requirements, for our Eversource Service Pension Plan there is no minimum funding requirement in 2025 and we do not expect to make pension contributions in 2025. We do not expect to make any contributions to the Eversource Service PBOP Plan in 2025. Eversource contributed $ 5.0 million and $ 0.9 million to the Aquarion Pension and PBOP Plans, respectively, in 2024.

 Fair Value of Pension and PBOP Plan Assets: Pension and PBOP funds are held in external trusts. Trust assets, including accumulated earnings, must be used exclusively for Pension and PBOP payments. Eversource's investment strategy for its Pension and PBOP Plans is to maximize the long-term rates of return on these plans' assets within an acceptable level of risk. The investment guidelines for each asset category includes a diversification of asset types, fund strategies and fund managers and it establishes target asset allocations that are routinely reviewed and periodically rebalanced. PBOP assets are comprised of assets held in the PBOP Plan trust, as well as specific assets within the Pension Plan trust (401(h) assets). The investment policy and strategy of the 401(h) assets is consistent with that of the defined benefit pension plan. Eversource's expected long-term rates of return on Pension and PBOP Plan assets are based on target asset allocation assumptions and related expected long-

 term rates of return. In developing its expected long-term rate of return assumptions for the Pension and PBOP Plans, Eversource evaluated input from consultants, as well as long-term inflation assumptions and historical returns. Management has assumed long-term rates of return of 8.25 percent for the Eversource Service Pension Plan assets, the Eversource Service PBOP Plan assets and the Aquarion Pension Plan assets, and a 7 percent long-term rate of return for the Aquarion PBOP Plan, to estimate its 2025 Pension and PBOP costs.

 These long-term rates of return are based on the assumed rates of return for the target asset allocations as follows:

 2024
 2023

 Target Asset Allocation
 Assumed Rate of Return
 Target Asset Allocation
 Assumed Rate of Return

 Eversource Pension Plan

 Eversource PBOP Plan

 Eversource Pension Plan and PBOP Plan

 Eversource Pension Plan

 Eversource PBOP Plan

 Eversource Pension Plan and PBOP Plan

 Equity Securities:

 United States
 —
 %
 20.0
 %
 8.5
 %
 —
 %
 20.0
 %
 8.5
 %

 Global
 20.0
 %
 —
 %
 8.8
 %
 20.0
 %
 —
 %
 8.75
 %

 Non-United States
 —
 %
 11.0
 %
 8.5
 %
 —
 %
 11.0
 %
 8.5
 %

 Emerging Markets
 —
 %
 6.0
 %
 10.0
 %
 —
 %
 6.0
 %
 10.0
 %

 Debt Securities:

 Fixed Income
 16.0
 %
 17.0
 %
 5.5
 %
 16.0
 %
 17.0
 %
 5.5
 %

 Public High Yield Fixed Income
 5.0
 %
 —
 %
 7.5
 %
 5.0
 %
 —
 %
 7.5
 %

 United States Treasuries
 11.0
 %
 —
 %
 4.5
 %
 11.0
 %
 —
 %
 4.5
 %

 Private Debt
 10.0
 %
 13.0
 %
 10.0
 %
 10.0
 %
 13.0
 %
 10.0
 %

 Private Equity
 23.0
 %
 18.0
 %
 12.0
 %
 23.0
 %
 18.0
 %
 12.0
 %

 Real Assets
 15.0
 %
 15.0
 %
 7.5
 %
 15.0
 %
 15.0
 %
 7.5
 %

 The following tables present, by asset category, the Pension and PBOP Plan assets recorded at fair value on a recurring basis by the level in which they are classified within the fair value hierarchy:

 Pension Plan

 Fair Value Measurements as of December 31,

 2024 (1)

 2023 (2)

 Asset Category:
 Level 1
 Uncategorized
 Total
 Level 1
 Uncategorized
 Total

 Equity Securities
 $
 323.6
 $
 —
 $
 826.0
 $
 1,149.6
 $
 374.0
 $
 —
 $
 853.0
 $
 1,227.0

 Fixed Income
 314.3
 344.7
 1,329.6
 1,988.6
 354.6
 340.9
 1,516.4
 2,211.9

 Private Equity
 —
 —
 1,710.9
 1,710.9
 —
 —
 1,685.3
 1,685.3

 Real Assets
 243.8
 —
 652.2
 896.0
 173.6
 —
 722.1
 895.7

 Total
 $
 881.7
 $
 344.7
 $
 4,518.7
 $
 5,745.1
 $
 902.2
 $
 340.9
 $
 4,776.8
 $
 6,019.9

 Less: 401(h) PBOP Assets (3)

 ( 231.1)

 ( 244.9)

 Total Pension Assets

 $
 5,514.0

 $
 5,775.0

 PBOP Plan

 Fair Value Measurements as of December 31,

 2024 (1)

 2023

 Asset Category:
 Level 1
 Uncategorized
 Total
 Level 1
 Uncategorized
 Total

 Equity Securities
 $
 184.8
 $
 —
 $
 166.3
 $
 351.1
 $
 139.1
 $
 —
 $
 212.1
 $
 351.2

 Fixed Income
 61.8
 44.6
 127.5
 233.9
 33.4
 43.0
 159.8
 236.2

 Private Equity
 —
 —
 99.0
 99.0
 —
 —
 87.7
 87.7

 Real Assets
 83.7
 —
 37.5
 121.2
 70.5
 —
 33.9
 104.4

 Total
 $
 330.3
 $
 44.6
 $
 430.3
 $
 805.2
 $
 243.0
 $
 43.0
 $
 493.5
 $
 779.5

 Add: 401(h) PBOP Assets (3)

 231.1

 244.9

 Total PBOP Assets

 $
 1,036.3

 $
 1,024.4

 (1) As of December 31, 2024, the funded status of the Aquarion water distribution business's Pension and PBOP benefit plans have been reclassified in held for sale presentation on the Eversource balance sheet. Therefore, these Pension and PBOP asset balances have been excluded from the table above as of December 31, 2024.

 (2) Fixed Income investments classified as Level 1 as of December 31, 2023 include pending purchases and pending redemption settlements of $ 31 million.

 (3) The assets of the Pension Plan include a 401(h) account that has been allocated to provide health and welfare postretirement benefits under the PBOP Plan.

 The Company values assets based on observable inputs when available. Equity securities, fixed income exchange traded funds and real asset futures contracts classified as Level 1 in the fair value hierarchy are priced based on the closing price on the primary exchange as of the balance sheet date.

 Fixed income securities, such as government issued securities and corporate bonds, are included in Level 2 and are valued using pricing models, quoted prices of securities with similar characteristics or discounted cash flows. The pricing models utilize observable inputs such as recent trades for the same or similar instruments, yield curves, discount margins and bond structures. Swaps are valued using pricing models that incorporate interest rates and equity and fixed income index closing prices to determine a net present value of the cash flows.

 Certain investments, such as commingled funds, private equity investments, fixed income funds, real asset funds and hedge funds are valued using the net asset value (NAV) as a practical expedient. Assets valued at NAV are uncategorized in the fair value hierarchy. These investments are structured as investment companies offering shares or units to multiple investors for the purpose of providing a return. Commingled funds are recorded at NAV provided by the asset manager, which is based on the market prices of the underlying equity securities. Private Equity investments, Fixed Income partnership funds and Real Assets are valued using the NAV provided by the partnerships, which are based on discounted cash flows of the underlying investments, real estate appraisals or public market comparables of the underlying investments, or the NAV of underlying assets held in hedge funds. Equity Securities investments in United States, Global, Non-United States and Emerging Markets that are uncategorized include investments in commingled funds and hedge funds that are overlaid with equity index swaps and futures contracts. Fixed Income investments that are uncategorized include investments in commingled funds, fixed income funds that invest in a variety of opportunistic credit and private debt strategies, and hedge funds that are overlaid with fixed income futures.

 B. Defined Contribution Plans
 Eversource maintains defined contribution plans on behalf of eligible participants. The Eversource 401k Plan provides for employee and employer contributions up to statutory limits. For the years ended December 31, 2024, 2023 and 2022, for eligible employees, the Eversource 401k Plan provided employer matching contributions of either 100 percent up to a maximum of three percent of eligible compensation or 50 percent up to a maximum of eight percent of eligible compensation. The Eversource 401k Plan also contained a K-Vantage feature for the benefit of eligible participants, which provided an additional annual employer contribution based on age and years of service. K-Vantage participants were not eligible to actively participate in the Eversource Pension Plan.

 The total Eversource 401k Plan employer matching contributions, including the K-Vantage contributions, were as follows:

 CL&P
 PSNH

 2024
 $
 76.2
 $
 10.6
 $
 15.4
 $
 6.0

 2023
 67.3
 9.0
 13.7
 5.4

 2022
 59.9
 7.7
 12.8
 4.8

 Effective January 1, 2025 for eligible Plan participants, the Eversource 401k Plan began providing employer matching contributions of 100 percent up to a maximum of six percent of eligible compensation. Also effective January 1, 2025, Eversource replaced employer K-Vantage contributions with the Cash Balance Pension Plan. See Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for further information.

 C. Share-Based Payments
 Share-based compensation awards are recorded using a fair-value based method at the date of grant. Eversource, CL&P, NSTAR Electric and PSNH record compensation expense related to these awards, as applicable, for shares issued to their respective employees and officers, as well as for the allocation of costs associated with shares issued to Eversource's service company employees and officers that support CL&P, NSTAR Electric and PSNH.

 Eversource Incentive Plans: Eversource maintains long-term equity-based incentive plans in which Eversource, CL&P, NSTAR Electric and PSNH employees, officers and board members are eligible to participate. The incentive plans authorize Eversource to grant up to 7,400,000 new shares for various types of awards, including RSUs and performance shares, to eligible employees, officers, and board members. As of December 31, 2024 and 2023, Eversource had 3,790,353 and 4,587,376 common shares, respectively, available for issuance under these plans.

 Eversource accounts for its various share-based plans as follows:

 • RSUs - Eversource records compensation expense, net of estimated forfeitures, on a straight-line basis over the requisite service period based upon the fair value of Eversource's common shares at the date of grant. The par value of RSUs is reclassified to Common Stock from Capital Surplus, Paid In as RSUs become issued as common shares.

 • Performance Shares - Eversource records compensation expense, net of estimated forfeitures, over the requisite service period. Performance shares vest based upon the extent to which Company goals are achieved. Vesting of outstanding performance shares is based upon the Company's EPS growth over the requisite service period and level of payout is determined based on the total shareholder return as compared to the Edison Electric Institute (EEI) Index during the requisite service period. The fair value of performance shares is determined at the date of grant using a lattice model. Compensation expense is subject to volatility until payout is established.

 RSUs: Eversource granted RSUs under the annual long-term incentive programs that are subject to three-year graded vesting schedules for employees, and one-year graded vesting schedules, or immediate vesting, for board members. RSUs are paid in shares, reduced by amounts sufficient to satisfy withholdings for income taxes, subsequent to vesting. A summary of RSU transactions is as follows:

 RSUs
(Units)
 Weighted Average
Grant-Date Fair Value

 Outstanding as of December 31, 2023
 672,242
 $
 65.89

 Granted
 372,400
 $
 57.93

 Shares Issued
 ( 289,372)
 $
 65.25

 Forfeited
 ( 39,828)
 $
 66.91

 Outstanding as of December 31, 2024
 715,442
 $
 61.95

 The weighted average grant-date fair value of RSUs granted for the years ended December 31, 2024, 2023 and 2022 was $ 57.93, $ 76.42 and $ 85.96, respectively. As of December 31, 2024 and 2023, the number and weighted average grant-date fair value of unvested RSUs was 455,620 and $ 65.29 per share, and 326,581 and $ 80.76 per share, respectively. During 2024, there were 280,938 RSUs at a weighted average grant-date fair value of $ 65.20 per share that vested during the year and were either paid or deferred. As of December 31, 2024, 259,822 RSUs were fully vested and deferred and an additional 432,839 are expected to vest.

 Performance Shares: Eversource granted performance shares under the annual long-term incentive programs that vest based upon the extent to which Company goals are achieved at the end of three-year performance measurement periods. Performance shares are paid in shares, after the performance measurement period. A summary of performance share transactions is as follows:

 Performance Shares
(Units)
 Weighted Average
Grant-Date Fair Value

 Outstanding as of December 31, 2023
 664,424
 $
 85.33

 Granted
 431,789
 $
 55.87

 Shares Issued
 ( 126,054)
 $
 85.54

 Forfeited
 ( 105,967)
 $
 77.98

 Outstanding as of December 31, 2024
 864,192
 $
 71.48

 The weighted average grant-date fair value of performance shares granted for the years ended December 31, 2024, 2023 and 2022 was $ 55.87, $ 83.39 and $ 83.34, respectively. As of December 31, 2024 and 2023, the number and weighted average grant-date fair value of unvested performance shares was 737,738 and $ 69.12 per share, and 485,480 and $ 85.20 per share, respectively. During 2024, there were 72,723 performance shares at a weighted average grant-date fair value of $ 84.87 per share that vested during the year and were either paid or deferred. As of December 31, 2024, 126,454 performance shares were fully vested and deferred.

 Compensation Expense: The total compensation expense and associated future income tax benefits recognized by Eversource, CL&P, NSTAR Electric and PSNH for share-based compensation awards were as follows:

 2024
 2023
 2022

 Compensation Expense
 $
 30.0
 $
 27.8
 $
 33.4

 Future Income Tax Benefit
 7.8
 7.3
 8.7

 2024
 2023
 2022

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Compensation Expense
 $
 9.3
 $
 9.6
 $
 3.6
 $
 8.7
 $
 8.7
 $
 3.0
 $
 10.0
 $
 10.7
 $
 3.6

 Future Income Tax Benefit
 2.4
 2.5
 0.9
 2.3
 2.3
 0.8
 2.6
 2.8
 0.9

 As of December 31, 2024, there was $ 31.2 million of total unrecognized compensation expense related to nonvested share-based awards for Eversource, including $ 5.5 million for CL&P, $ 8.8 million for NSTAR Electric, and $ 2.0 million for PSNH. This cost is expected to be recognized ratably over a weighted-average period of 1.76 years for Eversource, CL&P, and PSNH and 1.77 years for NSTAR Electric.

 An income tax rate of 26 percent was used to estimate the tax effect on total share-based payments determined under the fair-value based method for all awards. The Company issues treasury shares to settle fully vested RSUs and performance shares under the Company's incentive plans.

 For the years ended December 31, 2024 and 2023, a tax deficiency associated with the distribution of stock compensation awards increased income tax expense by $ 2.3 million and $ 0.5 million, respectively, which decreased cash flows from operating activities on the statements of cash flows. For the year ended December 31, 2022, excess tax benefits associated with the distribution of stock compensation awards reduced income tax expense by $ 2.1 million, which increased cash flows from operating activities on the statements of cash flows.

 D. Other Retirement Benefits
 Eversource provides retirement and other benefits for certain current and past company officers. These benefits are accounted for on an accrual basis and expensed over a period equal to the service lives of the employees. The actuarially-determined liability for these benefits is included in Other Current and Long-Term Liabilities on the balance sheets. The related expense, which includes the allocation of expense associated with Eversource's service company officers that support CL&P, NSTAR Electric and PSNH, is included in Operations and Maintenance Expense on the income statements. The liability and expense amounts are as follows:

 As of and For the Years Ended December 31,

 2024
 2023
 2022

 Actuarially-Determined Liability
 $
 30.2
 $
 32.6
 $
 43.4

 Other Retirement Benefits Expense (1)

 2.4
 2.6
 10.9

 As of and For the Years Ended December 31,

 2024
 2023
 2022

 CL&P
 PSNH
 CL&P
 PSNH
 CL&P
 PSNH

 Actuarially-Determined Liability
 0.1
 $
 —
 $
 1.0
 $
 0.2
 $
 —
 $
 1.1
 $
 0.2
 $
 0.1
 $
 1.3

 Other Retirement Benefits Expense (1)

 0.8
 0.8
 0.3
 0.8
 0.8
 0.4
 4.0
 3.7
 1.3

 (1) Other Retirement Benefits Expense in 2022 includes a one-time special retirement benefit payable of $ 9.2 million, which was paid in 2023.

 12. INCOME TAXES

 The components of income tax expense are as follows:

 2024
 2023
 2022

 Current Income Taxes:

 $
 ( 23.4)
 $
 75.8
 $
 95.8

 State
 14.3
 0.6
 13.6

 Total Current
 ( 9.1)
 76.4
 109.4

 Deferred Income Taxes, Net:

 266.3
 198.8

 State
 169.6
 86.3
 148.0

 Total Deferred
 435.9
 85.4
 346.8

 Investment Tax Credits, Net
 ( 2.6)

 $
 424.7
 $
 159.7
 $
 453.6

 2024
 2023
 2022

 CL&P
 NSTAR
 PSNH
 CL&P
 PSNH
 CL&P
 PSNH

 Current Income Taxes:

 $
 25.9
 $
 65.9
 $
 $
 ( 10.8)
 $
 50.7
 $
 ( 40.0)
 $
 106.2
 $
 55.0
 $
 29.6

 State
 ( 6.8)
 15.2
 ( 5.2)
 ( 2.3)
 7.8
 ( 20.0)
 20.1
 8.7
 5.9

 Total Current
 19.1
 81.1
 ( 6.9)
 ( 13.1)
 58.5
 ( 60.0)
 126.3
 63.7
 35.5

 Deferred Income Taxes, Net:

 107.9
 63.9
 50.8
 130.3
 50.1
 81.2
 17.2
 35.6
 5.9

 State
 67.5
 47.3
 26.3
 53.7
 46.1
 37.8
 28.2
 42.4
 9.9

 Total Deferred
 175.4
 111.2
 77.1
 184.0
 96.2
 119.0
 45.4
 78.0
 15.8

 Investment Tax Credits, Net
 —
 —
 —
 —
 —

 $
 194.5
 $
 190.6
 $
 70.2
 $
 170.9
 $
 153.0
 $
 59.0
 $
 171.2
 $
 140.0
 $
 51.3

 A reconciliation between income tax expense and the expected tax expense at the statutory rate is as follows:

 (Millions of Dollars, except percentages)

 2024
 2023
 2022

 Income/(Loss) Before Income Tax Expense
 $
 1,243.8
 $
 ( 275.0)
 $
 1,866.0

 Statutory Federal Income Tax Expense at 21%
 261.2
 ( 57.7)
 391.9

 Tax Effect of Differences:

 ( 22.6)
 ( 25.8)
 ( 17.1)

 Investment Tax Credit Amortization
 ( 2.6)

 Other Federal Tax Credits
 ( 67.0)
 ( 42.5)
 —

 State Income Taxes, Net of Federal Impact
 43.2
 ( 11.4)
 75.9

 Dividends on ESOP
 ( 5.5)
 ( 5.3)
 ( 5.1)

 Tax Asset Valuation Allowance/Reserve Adjustments
 278.6
 295.8
 51.6

 Tax Deficiency/(Excess Stock Benefit)
 2.3
 0.5

 EDIT Amortization
 ( 37.0)
 ( 51.5)
 ( 49.1)

 Other, Net
 ( 26.4)
 59.7
 10.2

 $
 424.7
 $
 159.7
 $
 453.6

 Effective Tax Rate
 34.1
 %
 ( 58.1)
 %
 24.3
 %

 2024
 2023
 2022

 (Millions of Dollars, except percentages)
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 $
 707.1
 $
 826.9
 $
 285.1
 $
 689.6
 $
 697.5
 $
 254.7
 $
 704.1
 $
 632.4
 $
 222.9

 Statutory Federal Income Tax Expense at 21%
 148.5
 173.7
 59.9
 144.9
 146.5
 53.5
 147.9
 132.8
 46.8

 Tax Effect of Differences:

 0.4
 ( 10.9)
 ( 1.0)
 ( 5.6)
 ( 8.8)
 ( 1.0)
 ( 3.7)
 ( 4.2)
 0.9

 Investment Tax Credit Amortization
 —
 —
 —
 —
 —

 State Income Taxes, Net of Federal Impact
 ( 2.8)
 49.4
 16.7
 ( 10.7)
 42.5
 14.1
 ( 6.6)
 40.3
 12.5

 Tax Asset Valuation
 Allowance/Reserve Adjustments
 50.8
 —
 —
 51.3
 —
 —
 44.7
 —
 —

 Tax Deficiency/(Excess Stock Benefit)
 0.8
 0.8
 0.3
 0.2
 0.2
 0.1
 ( 0.8)

 EDIT Amortization
 ( 9.2)
 ( 20.0)
 ( 6.5)
 ( 10.5)
 ( 28.4)
 ( 6.8)
 ( 9.2)
 ( 29.2)
 ( 7.7)

 Other, Net
 6.0
 0.8
 1.3
 2.7
 2.8

 $
 194.5
 $
 190.6
 $
 70.2
 $
 170.9
 $
 153.0
 $
 59.0
 $
 171.2
 $
 140.0
 $
 51.3

 Effective Tax Rate
 27.5
 %
 23.0
 %
 24.6
 %
 24.8
 %
 21.9
 %
 23.2
 %
 24.3
 %
 22.1
 %
 23.0
 %

 Eversource, CL&P, NSTAR Electric and PSNH file a consolidated federal income tax return and unitary, combined and separate state income tax returns. These entities are also parties to a tax allocation agreement under which taxable subsidiaries do not pay any more taxes than they would have otherwise paid had they filed a separate company tax return, and subsidiaries generating tax losses, if any, are paid for their losses when utilized.

 Deferred tax assets and liabilities are recognized for the future tax effects of temporary differences between the carrying amounts and the tax basis of assets and liabilities. The tax effect of temporary differences is accounted for in accordance with the rate-making treatment of the applicable regulatory commissions and relevant accounting authoritative literature. The tax effects of temporary differences that give rise to the net accumulated deferred income tax obligations are as follows:

 2024
 2023

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Deferred Tax Assets:

 $
 266.9
 $
 33.7
 $
 83.5
 $
 14.5
 $
 244.5
 $
 29.9
 $
 66.8
 $
 13.0

 Derivative Liabilities
 19.6
 19.6
 —
 —
 33.0
 33.0
 —
 —

 Regulatory Deferrals - Liabilities
 508.7
 128.0
 316.7
 19.6
 452.0
 94.4
 291.5
 23.8

 Allowance for Uncollectible Accounts
 145.3
 75.4
 26.5
 3.8
 143.8
 79.6
 21.5
 3.9

 Tax Effect - Tax Regulatory Liabilities
 720.8
 317.6
 214.3
 93.2
 739.0
 320.7
 227.1
 95.5

 Net Operating Loss Carryforwards
 198.2
 —
 —
 1.5
 13.8
 —
 —
 —

 Purchase Accounting Adjustment
 52.1
 —
 —
 —
 56.7
 —
 —
 —

 Equity Method Wind Investments
 1,098.6
 —
 —
 —
 584.9
 —
 —
 —

 Other
 267.1
 134.7
 31.5
 24.1
 200.1
 125.3
 25.0
 23.4

 Total Deferred Tax Assets
 3,277.3
 709.0
 672.5
 156.7
 2,467.8
 682.9
 631.9
 159.6

 Less: Valuation Allowance (1)

 558.2
 104.1
 —
 —
 328.1
 80.6
 —
 —

 Net Deferred Tax Assets
 $
 2,719.1
 $
 604.9
 $
 672.5
 $
 156.7
 $
 2,139.7
 $
 602.3
 $
 631.9
 $
 159.6

 Deferred Tax Liabilities:

 Accelerated Depreciation and Other
 Plant-Related Differences
 $
 5,493.3
 $
 1,820.3
 $
 1,845.2
 $
 618.4
 $
 5,103.3
 $
 1,703.4
 $
 1,728.6
 $
 566.5

 Property Tax Accruals
 107.4
 49.8
 44.5
 6.5
 95.0
 42.0
 39.8
 6.3

 Regulatory Amounts:

 Regulatory Deferrals - Assets
 1,709.1
 522.9
 519.9
 277.8
 1,512.3
 470.0
 474.5
 250.3

 Tax Effect - Tax Regulatory Assets
 294.5
 194.7
 10.0
 9.4
 284.0
 191.9
 10.5
 8.3

 Goodwill-related Regulatory Asset - 1999 Merger
 67.5
 —
 58.0
 —
 72.2
 —
 61.9
 —

 353.0
 51.0
 175.4
 23.5
 282.0
 38.8
 146.7
 16.8

 Derivative Assets
 3.8
 3.8
 —
 —
 6.4
 6.4
 —
 —

 Other
 101.7
 15.2
 24.9
 2.7
 88.2
 9.9
 19.5
 2.9

 Total Deferred Tax Liabilities
 $
 8,130.3
 $
 2,657.7
 $
 2,677.9
 $
 938.3
 $
 7,443.4
 $
 2,462.4
 $
 2,481.5
 $
 851.1

 (1) As of December 31, 2024 and 2023, the Eversource Valuation Allowance of $ 558.2 million and $ 328.1 million, includes $ 427.0 million and $ 224.0 million, respectively, related to Eversource's share of offshore wind investments.

 Carryforwards: The following table provides the amounts and expiration dates of state tax credit and loss carryforwards and federal tax credit and net operating loss carryforwards:

 2024
 2023

 CL&P
 NSTAR
 PSNH
 Expiration Range
 CL&P
 NSTAR
 PSNH
 Expiration Range

 Federal Net Operating Loss
 $
 877.7
 $
 —
 $
 —
 $
 7.1
 —
 $
 —
 $
 —
 $
 —
 $
 —
 —

 Federal Tax Credit
 404.1
 —
 —
 —
 2044
 —
 —
 —
 —
 —

 Federal Capital Loss
 2,700.0
 —
 —
 —
 2024 - 2029
 —
 —
 —
 —
 —

 State Net Operating Loss
 214.1
 —
 —
 —
 2024 - 2044
 243.4
 —
 —
 —
 2023 - 2041

 State Tax Credit
 238.3
 157.7
 —
 —
 2024 - 2029
 228.5
 157.5
 —
 —
 2023 - 2028

 State Capital Loss
 2,700.0
 —
 —
 —
 2024 - 2029
 —
 —
 —
 —
 —

 State Charitable Contribution
 15.2
 —
 —
 —
 2024 - 2028
 7.9
 —
 —
 —
 2023 - 2027

 In 2024 and 2023, the Company increased its valuation allowance reserve for state credits by $ 27.3 million ($ 23.5 million for CL&P), net of tax, and $ 21.3 million ($ 17.3 million for CL&P), net of tax, respectively, to reflect an update for expiring tax credits.

 For 2024, state credit and federal and state loss carryforwards have been partially reserved by a valuation allowance of $ 558.2 million (net of tax) and for 2023, state credit and state loss carryforwards were partially reserved by a valuation allowance of $ 104.1 million (net of tax).

 Unrecognized Tax Benefits: A reconciliation of the activity in unrecognized tax benefits, all of which would impact the effective tax rate if recognized, is as follows:

 CL&P

 $
 65.8
 $
 26.2

 Gross Increases - Current Year
 11.5
 3.5

 Gross Decreases - Prior Year
 ( 2.4)

 Lapse of Statute of Limitations
 ( 7.8)
 ( 3.3)

 67.1
 25.5

 Gross Increases - Current Year
 23.4
 4.0

 Gross Increases - Prior Year
 0.1
 0.1

 Gross Decreases - Prior Year
 —

 Lapse of Statute of Limitations
 ( 9.2)
 ( 3.8)

 81.3
 25.8

 Gross Increases - Current Year
 14.2
 2.9

 Gross Increases - Prior Year
 11.0
 —

 Gross Decreases - Prior Year

 Lapse of Statute of Limitations
 ( 12.6)
 ( 6.6)

 $
 93.7
 $
 21.9

 Interest and Penalties: Interest on uncertain tax positions is recorded and generally classified as a component of Other Interest Expense on the statements of income. However, when resolution of uncertainties results in the Company receiving interest income, any related interest benefit is recorded in Other Income, Net on the statements of income. No penalties have been recorded. The amount of interest expense recognized on uncertain tax positions was $ 1.3 million and $ 0.3 million for the years ended December 31, 2024 and 2023, respectively. There was no interest expense/(income) recognized on uncertain tax positions for the year ended December 31, 2022. Accrued interest payable was $ 1.7 million and $ 0.4 million as of December 31, 2024 and 2023, respectively.

 Tax Positions: During 2024 and 2023, Eversource did not resolve any of its uncertain tax positions.

 Open Tax Years: The following table summarizes Eversource, CL&P, NSTAR Electric, and PSNH's tax years that remain subject to examination by major tax jurisdictions as of December 31, 2024:

 Description
 Tax Years

 2022 - 2024(1)

 Connecticut
 2021 - 2024

 Massachusetts
 2022 - 2024

 New Hampshire
 2021 - 2024

 (1) The Company's Corporate Income Tax Returns for 2022 and 2023 were reviewed and closed as part of the annual IRS CAP program, with the exception for partnership investments of the Company. The Company was recently informed of an IRS audit of one of the partnership returns for the tax year 2022 and the IRS reserves the right to audit 2023. The Company recorded in the above Unrecognized Tax Benefits a reserve associated with this Partnership audit. These years remain open in relation to those audits.

 Eversource does not estimate to have an earnings impact related to unrecognized tax benefits during the next twelve months.

 13. COMMITMENTS AND CONTINGENCIES

 A. Environmental Matters
 Eversource, CL&P, NSTAR Electric and PSNH are subject to environmental laws and regulations intended to mitigate or remove the effect of past operations and improve or maintain the quality of the environment. These laws and regulations require the removal or the remedy of the effect on the environment of the disposal or release of certain specified hazardous substances at current and former operating sites. Eversource, CL&P, NSTAR Electric and PSNH have an active environmental auditing and training program and each believes it is substantially in compliance with all enacted laws and regulations.

 Environmental reserves are accrued when assessments indicate it is probable that a liability has been incurred and an amount can be reasonably estimated. The approach used estimates the liability based on the most likely action plan from a variety of available remediation options, including no action required or several different remedies ranging from establishing institutional controls to full site remediation and monitoring. These liabilities are estimated on an undiscounted basis and do not assume that the amounts are recoverable from insurance companies or other third parties. The environmental reserves include sites at different stages of discovery and remediation and do not include any unasserted claims.

 These reserve estimates are subjective in nature as they take into consideration several different remediation options at each specific site. The reliability and precision of these estimates can be affected by several factors, including new information concerning either the level of contamination at the site, the extent of Eversource's, CL&P's, NSTAR Electric's and PSNH's responsibility for remediation or the extent of remediation required, recently enacted laws and regulations or changes in cost estimates due to certain economic factors. It is possible that new information or future developments could require a reassessment of the potential exposure to required environmental remediation. As this information becomes available, management will continue to assess the potential exposure and adjust the reserves accordingly.

 The amounts recorded as environmental reserves are included in Other Current Liabilities and Other Long-Term Liabilities on the balance sheets and represent management's best estimate of the liability for environmental costs, and take into consideration site assessment, remediation and long-term monitoring costs. The environmental reserves also take into account recurring costs of managing hazardous substances and pollutants, mandated expenditures to remediate contaminated sites and any other infrequent and non-recurring clean-up costs. A reconciliation of the activity in the environmental reserves is as follows:

 CL&P
 PSNH

 Balance as of January 1, 2023
 $
 122.6
 $
 13.9
 $
 3.4
 $
 6.1

 Additions
 16.8
 2.6
 2.5
 1.7

 Payments/Reductions
 ( 11.2)
 ( 2.7)

 128.2
 13.8
 5.4
 7.6

 Additions
 11.0
 0.8
 1.9
 0.2

 Payments/Reductions
 ( 11.2)
 ( 1.5)

 $
 128.0
 $
 13.4
 $
 6.6
 $
 6.3

 The number of environmental sites for which remediation or long-term monitoring, preliminary site work or site assessment is being performed are as follows:

 CL&P
 PSNH

 2024

 2023

 Included in the number of sites and reserve amounts above are former MGP sites that were operated several decades ago and manufactured natural gas from coal and other processes, which resulted in certain by-products remaining in the environment that may pose a potential risk to human health and the environment, for which Eversource may have potential liability. The reserve balances related to these former MGP sites were $ 115.9 million and $ 117.1 million as of December 31, 2024 and 2023, respectively, and related primarily to the natural gas business segment.

 As of December 31, 2024, for 17 environmental sites ( 9 for CL&P and 2 for NSTAR Electric) that are included in the Company's reserve for environmental costs, management cannot reasonably estimate the exposure to loss in excess of the reserve, or range of loss, as these sites are under investigation and/or there is significant uncertainty as to what remedial actions, if any, the Company may be required to undertake. As of December 31, 2024, $ 30.7 million (including $ 5.7 million for CL&P and $ 1.4 million for NSTAR Electric) had been accrued as a liability for these sites.

 As of December 31, 2024, for 8 environmental sites (1 for NSTAR Electric) that are included in the Company's reserve for environmental costs, the information known and the nature of the remediation options allow for the Company to estimate the range of losses for environmental costs. As of December 31, 2024, $ 29.5 million has been accrued as a liability for these sites, which represents the low end of the range of the liabilities for environmental costs. Management believes that additional losses of up to approximately $ 17.5 million may be incurred in executing current remediation plans for these sites.

 As of December 31, 2024, for the remaining 40 environmental sites (including 6 for CL&P, 11 for NSTAR Electric and 8 for PSNH) that are included in the Company's reserve for environmental costs, the $ 67.8 million accrual (including $ 7.7 million for CL&P, $ 5.2 million for NSTAR Electric and $ 6.3 million for PSNH) represents management's best estimate of the probable liability and no additional loss is estimable at this time.

 PSNH, NSTAR Gas, EGMA and Yankee Gas have rate recovery mechanisms for MGP related environmental costs, therefore, changes in their respective environmental reserves do not impact Net Income. CL&P is allowed to defer certain environmental costs for future recovery. NSTAR Electric does not have a separate environmental cost recovery regulatory mechanism.

 B. Long-Term Contractual Arrangements
 Estimated Future Annual Costs: The estimated future annual costs of significant executed, non-cancelable, long-term contractual arrangements in effect as of December 31, 2024 are as follows:

 2025
 2026
 2027
 2028
 2029
 Total

 $
 771.8
 $
 865.2
 $
 919.9
 $
 918.0
 $
 785.5
 $
 6,289.9
 $
 10,550.3

 Natural Gas Procurement
 532.6
 486.1
 364.6
 308.1
 294.9
 1,004.4
 2,990.7

 Capacity and Purchased Power
 75.2
 2.9
 2.7
 2.7
 2.3
 2.3
 88.1

 Peaker CfDs
 28.3
 27.7
 23.1
 23.3
 24.1
 84.6
 211.1

 17.1
 18.8
 20.0
 20.9
 21.8
 22.6
 121.2

 Total
 $
 1,425.0
 $
 1,400.7
 $
 1,330.3
 $
 1,273.0
 $
 1,128.6
 $
 7,403.8
 $
 13,961.4

 CL&P

 2025
 2026
 2027
 2028
 2029
 Total

 $
 651.0
 $
 671.9
 $
 723.7
 $
 724.5
 $
 588.4
 $
 3,473.6
 $
 6,833.1

 Capacity
 72.4
 0.1
 —
 —
 —
 —
 72.5

 Peaker CfDs
 28.3
 27.7
 23.1
 23.3
 24.1
 84.6
 211.1

 6.8
 7.4
 7.9
 8.3
 8.6
 8.9
 47.9

 Total
 $
 758.5
 $
 707.1
 $
 754.7
 $
 756.1
 $
 621.1
 $
 3,567.1
 $
 7,164.6

 2025
 2026
 2027
 2028
 2029
 Total

 $
 120.8
 $
 193.3
 $
 196.2
 $
 193.5
 $
 197.1
 $
 2,816.3
 $
 3,717.2

 Purchased Power
 2.8
 2.8
 2.7
 2.7
 2.3
 2.3
 15.6

 6.7
 7.4
 7.9
 8.2
 8.6
 8.9
 47.7

 Total
 $
 130.3
 $
 203.5
 $
 206.8
 $
 204.4
 $
 208.0
 $
 2,827.5
 $
 3,780.5

 PSNH

 2025
 2026
 2027
 2028
 2029
 Total

 $
 3.6
 $
 4.0
 $
 4.2
 $
 4.4
 $
 4.6
 $
 4.8
 $
 25.6

 The contractual obligations table above does not include CL&P's, NSTAR Electric's or PSNH's standard/basic service contracts for the purchase of energy supply, the amounts of which vary with customers' energy needs.

 Renewable Energy Purchase Contracts: Renewable energy purchase contracts include non-cancellable commitments under contracts of CL&P and NSTAR Electric for the purchase of energy and capacity from renewable energy facilities. Such contracts extend through 2046 for CL&P and 2045 for NSTAR Electric. In 2024, the NHPUC approved the termination of a PPA for the purchase of capacity, renewable energy and RECs from a New Hampshire generation plant and there are no remaining long-term renewable energy purchase contracts at PSNH.

 Renewable energy purchase contracts include long-term commitments of NSTAR Electric pertaining to the Vineyard Wind LLC contract awarded under the Massachusetts Clean Energy 83C procurement solicitation. NSTAR Electric, along with other Massachusetts distribution companies, entered into 20-year contracts to purchase electricity generated by this 800 megawatt offshore wind project. Construction on the Vineyard Wind project commenced in 2022. Estimated energy costs under this contract are expected to begin when the facilities are in service in 2025 and range between $ 100 million and $ 200 million per year under NSTAR Electric's 20-year contract, totaling approximately $ 2.6 billion.

 As required by 2018 regulation, CL&P and UI each entered into PURA-approved ten-year contracts in 2019 to purchase a combined total of approximately 9 million MWh annually from the Millstone Nuclear Power Station generation facility, which represents a combined amount of approximately 50 percent of the facility's output (approximately 40 percent by CL&P). Also as required by 2018 regulation, CL&P and UI each entered into PURA-approved eight-year contracts in 2019 to purchase a combined amount of approximately 18 percent of the Seabrook Nuclear Power Plant's output (approximately 15 percent by CL&P) beginning January 1, 2022. The total estimated remaining future cost of the Millstone Nuclear Power Station and Seabrook Nuclear Power Plant energy purchase contracts are $ 2.6 billion and are reflected in the table above. As required by law, CL&P cannot use this power to satisfy its customers' supply obligations. CL&P sells the energy purchased under these contracts into the market and uses the proceeds from these energy sales to offset the contract costs. As the net costs under these contracts are recovered from customers in future rates, the contracts do not have an impact on the net income of CL&P. These contracts do not meet the definition of a derivative, and accordingly, the costs of these contracts are being accounted for as incurred.

 The contractual obligations table above does not include long-term commitments signed by CL&P and NSTAR Electric, as required by the PURA and the DPU, respectively, for the purchase of renewable energy and related products that are contingent on the future construction of energy facilities, such as the long-term commitments of NSTAR Electric pertaining to the Massachusetts Clean Energy 83D contract entered into in 2018.

 Natural Gas Procurement: Eversource's natural gas distribution businesses have long-term contracts for the purchase, transportation and storage of natural gas as part of its portfolio of supplies, which extend through 2045.

 Capacity and Purchased Power: These contracts include capacity CfDs with generation facilities at CL&P through 2026, and a purchase obligation for electricity which extends through 2031 for NSTAR Electric. CL&P's portion of the costs and benefits under these capacity contracts are recovered from, or refunded to, CL&P's customers.

 Peaker CfDs: CL&P, along with UI, has three peaker CfDs for a total of approximately 500 MW of peaking capacity through 2042. CL&P has a sharing agreement with UI, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits of these CfDs. The Peaker CfDs pay the generation facility owner the difference between capacity, forward reserve and energy market revenues and a cost-of-service payment stream for 30 years. The ultimate cost or benefit to CL&P under these contracts will depend on the costs of plant operation and the prices that the projects receive for capacity and other products in the ISO-NE markets. CL&P's portion of the amounts paid or received under the Peaker CfDs are recovered from, or refunded to, CL&P's customers.

 Transmission Support Commitments: Along with other New England utilities, CL&P, NSTAR Electric and PSNH have entered into agreements to support the costs of, and receive rights to use, transmission and terminal facilities that import electricity from the Hydro-Qu bec system in Canada. CL&P, NSTAR Electric and PSNH are obligated to pay, over a 20-year period ending in 2040, their proportionate shares of the annual operation and maintenance expenses and capital costs of those facilities.

 The total costs incurred under these agreements were as follows:

 2024
 2023
 2022

 $
 591.4
 $
 581.4
 $
 678.1

 Natural Gas Procurement
 695.0
 695.8
 1,042.8

 Capacity and Purchased Power
 70.5
 69.0
 61.6

 Peaker CfDs
 23.1
 20.1
 13.4

 16.7
 14.2
 12.7

 2024
 2023
 2022

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 $
 529.0
 $
 62.4
 $
 —
 $
 474.1
 $
 60.0
 $
 47.3
 $
 513.2
 $
 90.8
 $
 74.1

 Capacity and Purchased Power
 67.6
 2.9
 —
 65.5
 2.9
 0.6
 57.7
 3.0
 0.9

 Peaker CfDs
 23.1
 —
 —
 20.1
 —
 —
 13.4
 —
 —

 6.6
 6.6
 3.5
 5.6
 5.6
 3.0
 5.0
 5.0
 2.7

 C. Spent Nuclear Fuel Obligations - Yankee Companies
 CL&P, NSTAR Electric and PSNH have plant closure and fuel storage cost obligations to the Yankee Companies, which have each completed the physical decommissioning of their respective nuclear power facilities and are now engaged in the long-term storage of their spent fuel. The Yankee Companies fund these costs through litigation proceeds received from the DOE and, to the extent necessary, through wholesale, FERC-approved rates charged under power purchase agreements with several New England utilities, including CL&P, NSTAR Electric and PSNH. CL&P, NSTAR Electric and PSNH, in turn recover these costs from their customers through state regulatory commission-approved retail rates. The Yankee Companies collect amounts that management believes are adequate to recover the remaining plant closure and fuel storage cost estimates for the respective plants. Management believes CL&P and NSTAR Electric will recover their shares of these obligations from their customers. PSNH has recovered its total share of these costs from its customers.

 Spent Nuclear Fuel Litigation:
 The Yankee Companies have filed complaints against the DOE in the Court of Federal Claims seeking monetary damages resulting from the DOE's failure to accept delivery of, and provide for a permanent facility to store, spent nuclear fuel pursuant to the terms of the 1983 spent fuel and high-level waste disposal contracts between the Yankee Companies and the DOE. The court previously awarded the Yankee Companies damages for Phases I, II, III and IV of litigation resulting from the DOE's failure to meet its contractual obligations. These Phases covered damages incurred in the years 1998 through 2016, and the awarded damages have been received by the Yankee Companies with certain amounts of the damages refunded to their customers.

 DOE Phase V Damages - On March 25, 2021, each of the Yankee Companies filed a fifth set of lawsuits against the DOE in the Court of Federal Claims resulting from the DOE's failure to begin accepting spent nuclear fuel for disposal covering the years from 2017 to 2020. The Yankee Companies filed claims seeking monetary damages totaling $ 120.4 million for CYAPC, YAEC and MYAPC. Pursuant to a June 2, 2022 court order, the Yankee Companies were subsequently permitted to include monetary damages relating to the year 2021 in the DOE Phase V complaint. The Yankee Companies submitted a supplemental filing to include these costs of $ 33.1 million on June 8, 2022. In September 2024, the parties reached an agreement in principle to settle the Phase V complaint totaling $ 145 million for CYAPC, YAEC, and MYAPC. The settlement was approved on November 19, 2024 and the Department of Justice filed a Notice of Appeal on January 17, 2025 on an issue outside the scope of the settlement. Oral arguments are expected to be scheduled in the second half of 2025.

 D. Guarantees and Indemnifications
 In the normal course of business, Eversource parent provides credit assurances on behalf of its subsidiaries, including CL&P, NSTAR Electric and PSNH, in the form of guarantees. Management does not anticipate a material impact to net income or cash flows as a result of these various guarantees and indemnifications.

 Guarantees issued on behalf of unconsolidated entities, including equity method ownership interests, for which Eversource parent is the guarantor, are recorded at fair value as a liability on the balance sheet at the inception of the guarantee. The fair value of guarantees issued on behalf of unconsolidated entities are recorded within Other Long-Term Liabilities on the balance sheet, and were $ 1.2 million and $ 4.4 million as of December 31, 2024 and 2023, respectively. Eversource regularly reviews performance risk under these guarantee arrangements, and believes the likelihood of payments being required under the guarantees is remote. In the event it becomes probable that Eversource parent will be required to perform under the guarantee, the amount of probable payment will be recorded.

 On September 30, 2024, Eversource completed the sale of its 50 percent ownership share in the South Fork Wind and Revolution Wind projects to GIP. Under the agreement with GIP, Eversource's existing and certain additional credit support obligations for Revolution Wind are expected to roll off as the project completes construction. On July 9, 2024, Eversource completed the sale of its 50 percent ownership share of Sunrise Wind to rsted. Under the agreement with rsted, Eversource's existing credit support obligations for Sunrise Wind were either terminated or indemnified by rsted as a result of the sale.

 The following table summarizes Eversource parent's exposure to guarantees and indemnifications of its subsidiaries and affiliates to external parties, and primarily relates to its previously-owned offshore wind investments:

 As of December 31, 2024

 Company (Obligor)
 Description
 Maximum Exposure
(in millions)

 Revolution Wind, LLC and TurbineCo, LLC
 Offshore wind construction-related purchase agreements with third-party contractors (1)

 $
 357.0

 Eversource Investment LLC, Eversource Investment Service Company LLC and South Fork Class B Member, LLC
 Offshore wind funding and indemnification obligations (2)

 277.5

 Eversource Investment LLC
 Letters of Credit (3)

 5.3

 Eversource TEI LLC
 South Fork Wind Tax Equity (4)

 50.0

 South Fork Wind, LLC
 Power Purchase Agreement Security (5)

 7.1

 Various Eversource subsidiaries
 Surety bonds (6)

 30.7

 (1) Eversource parent issued guarantees on behalf of its previously 50 percent-owned affiliate, Revolution Wind, LLC, and on behalf of TurbineCo, LLC (successor in interest to North East Offshore, LLC (NEO)), under which Eversource parent agreed to guarantee each entity's performance of obligations under certain construction-related purchase agreements with third-party contractors, in an aggregate amount not to exceed $ 935.6 million. Eversource parent's obligations under the guarantees expire upon the earlier of (i) dates ranging between December 2024 and November 2027 and (ii) full performance of the guaranteed obligations.

 (2) Eversource parent issued guarantees on behalf of its wholly-owned subsidiary Eversource Investment LLC (EI), which held Eversource's previous investments in offshore wind-related equity method investments until sale, and on behalf of its previously 50 percent-owned affiliate, South Fork Class B Member, LLC, whereby Eversource parent will guarantee each entity's performance of certain funding obligations of the South Fork and Revolution Wind projects. Eversource parent also guaranteed certain indemnification obligations of EI associated with third party credit support for EI's investment in NEO. On September 30, 2024, Eversource parent issued a guaranty on behalf of its wholly-owned subsidiary, Eversource Investment Service Company LLC, whereby Eversource parent will guarantee Eversource Investment Service Company LLC's performance of certain indemnification obligations during the onshore construction phase of the Revolution Wind project, in an amount not to exceed $ 100.0 million. These guarantees will not exceed $ 1.62 billion and expire upon the full performance of the guaranteed obligations.

 (3) Eversource parent entered into a guarantee on behalf of EI, under which Eversource parent would guarantee EI's obligations under a letter of credit facility with a financial institution that EI may request in an aggregate amount of up to approximately $ 25 million. As of December 31, 2024, EI has issued two letters of credit on behalf of South Fork Wind, LLC and one letter of credit on behalf of Revolution Wind, LLC totaling $ 5.3 million. The guarantee will remain in effect until full performance of the guaranteed obligations. On January 24, 2025, the $ 1.0 million letter of credit issued on behalf of Revolution Wind, LLC was terminated.

 (4) Eversource parent issued a guarantee on behalf of its wholly-owned subsidiary, Eversource TEI LLC, whereby Eversource parent will guarantee Eversource TEI LLC's performance of certain obligations, in an amount not to exceed $ 50.0 million, in connection with any remaining obligations under the LLC agreement. Eversource parent's obligations expire upon the full performance of the guaranteed obligations.

 (5) Eversource parent issued a guarantee on behalf of its previously 50 percent-owned affiliate, South Fork Wind, LLC, whereby Eversource parent will guarantee South Fork Wind, LLC's performance of certain obligations, in an amount not to exceed $ 7.1 million, under a Power Purchase Agreement between the Long Island Power Authority and South Fork Wind, LLC (the Agreement). The guarantee expires upon the later of (i) the end of the Agreement term, January 2044, with the option to extend to January 2049 and (ii) full performance of the guaranteed obligations.

 (6) Surety bonds expire in 2025. Expiration dates reflect termination dates, the majority of which will be renewed or extended. Certain surety bonds contain credit ratings triggers that would require Eversource parent to post collateral in the event that the unsecured debt credit ratings of Eversource parent are downgraded.

 On September 30, 2024, Eversource entered into an agreement with GIP and rsted to contingently provide future credit support up to a maximum of $ 850 million in guarantees, if required, to support third party tax equity financing for Revolution Wind.

 E. FERC ROE Complaints
 Four separate complaints were filed at the FERC by combinations of New England state attorneys general, state regulatory commissions, consumer advocates, consumer groups, municipal parties and other parties (collectively, the Complainants). In each of the first three complaints, filed on October 1, 2011, December 27, 2012, and July 31, 2014, respectively, the Complainants challenged the NETOs' base ROE of 11.14 percent that had been utilized since 2005 and sought an order to reduce it prospectively from the date of the final FERC order and for the separate 15 -month complaint periods. In the fourth complaint, filed April 29, 2016, the Complainants challenged the NETOs' base ROE billed of 10.57 percent and the maximum ROE for transmission incentive (incentive cap) of 11.74 percent, asserting that these ROEs were unjust and unreasonable.

 The ROE originally billed during the period October 1, 2011 (beginning of the first complaint period) through October 15, 2014 consisted of a base ROE of 11.14 percent and incentives up to 13.1 percent. On October 16, 2014, FERC issued Opinion No. 531-A and set the base ROE at 10.57 percent and the incentive cap at 11.74 percent for the first complaint period. This was also effective for all prospective billings to customers beginning October 16, 2014. This FERC order was vacated on April 14, 2017 by the U.S. Court of Appeals for the D.C. Circuit (the Court).

 All amounts associated with the first complaint period have been refunded, which totaled $ 38.9 million (pre-tax and excluding interest) at Eversource and reflected both the base ROE and incentive cap prescribed by the FERC order. The refund consisted of $ 22.4 million for CL&P, $ 13.7 million for NSTAR Electric and $ 2.8 million for PSNH.

 Eversource has recorded a reserve of $ 39.1 million (pre-tax and excluding interest) for the second complaint period as of both December 31, 2024 and 2023. This reserve represents the difference between the billed rates during the second complaint period and a 10.57 percent base ROE and 11.74 percent incentive cap. The reserve consisted of $ 21.4 million for CL&P, $ 14.6 million for NSTAR Electric and $ 3.1 million for PSNH as of both December 31, 2024 and 2023.

 On October 16, 2018, FERC issued an order on all four complaints describing how it intends to address the issues that were remanded by the Court. FERC proposed a new framework to determine (1) whether an existing ROE is unjust and unreasonable and, if so, (2) how to calculate a replacement ROE. Initial briefs were filed by the NETOs, Complainants and FERC Trial Staff on January 11, 2019 and reply briefs were filed on March 8, 2019. The NETOs' brief was supportive of the overall ROE methodology determined in the October 16, 2018 order provided the FERC does not change the proposed methodology or alter its implementation in a manner that has a material impact on the results.

 The FERC order included illustrative calculations for the first complaint using FERC's proposed frameworks with financial data from that complaint. Those illustrative calculations indicated that for the first complaint period, for the NETOs, which FERC concludes are of average financial risk, the preliminary just and reasonable base ROE is 10.41 percent and the preliminary incentive cap on total ROE is 13.08 percent. If the results of the illustrative calculations were included in a final FERC order for each of the complaint periods, then a 10.41 percent base ROE and a 13.08 percent incentive cap would not have a significant impact on our financial statements for all of the complaint periods. These preliminary calculations are not binding and do not represent what we believe to be the most likely outcome of a final FERC order.

 On November 21, 2019, FERC issued Opinion No. 569 affecting the two pending transmission ROE complaints against the Midcontinent ISO (MISO) transmission owners, in which FERC adopted a new methodology for determining base ROEs. Various parties sought rehearing. On December 23, 2019, the NETOs filed supplementary materials in the NETOs' four pending cases to respond to this new methodology because of the uncertainty of the applicability to the NETOs' cases. On May 21, 2020, the FERC issued its order in Opinion No. 569-A on the rehearing of the MISO transmission owners' cases, in which FERC again changed its methodology for determining the MISO transmission owners' base ROEs. On November 19, 2020, the FERC issued Opinion No. 569-B denying rehearing of Opinion No. 569-A and reaffirmed the methodology previously adopted in Opinion No. 569-A. The new methodology differs significantly from the methodology proposed by FERC in its October 16, 2018 order to determine the NETOs' base ROEs in their four pending cases. FERC Opinion Nos. 569-A and 569-B were appealed to the Court. On August 9, 2022, the Court issued its decision vacating MISO ROE FERC Opinion Nos. 569, 569-A and 569-B and remanded to FERC to reopen the proceedings. The Court found that FERC's development of the new return methodology was arbitrary and capricious due to FERC's failure to offer a reasonable explanation for its decision to reintroduce the risk-premium financial model in its new methodology for calculating a just and reasonable return.

 On October 17, 2024, FERC issued an order on the remand of the MISO ROE proceedings. The order addressed the Court's decision that the reintroduction of the risk-premium financial model in the ROE methodology was arbitrary and capricious by removing the risk-premium financial model from the ROE methodology. The removal of the risk-premium financial model was the only revision to FERC's ROE methodology and resulted in a two-model approach utilizing the two-step discounted cash flow model and the capital asset pricing model. MISO was directed to provide refunds for the period November 12, 2013 to February 11, 2015 (the first MISO ROE complaint refund period) and for the period from September 28, 2016 (the date of FERC's order on the first MISO ROE complaint) to October 17, 2024 by December 1, 2025. The order also stated that FERC does not preclude the use of the risk-premium financial model in future proceedings if the parties can demonstrate that FERC's stated concerns around the inclusion of the model have been addressed.

 On November 13, 2024, the NETOs filed a supplemental brief in their four pending ROE proceedings to explain to FERC that it cannot apply the reasoning and methodologies of the MISO ROE case to the NETOs' cases due to the entirely different set of facts in the MISO and NETOs ROE proceedings. Doing so would violate the substance of the Court's April 14, 2017 order and would violate the legal standard required by the Federal Power Act.

 On February 4, 2025, the MISO transmission owners submitted a petition for review with the Court requesting review of the October 17, 2024 MISO ROE order on remand and a December 19, 2024 notice of denial of rehearing. The petition requests review of FERC's decision to retroactively backdate the MISO transmission owners' base ROE to the date of an earlier order that FERC abandoned when it issued Order No. 569, treat an underlying unlawful complaint as if it were legitimate, and order eight years of interest as part of the directed refunds.

 Given the significant uncertainty regarding the applicability of the FERC order in the MISO transmission owners' two complaint cases to the NETOs' pending four complaint cases due to the complex differences between the cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaints or subsequent periods at this time and Eversource cannot reasonably estimate any potential range of loss for any of the four complaint proceedings at this time. The resolution of these proceedings could have a material impact on the financial condition, results of operations, and cash flows.

 Eversource, CL&P, NSTAR Electric and PSNH currently record revenues at the 10.57 percent base ROE and incentive cap at 11.74 percent established in the October 16, 2014 FERC order.

 A change of 10 basis points to the base ROE used to establish the reserves would impact Eversource's after-tax earnings by an average of approximately $ 3 million for each of the four 15-month complaint periods.

 F. Litigation and Legal Proceedings
 Eversource, including CL&P, NSTAR Electric and PSNH, are involved in legal, tax and regulatory proceedings regarding matters arising in the ordinary course of business, which involve management's assessment to determine the probability of whether a loss will occur and, if probable, its best estimate of probable loss. The Company records and discloses losses when these losses are probable and reasonably estimable, and discloses matters when losses are probable but not estimable or when losses are reasonably possible. Legal costs related to the defense of loss contingencies are expensed as incurred.

 14. LEASES

 Eversource, including CL&P, NSTAR Electric and PSNH, has entered into lease agreements as a lessee for the use of land, office space, service centers, vehicles, information technology, and equipment. These lease agreements are classified as either finance or operating leases and the liability and right-of-use asset are recognized on the balance sheet at lease commencement. Leases with an initial term of 12 months or less are not recorded on the balance sheet and are recognized as lease expense on a straight-line basis over the lease term.

 Eversource determines whether or not a contract contains a lease based on whether or not it provides Eversource with the use of a specifically identified asset for a period of time, as well as both the right to direct the use of that asset and receive the significant economic benefits of the asset. Eversource has elected the practical expedient to not separate non-lease components from lease components and instead to account for both as a single lease component, with the exception of the information technology asset class where the lease and non-lease components are separated.

 The provisions of Eversource, CL&P, NSTAR Electric and PSNH lease agreements contain renewal options. The renewal options range from one year to twenty years. The renewal period is included in the measurement of the lease liability if it is reasonably certain that Eversource will exercise these renewal options.

 For leases entered into or modified after the January 1, 2019 implementation date of the leases standard under Topic 842, the discount rate utilized for classification and measurement purposes as of the inception date of the lease is based on each company's collateralized incremental interest rate to borrow over a comparable term for an individual lease because the rate implicit in the lease is not determinable.

 CL&P and PSNH entered into certain contracts for the purchase of energy that qualify as leases. These contracts do not have minimum lease payments and therefore are not recognized as a lease liability on the balance sheet and are not reflected in the future minimum lease payments table below. Expense related to these contracts is included as variable lease cost in the table below. The expense and long-term obligation for these contracts are also included in Note 13B, "Commitments and Contingencies - Long-Term Contractual Arrangements," to the financial statements. In 2024, these contracts at PSNH were terminated.

 The components of lease cost, prior to amounts capitalized, are as follows:

 2024
 2023
 2022

 Finance Lease Cost:

 Amortization of Right-of-use-Assets
 $
 6.4
 $
 4.8
 $
 8.3

 Interest on Lease Liabilities
 2.7
 2.0
 2.0

 Total Finance Lease Cost
 9.1
 6.8
 10.3

 Operating Lease Cost
 15.2
 11.4
 11.6

 Variable Lease Cost
 18.3
 69.2
 78.1

 Total Lease Cost
 $
 42.6
 $
 87.4
 100.0

 2024
 2023
 2022

 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH
 CL&P
 NSTAR
 PSNH

 Finance Lease Cost:

 Amortization of Right-of-use-Assets
 $
 1.7
 $
 0.2
 $
 —
 $
 —
 $
 0.2
 $
 —
 $
 —
 $
 0.2
 $
 0.1

 Interest on Lease Liabilities
 0.8
 0.6
 —
 —
 0.6
 —
 —
 0.6
 —

 Total Finance Lease Cost
 2.5
 0.8
 —
 —
 0.8
 —
 —
 0.8
 0.1

 Operating Lease Cost
 2.6
 5.3
 1.8
 0.7
 3.0
 0.4
 0.3
 2.3
 0.1

 Variable Lease Cost
 18.9
 —
 ( 0.6)
 21.9
 —
 47.3
 25.6
 —
 52.5

 Total Lease Cost
 $
 24.0
 $
 6.1
 $
 1.2
 $
 22.6
 $
 3.8
 $
 47.7
 $
 25.9
 $
 3.1
 $
 52.7

 Operating lease cost, net of the capitalized portion, is included in Operations and Maintenance (or Purchased Power, Purchased Natural Gas and Transmission expense for transmission leases) on the statements of income. Amortization of finance lease assets is included in Depreciation on the statements of income. Interest expense on finance leases is included in Interest Expense on the statements of income.

 Supplemental balance sheet information related to leases is as follows:

 As of December 31, 2024
 As of December 31, 2023

 Balance Sheet Classification
 CL&P
 PSNH
 CL&P
 PSNH

 Operating Leases:

 Right-of-use-Assets, Net
 $
 56.1
 $
 7.7
 $
 29.4
 $
 3.3
 $
 53.5
 $
 2.2
 $
 27.7
 $
 4.7

 Operating Lease Liabilities

 Current Portion
 $
 10.4
 $
 2.2
 $
 3.7
 $
 1.7
 $
 9.5
 $
 0.8
 $
 2.2
 $
 1.5

 Long-Term
 45.7
 5.5
 25.7
 1.6
 44.0
 1.4
 25.5
 3.2

 Total Operating Lease Liabilities
 $
 56.1
 $
 7.7
 $
 29.4
 $
 3.3
 $
 53.5
 $
 2.2
 $
 27.7
 $
 4.7

 Finance Leases:

 Right-of-use-Assets, Net
 $
 61.9
 $
 16.6
 $
 2.8
 $
 —
 $
 68.6
 $
 18.3
 $
 3.0
 $
 —

 Finance Lease Liabilities

 Current Portion
 $
 5.6
 $
 1.5
 $
 —
 $
 —
 $
 5.4
 $
 1.4
 $
 —
 $
 —

 Long-Term
 62.1
 15.6
 4.9
 —
 67.3
 16.9
 4.9
 —

 Total Finance Lease Liabilities
 $
 67.7
 $
 17.1
 $
 4.9
 $
 —
 $
 72.7
 $
 18.3
 $
 4.9
 $
 —

 The finance lease payments that NSTAR Electric will make over the next twelve months are entirely interest-related, due to escalating payments. As such, none of the finance lease payments over the next twelve months will reduce the finance lease liability.

 As of December 31, 2024, the operating lease balances attributable to the Aquarion water distribution business have been reclassified to Assets Held for Sale on the Eversource balance sheet. As of December 31, 2023, these balances were recorded within Other Long-Term Assets on the Eversource balance sheet. For further information, see Note 24, "Assets Held for Sale."

 Other information related to leases is as follows:

 2024
 2023

 CL&P
 PSNH
 CL&P
 PSNH

 Weighted-Average Remaining Lease Term (Years):

 Operating Leases

 Finance Leases
 —
 —

 Weighted-Average Discount Rate (Percentage):

 Operating Leases
 4.1
 %
 5.2
 %
 4.2
 %
 5.2
 %
 4.0
 %
 5.2
 %
 4.2
 %
 5.2
 %

 Finance Leases
 3.3
 %
 5.3
 %
 2.9
 %
 —
 %
 3.3
 %
 5.3
 %
 2.9
 %
 —
 %

 CL&P
 PSNH

 Cash Paid for Amounts Included in the Measurement of Lease Liabilities:

 Operating Cash Flows from Operating Leases
 $
 14.5
 $
 2.5
 $
 4.9
 $
 1.8

 Operating Cash Flows from Finance Leases
 2.6
 0.7
 0.7
 —

 Financing Cash Flows from Finance Leases
 5.2
 1.2
 —
 —

 Supplemental Non-Cash Information on Lease Liabilities:

 Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities
 15.3
 7.8
 5.7
 0.3

 Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities
 0.3
 —
 —
 —

 CL&P
 PSNH

 Cash Paid for Amounts Included in the Measurement of Lease Liabilities:

 Operating Cash Flows from Operating Leases
 $
 10.5
 $
 0.7
 $
 2.5
 $
 0.4

 Operating Cash Flows from Finance Leases
 2.0
 —
 0.6
 —

 Financing Cash Flows from Finance Leases
 3.9
 —
 —
 —

 Supplemental Non-Cash Information on Lease Liabilities:

 Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities
 12.8
 0.6
 7.0
 5.0

 Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities
 18.5
 18.3
 —
 —

 CL&P
 PSNH

 Cash Paid for Amounts Included in the Measurement of Lease Liabilities:

 Operating Cash Flows from Operating Leases
 $
 11.3
 $
 0.3
 $
 2.1
 $
 0.1

 Operating Cash Flows from Finance Leases
 2.0
 —
 0.6
 —

 Financing Cash Flows from Finance Leases
 3.9
 —
 —
 0.1

 Supplemental Non-Cash Information on Lease Liabilities:

 Right-of-use-Assets Obtained in Exchange for New Operating Lease Liabilities
 18.9
 2.4
 —
 —

 Right-of-use-Assets Obtained in Exchange for New Finance Lease Liabilities
 3.5
 —
 —
 —

 As of December 31, 2024, there are no lease agreements for Eversource, CL&P, NSTAR Electric or PSNH which have been executed but have yet to commence and have not been recorded as right-of-use assets.

 Future minimum lease payments, excluding variable costs, under long-term leases, as of December 31, 2024 are as follows:

 Operating Leases
 Finance Leases

 CL&P
 PSNH
 CL&P

 Year Ending December 31,

 2025
 $
 12.5
 $
 2.6
 $
 4.9
 $
 1.9
 $
 8.3
 $
 2.3
 $
 0.7

 2026
 11.0
 2.3
 4.9
 1.5
 7.9
 2.4
 0.7

 2027
 7.0
 1.8
 2.9
 0.1
 7.9
 2.5
 0.7

 2028
 6.6
 1.8
 2.6
 —
 7.3
 2.6
 0.7

 2029
 4.5
 —
 2.5
 —
 7.3
 2.6
 0.7

 26.2
 —
 22.2
 —
 50.5
 8.9
 10.2

 Future lease payments
 67.8
 8.5
 40.0
 3.5
 89.2
 21.3
 13.7

 Less amount representing interest
 11.7
 0.8
 10.6
 0.2
 21.5
 4.2
 8.8

 Present value of future minimum lease payments
 $
 56.1
 $
 7.7
 $
 29.4
 $
 3.3
 $
 67.7
 $
 17.1
 $
 4.9

 15. FAIR VALUE OF FINANCIAL INSTRUMENTS

 The following methods and assumptions were used to estimate the fair value of each of the following financial instruments:

 Preferred Stock, Long-Term Debt and Rate Reduction Bonds: The fair value of CL&P's and NSTAR Electric's preferred stock is based upon pricing models that incorporate interest rates and other market factors, valuations or trades of similar securities and cash flow projections. The fair value of long-term debt and RRB debt securities is based upon pricing models that incorporate quoted market prices for those issues or similar issues adjusted for market conditions, credit ratings of the respective companies and treasury benchmark yields. The fair values provided in the table below are classified as Level 2 within the fair value hierarchy. Carrying amounts and estimated fair values are as follows:

 CL&P
 PSNH

 Carrying Amount
 Fair Value
 Carrying
 Fair
Value
 Carrying
 Fair
Value
 Carrying
 Fair
Value

 As of December 31, 2024:

 Preferred Stock Not Subject to Mandatory Redemption
 $
 155.6
 $
 123.8
 $
 116.2
 $
 90.3
 $
 43.0
 $
 33.5
 $
 —
 $
 —

 26,704.8
 24,791.4
 5,111.1
 4,705.8
 5,094.9
 4,759.4
 1,732.1
 1,529.7

 Rate Reduction Bonds
 367.3
 352.1
 —
 —
 —
 —
 367.3
 352.1

 As of December 31, 2023:

 Preferred Stock Not Subject to Mandatory Redemption
 $
 155.6
 $
 122.2
 $
 116.2
 $
 90.4
 $
 43.0
 $
 31.8
 $
 —
 $
 —

 24,413.5
 22,855.2
 4,814.4
 4,572.0
 4,496.9
 4,273.7
 1,431.6
 1,292.6

 Rate Reduction Bonds
 410.5
 395.0
 —
 —
 —
 —
 410.5
 395.0

 Derivative Instruments and Marketable Securities: Derivative instruments and investments in marketable securities are carried at fair value. For further information, see Note 4, "Derivative Instruments," and Note 5, "Marketable Securities," to the financial statements.

 See Note 1H, "Summary of Significant Accounting Policies – Fair Value Measurements," for the fair value measurement policy and the fair value hierarchy.

 16. ACCUMULATED OTHER COMPREHENSIVE INCOME/(LOSS)

 The changes in accumulated other comprehensive income/(loss) by component, net of tax, are as follows:

 Qualified
Cash Flow
Hedging
Instruments
 Defined
Benefit
Plans
 Total
 Qualified
Cash Flow
Hedging
Instruments
Losses
on Marketable
Securities
 Defined
Benefit
Plans
 Total

 Balance as of January 1st
 $
 $
 ( 33.3)
 $
 ( 33.7)
 $
 $
 $
 ( 37.8)
 $
 ( 39.4)

 OCI Before Reclassifications
 —
 ( 2.5)
 ( 2.5)
 —
 —
 ( 8.8)
 ( 8.8)

 Amounts Reclassified from AOCI
 —
 9.7
 9.7
 —
 1.2
 13.3
 14.5

 Net OCI
 —
 7.2
 7.2
 —
 1.2
 4.5
 5.7

 Balance as of December 31st
 $
 $
 ( 26.1)
 $
 ( 26.5)
 $
 $
 —
 $
 ( 33.3)
 $
 ( 33.7)

 Defined benefit plan OCI amounts before reclassifications relate to actuarial gains and losses that arose during the year and were recognized in AOCI. The unamortized actuarial gains and losses and prior service costs on the defined benefit plans are amortized from AOCI into Other Income, Net over the average future employee service period, and are reflected in amounts reclassified from AOCI. The related tax effects of the defined benefit plan OCI amounts before reclassifications recognized in AOCI were net deferred tax assets of $ 0.4 million, $ 4.9 million and $ 1.3 million in 2024, 2023 and 2022, respectively.

 The following table sets forth the amounts reclassified from AOCI by component and the impacted line item on the statements of income:

 Amounts Reclassified from AOCI

 Statements of Income
Line Item Impacted

 2024
 2023
 2022

 Unrealized Loss on Marketable Securities
 —
 ( 1.6)
 —

 Tax Effect
 —
 0.4
 —

 Unrealized Loss on Marketable Securities, Net of Tax
 —
 —

 Defined Benefit Plan Costs:

 Amortization of Actuarial Losses
 ( 6.8)
 ( 9.0)
 Other Income, Net (1)

 Amortization of Prior Service Cost
 Other Income, Net (1)

 Settlement Losses
 ( 4.3)
 ( 12.4)
 —
 Other Income, Net (1)

 Total Defined Benefit Plan Costs
 ( 11.4)
 ( 19.7)
 ( 9.3)

 Tax Effect
 1.7
 6.4
 2.3

 Defined Benefit Plan Costs, Net of Tax
 ( 9.7)
 ( 13.3)

 Total Amounts Reclassified from AOCI, Net of Tax
 $
 ( 9.7)
 $
 ( 14.5)
 $

 (1) These amounts are included in the computation of net periodic Pension, SERP and PBOP costs. See Note 1L, "Summary of Significant Accounting Policies – Other Income, Net" and Note 11A, "Employee Benefits – Pension Benefits and Postretirement Benefits Other Than Pension," for further information.

 17. DIVIDEND RESTRICTIONS

 Eversource parent's ability to pay dividends may be affected by certain state statutes, the ability of its subsidiaries to pay common dividends and the leverage restriction tied to its consolidated total indebtedness to total capitalization ratio requirement in its revolving credit agreements. Pursuant to the joint revolving credit agreement of Eversource, CL&P, PSNH, NSTAR Gas, Yankee Gas, EGMA and Aquarion Water Company of Connecticut, and to the NSTAR Electric revolving credit agreement, Eversource is required to maintain consolidated total indebtedness to total capitalization ratio of no greater than 70 percent at the end of each fiscal quarter and each other company is required to maintain consolidated total indebtedness to total capitalization ratio of no greater than 65 percent at the end of each fiscal quarter. As of December 31, 2024, all companies were in compliance with such covenant and in compliance with all such provisions of the revolving credit agreements that may restrict the payment of dividends as of December 31, 2024.

 The Retained Earnings balances subject to dividend restrictions were $ 3.93 billion for Eversource, $ 2.82 billion for CL&P, $ 3.13 billion for NSTAR Electric and $ 808.7 million for PSNH as of December 31, 2024.

 CL&P, NSTAR Electric and PSNH are subject to Section 305 of the Federal Power Act that makes it unlawful for a public utility to make or pay a dividend from any funds "properly included in its capital account." Management believes that this Federal Power Act restriction, as applied to CL&P, NSTAR Electric and PSNH, would not be construed or applied by the FERC to prohibit the payment of dividends from retained earnings for lawful and legitimate business purposes. In addition, certain state statutes may impose additional limitations on such companies and, including but not limited to, on NSTAR Gas, Yankee Gas, EGMA, and Aquarion's operating companies. Such state law restrictions do not restrict the payment of dividends from retained earnings or net income.

 18. COMMON SHARES

 The following table sets forth the Eversource parent common shares and the shares of common stock of CL&P, NSTAR Electric and PSNH that were authorized and issued, as well as the respective per share par values:

 Shares

Par Value
 Authorized as of December 31, 2024 and 2023
 Issued as of December 31,

 2024
 2023

 $
 410,000,000
 375,724,367
 359,984,073

 CL&P
 $
 24,500,000

 $
 100,000,000

 PSNH
 $
 100,000,000

 Common Share Issuances: Eversource had an equity distribution agreement pursuant to which it could offer and sell up to $ 1.2 billion of its common shares from time to time through an "at-the-market" (ATM) equity offering program. Eversource issued and sold its common shares through its sales agents during the term of this agreement. Shares were offered in transactions on the New York Stock Exchange, in the over-the-counter market, through negotiated transactions or otherwise. Sales were made at either market prices prevailing at the time of sale, at prices related to such prevailing market prices or at negotiated prices. In 2024, Eversource issued 15,740,294 common shares, which resulted in proceeds of $ 989.4 million, net of issuance costs. Eversource used the net proceeds received for general corporate purposes. In 2023, no shares were issued under this agreement. Eversource completed the program in October 2024.

 Treasury Shares: As of December 31, 2024 and 2023, there were 9,116,315 and 10,443,807 Eversource common shares held as treasury shares, respectively. As of December 31, 2024 and 2023, there were 366,608,052 and 349,540,266 Eversource common shares outstanding, respectively.

 Acquisition of The Torrington Water Company: On October 3, 2022, Aquarion acquired The Torrington Water Company (TWC) following the receipt of all required approvals. The acquisition was structured as a stock-for-stock merger and Eversource issued 925,264 treasury shares at closing for a purchase price of $ 72.1 million.

 Eversource issues treasury shares to satisfy awards under the Company's incentive plans, shares issued under the dividend reinvestment and share purchase plan, and matching contributions under the Eversource 401k Plan. Eversource also issued treasury shares for its October 2022 water business acquisitions. The issuance of treasury shares represents a non-cash transaction, as the treasury shares were used to fulfill Eversource's obligations that require the issuance of common shares.

 On May 3, 2023, shareholders voted to increase the authorized common shares from 380,000,000 shares to 410,000,000 shares.

 19. PREFERRED STOCK NOT SUBJECT TO MANDATORY REDEMPTION

 The CL&P and NSTAR Electric preferred stock is not subject to mandatory redemption and is presented as a noncontrolling interest of a subsidiary in Eversource's financial statements.

CL&P is authorized to issue up to 9,000,000 shares of preferred stock, par value $ 50 per share, and NSTAR Electric is authorized to issue 2,890,000 shares of preferred stock, par value $ 100 per share. Holders of preferred stock of CL&P and NSTAR Electric are entitled to receive cumulative dividends in preference to any payment of dividends on the common stock. Upon liquidation, holders of preferred stock of CL&P and NSTAR Electric are entitled to receive a liquidation preference before any distribution to holders of common stock in an amount equal to the par value of the preferred stock plus accrued and unpaid dividends. If the net assets were to be insufficient to pay the liquidation preference in full, then the net assets would be distributed ratably to all holders of preferred stock. The preferred stock of CL&P and NSTAR Electric is subject to optional redemption by the CL&P and NSTAR Electric Boards of Directors at any time.

 Details of preferred stock not subject to mandatory redemption are as follows (in millions, except in redemption price and shares):

 Redemption Price
 Shares Outstanding as of December 31,

 Series
 2024
 2023
 2024
 2023

 CL&P

 $ 1.90
 Series of 1947
 $
 52.50
 163,912
 163,912
 $
 8.2
 $
 8.2

 $ 2.00
 Series of 1947
 $
 54.00
 336,088
 336,088
 16.8
 16.8

 $ 2.04
 Series of 1949
 $
 52.00
 5.0
 5.0

 $ 2.20
 Series of 1949
 $
 52.50
 10.0
 10.0

 3.90 %
 Series of 1949
 $
 50.50
 160,000
 160,000
 8.0
 8.0

 $ 2.06
 Series E of 1954
 $
 51.00
 10.0
 10.0

 $ 2.09
 Series F of 1955
 $
 51.00
 5.0
 5.0

 4.50 %
 Series of 1956
 $
 50.75
 104,000
 104,000
 5.2
 5.2

 4.96 %
 Series of 1958
 $
 50.50
 5.0
 5.0

 4.50 %
 Series of 1963
 $
 50.50
 160,000
 160,000
 8.0
 8.0

 5.28 %
 Series of 1967
 $
 51.43
 10.0
 10.0

 $ 3.24
 Series G of 1968
 $
 51.84
 15.0
 15.0

 6.56 %
 Series of 1968
 $
 51.44
 10.0
 10.0

 Total CL&P

 2,324,000
 2,324,000
 $
 116.2
 $
 116.2

 4.25 %
 Series of 1956
 $
 103.625
 180,000
 180,000
 $
 18.0
 $
 18.0

 4.78 %
 Series of 1958
 $
 102.80
 25.0
 25.0

 Total NSTAR Electric

 430,000
 430,000
 $
 43.0
 $
 43.0

 Fair Value Adjustment due to Merger with NSTAR

 ( 3.6)
 ( 3.6)

 Total Eversource - Noncontrolling Interest - Preferred Stock of Subsidiaries
 $
 155.6
 $
 155.6

 20. COMMON SHAREHOLDERS' EQUITY AND NONCONTROLLING INTERESTS

 Dividends on the preferred stock of CL&P and NSTAR Electric totaled $ 7.5 million for each of the years ended December 31, 2024, 2023 and 2022. These dividends were presented as Net Income Attributable to Noncontrolling Interests on the Eversource statements of income. Noncontrolling Interest – Preferred Stock of Subsidiaries on the Eversource balance sheets totaled $ 155.6 million as of December 31, 2024 and 2023. On the Eversource balance sheets, Common Shareholders' Equity was fully attributable to Eversource parent and Noncontrolling Interest – Preferred Stock of Subsidiaries was fully attributable to the noncontrolling interest.

 For the years ended December 31, 2024, 2023 and 2022, there was no change in ownership of the common equity of CL&P and NSTAR Electric.

 21. EARNINGS/(LOSS) PER SHARE

 Basic earnings/(loss) per share is computed based upon the weighted average number of common shares outstanding during each period. Diluted earnings/(loss) per share is computed on the basis of the weighted average number of common shares outstanding plus the potential dilutive effect of certain share-based compensation awards as if they were converted into outstanding common shares. The dilutive effect of unvested RSU and performance share awards is calculated using the treasury stock method. RSU and performance share awards are included in basic weighted average common shares outstanding as of the date that all necessary vesting conditions have been satisfied.

 For the years ended December 31, 2024, 2023 and 2022, there were no antidilutive share awards excluded from the computation.

 The following table sets forth the components of basic and diluted earnings/(loss) per share:

 (Millions of Dollars, except share information)

 2024
 2023
 2022

 Net Income/(Loss) Attributable to Common Shareholders
 $
 811.7
 $
 ( 442.2)
 $
 1,404.9

 Weighted Average Common Shares Outstanding:

 Basic
 357,482,965
 349,580,638
 346,783,444

 Dilutive Effect
 296,443
 259,843
 463,324

 Diluted
 357,779,408
 349,840,481
 347,246,768

 Basic Earnings/(Loss) Per Common Share
 $
 2.27
 $
 ( 1.27)
 $
 4.05

 Diluted Earnings/(Loss) Per Common Share
 $
 2.27
 $
 ( 1.26)
 $
 4.05

 22. REVENUES

 Revenue is recognized when promised goods or services (referred to as performance obligations) are transferred to customers in an amount that reflects the consideration to which the company expects to be entitled in exchange for those goods or services. A five-step model is used for recognizing and measuring revenue from contracts with customers, which includes identifying the contract with the customer, identifying the performance obligations promised within the contract, determining the transaction price (the amount of consideration to which the company expects to be entitled), allocating the transaction price to the performance obligations and recognizing revenue when (or as) the performance obligation is satisfied.

 The following tables present operating revenues disaggregated by revenue source:

 Other
 Total

 Revenues from Contracts with Customers

 Retail Tariff Sales

 Residential
 $
 4,904.8
 $
 1,129.1
 $
 —
 $
 150.4
 $
 —
 $
 —
 $
 6,184.3

 Commercial
 2,973.3
 588.0
 —
 70.3
 —
 ( 7.7)
 3,623.9

 Industrial
 389.0
 172.5
 —
 4.7
 —
 ( 22.4)
 543.8

 Total Retail Tariff Sales Revenues
 8,267.1
 1,889.6
 —
 225.4
 —
 ( 30.1)
 10,352.0

 Wholesale Transmission Revenues
 —
 —
 2,032.4
 —
 —
 ( 1,529.3)
 503.1

 Wholesale Market Sales Revenues
 658.9
 161.9
 —
 4.2
 —
 —
 825.0

 Other Revenues from Contracts with Customers
 92.2
 5.1
 13.9
 5.7
 1,701.3
 ( 1,694.6)
 123.6

 Reserve for Revenues Subject to Refund
 —
 —
 —
 ( 1.9)
 —
 —
 ( 1.9)

 Total Revenues from Contracts with Customers
 9,018.2
 2,056.6
 2,046.3
 233.4
 1,701.3
 ( 3,254.0)
 11,801.8

 Alternative Revenue Programs
 28.7
 44.5
 74.2
 ( 5.3)
 —
 ( 67.2)
 74.9

 Other Revenues
 19.6
 2.8
 0.5
 1.2
 —
 —
 24.1

 $
 9,066.5
 $
 2,103.9
 $
 2,121.0
 $
 229.3
 $
 1,701.3
 $
 ( 3,321.2)
 $
 11,900.8

 Other
 Total

 Revenues from Contracts with Customers

 Retail Tariff Sales

 Residential
 $
 5,054.2
 $
 1,145.4
 $
 —
 $
 144.7
 $
 —
 $
 —
 $
 6,344.3

 Commercial
 2,893.2
 637.7
 —
 69.8
 —
 ( 4.8)
 3,595.9

 Industrial
 352.4
 186.8
 —
 4.5
 —
 ( 19.7)
 524.0

 Total Retail Tariff Sales Revenues
 8,299.8
 1,969.9
 —
 219.0
 —
 ( 24.5)
 10,464.2

 Wholesale Transmission Revenues
 —
 —
 1,777.5
 —
 —
 ( 1,310.5)
 467.0

 Wholesale Market Sales Revenues
 625.0
 206.7
 —
 3.9
 —
 —
 835.6

 Other Revenues from Contracts with Customers
 82.6
 5.6
 14.6
 8.1
 1,636.6
 ( 1,628.0)
 119.5

 Amortization of Revenues Subject to Refund
 —
 —
 4.3
 —
 —
 —
 4.3

 Total Revenues from Contracts with Customers
 9,007.4
 2,182.2
 1,796.4
 231.0
 1,636.6
 ( 2,963.0)
 11,890.6

 Alternative Revenue Programs
 ( 54.3)
 35.5
 118.9
 0.4
 —
 ( 106.5)
 ( 6.0)

 Other Revenues
 20.4
 4.0
 0.6
 1.1
 —
 —
 26.1

 $
 8,973.5
 $
 2,221.7
 $
 1,915.9
 $
 232.5
 $
 1,636.6
 $
 ( 3,069.5)
 $
 11,910.7

 Other
 Total

 Revenues from Contracts with Customers

 Retail Tariff Sales

 Residential
 $
 4,796.1
 $
 1,204.9
 $
 —
 $
 141.7
 $
 —
 $
 —
 $
 6,142.7

 Commercial
 2,903.3
 648.5
 —
 66.5
 —
 ( 4.1)
 3,614.2

 Industrial
 374.9
 199.7
 —
 4.7
 —
 ( 20.1)
 559.2

 Total Retail Tariff Sales Revenues
 8,074.3
 2,053.1
 —
 212.9
 —
 ( 24.2)
 10,316.1

 Wholesale Transmission Revenues
 —
 —
 1,700.5
 —
 —
 ( 1,264.5)
 436.0

 Wholesale Market Sales Revenues
 1,190.9
 140.8
 —
 3.8
 —
 —
 1,335.5

 Other Revenues from Contracts with Customers
 72.3
 5.6
 14.1
 8.4
 1,435.5
 ( 1,425.3)
 110.6

 Amortization of/(Reserve for) Revenues
 Subject to Refund
 72.0
 —
 0.7
 —
 —
 72.0

 Total Revenues from Contracts with Customers
 9,409.5
 2,199.5
 1,715.3
 224.4
 1,435.5
 ( 2,714.0)
 12,270.2

 Alternative Revenue Programs
 ( 15.4)
 14.8
 92.7
 ( 2.5)
 —
 ( 84.3)
 5.3

 Other Revenues
 11.2
 1.3
 0.7
 0.6
 —
 —
 13.8

 $
 9,405.3
 $
 2,215.6
 $
 1,808.7
 $
 222.5
 $
 1,435.5
 $
 ( 2,798.3)
 $
 12,289.3

 2024
 2023
 2022

 CL&P
 PSNH
 CL&P
 PSNH
 CL&P
 PSNH

 Revenues from Contracts with Customers

 Retail Tariff Sales

 Residential
 $
 2,493.7
 $
 1,771.8
 $
 639.3
 $
 2,597.8
 $
 1,691.0
 $
 765.4
 $
 2,397.2
 $
 1,601.8
 $
 797.1

 Commercial
 1,164.8
 1,466.7
 343.6
 1,082.1
 1,442.3
 369.6
 1,067.9
 1,457.4
 380.8

 Industrial
 164.2
 118.1
 106.7
 137.2
 123.2
 92.0
 146.4
 135.8
 92.7

 Total Retail Tariff Sales Revenues
 3,822.7
 3,356.6
 1,089.6
 3,817.1
 3,256.5
 1,227.0
 3,611.5
 3,195.0
 1,270.6

 Wholesale Transmission Revenues
 870.8
 794.1
 367.5
 794.7
 692.0
 290.8
 755.1
 670.4
 275.0

 Wholesale Market Sales Revenues
 491.9
 131.1
 35.9
 429.1
 131.8
 64.1
 873.7
 215.0
 102.2

 Other Revenues from Contracts
 with Customers
 36.7
 50.2
 21.2
 32.4
 49.1
 18.1
 30.2
 46.9
 11.8

 Amortization of Revenues Subject
 to Refund
 —
 —
 —
 4.3
 —
 —
 72.7
 —
 —

 Total Revenues from Contracts
 with Customers
 5,222.1
 4,332.0
 1,514.2
 5,077.6
 4,129.4
 1,600.0
 5,343.2
 4,127.3
 1,659.6

 Alternative Revenue Programs
 45.4
 36.7
 20.8
 66.8
 ( 52.0)
 49.8
 56.5
 0.7
 20.1

 Other Revenues
 9.0
 8.5
 2.6
 9.6
 8.4
 3.0
 1.8
 7.2
 2.9

 ( 661.5)
 ( 656.3)
 ( 243.1)
 ( 575.2)
 ( 570.3)
 ( 204.9)
 ( 583.8)
 ( 552.1)
 ( 207.8)

 $
 4,615.0
 $
 3,720.9
 $
 1,294.5
 $
 4,578.8
 $
 3,515.5
 $
 1,447.9
 $
 4,817.7
 $
 3,583.1
 $
 1,474.8

 Retail Tariff Sales: Regulated utilities provide products and services to their regulated customers under rates, pricing, payment terms and conditions of service, regulated by each state regulatory agency. The arrangement whereby a utility provides commodity service to a customer for a price approved by the respective state regulatory commission is referred to as a tariff sale contract, and the tariff governs all aspects of the provision of regulated services by utilities. The majority of revenue for Eversource, CL&P, NSTAR Electric and PSNH is derived from regulated retail tariff sales for the sale and distribution of electricity, natural gas and water to residential, commercial and industrial retail customers.

 The utility's performance obligation for the regulated tariff sales is to provide electricity, natural gas or water to the customer as demanded. The promise to provide the commodity represents a single performance obligation, as it is a promise to transfer a series of distinct goods or services that are substantially the same and that have the same pattern of transfer to the customer. Revenue is recognized over time as the customer simultaneously receives and consumes the benefits provided by the utility, and the utility satisfies its performance obligation. Revenue is recognized based on the output method as there is a directly observable output to the customer (electricity, natural gas or water units delivered to the customer and immediately consumed). Each Eversource utility is entitled to be compensated for performance completed to date (service taken by the customer) until service is terminated.

 In regulated tariff sales, the transaction prices are the rates approved by the respective state regulatory commissions. In general, rates can only be changed through formal proceedings with the state regulatory commissions. These rates are designed to recover the costs to provide service to customers and include a return on investment. Regulatory commission-approved tracking mechanisms are included in these rates and are also used to recover, on a fully-reconciling basis, certain costs, such as the procurement of energy supply, state mandated energy purchase agreements, retail transmission charges, energy efficiency program costs, net metering for distributed generation, and restructuring and stranded costs, among others. These tracking mechanisms result in rates being changed periodically to ensure recovery of actual costs incurred and the refund of any overcollection of costs.

 Electric customers may elect to purchase electricity from each Eversource electric utility or may contract separately with a competitive third party supplier. Certain eligible natural gas customers may elect to purchase natural gas from each Eversource natural gas utility or may contract separately with a gas supply operator. Revenue is not recorded for the sale of the electricity or the natural gas commodity to customers who have contracted separately with these suppliers, only the delivery to a customer, as the utility is acting as an agent on behalf of the supplier.

 Wholesale Transmission Revenues: The Eversource electric transmission-owning companies (CL&P, NSTAR Electric and PSNH) each own and maintain transmission facilities that are part of an interstate power transmission grid over which electricity is transmitted throughout New England. CL&P, NSTAR Electric and PSNH, as well as most other New England utilities, are parties to a series of agreements that provide for coordinated planning and operation of the region's transmission facilities and the rules by which they acquire transmission services. The Eversource electric transmission-owning companies have a combination of FERC-approved regional and local formula rates that are designed to work in tandem to recover all their transmission costs. These rates are part of the ISO-NE Tariff. Regional rates recover the costs of higher voltage transmission facilities that benefit the region and are collected from all New England transmission customers, including the Eversource distribution businesses. Eversource's local rates generally recover the costs of transmission facilities that do not provide a benefit to the region, and are collected from Eversource's distribution businesses and other transmission customers. The distribution businesses of Eversource, in turn, recover the FERC approved charges from retail customers through annual tracking mechanisms, which are retail tariff sales.

 The utility's performance obligation for regulated wholesale transmission sales is to provide transmission services to the customer as demanded. The promise to provide transmission service represents a single performance obligation. The transaction prices are the transmission rate formulas as defined by the ISO-NE Tariff and are regulated and established by FERC. Wholesale transmission revenue is recognized over time as the performance obligation is completed, which occurs as transmission services are provided to customers. The revenue is recognized based on the output method. Each Eversource utility is entitled to be compensated for performance completed to date (e.g., use of the transmission system by the customer).

 Wholesale Market Sales Revenues: Wholesale market sales transactions include sales of energy and energy-related products into the ISO-NE wholesale electricity market, sales of natural gas to third party marketers, and also the sale of RECs to various counterparties. ISO-NE oversees the region's wholesale electricity market and administers the transactions and terms and conditions, including payment terms, which are established in the ISO-NE tariff, between the buyers and sellers in the market. Pricing is set by the wholesale market. The wholesale transactions in the ISO-NE market occur on a day-ahead basis or a real-time basis (daily) and are, therefore, short-term. Transactions are tracked and reported by ISO-NE net by the hour, which is the net hourly position of energy sales and purchases by each market participant. The performance obligation for ISO-NE energy transactions is defined to be the net by hour transaction. Revenue is recognized when the performance obligation for these energy sales transactions is satisfied, which is when the sale occurs and the energy is transferred to the customer. For sales of natural gas, transportation, and natural gas pipeline capacity to third party marketers, revenue is recognized when the performance obligation is satisfied at the point in time the sale occurs and the natural gas or related product is transferred to the marketer. RECs are sold to various counterparties, and revenue is recognized when the performance obligation is satisfied upon transfer of title to the customer through the New England Power Pool Generation Information System. Wholesale transactions also include the sale of CL&P's, NSTAR Electric's and PSNH's transmission rights associated with their proportionate equity ownership share in the transmission lines of the Hydro-Qu bec system in Canada.

 Other Revenues from Contracts with Customers: Other revenues from contracts with customers primarily include property rentals that are not deemed leases. These revenues are generally recognized on a straight-line basis over time as the service is provided to the customer. Other revenues also include revenues from Eversource's service company, which is eliminated in consolidation.

 Amortization of/(Reserve for) Revenues Subject to Refund: A reserve is recorded as a reduction to revenues when future refunds to customers are deemed probable. The reserve is reversed as refunds are provided to customers in rates. Amortization of Revenues Subject to Refund within the Electric Distribution segment in 2022 represents the reversal of a 2021 reserve at CL&P established to provide bill credits to customers as a result of the settlement agreement on October 1, 2021 and a storm performance penalty assessed by PURA. The reserve of $ 93.4 million was reversed as customer credits were distributed to CL&P's customers in retail electric rates in 2021 and 2022.

 Alternative Revenue Programs: In accordance with accounting guidance for rate-regulated operations, certain of Eversource's utilities' rate making mechanisms qualify as alternative revenue programs (ARPs) if they meet specified criteria, in which case revenues may be recognized prior to billing based on allowed levels of collection in rates. Eversource's utility companies recognize revenue and record a regulatory asset or liability once the condition or event allowing for the automatic adjustment of future rates occurs. ARP revenues include both the recognition of the deferral adjustment to ARP revenues, when the regulator-specified condition or event allowing for additional billing or refund has occurred, and an equal and offsetting reversal of the ARP deferral to revenues as those amounts are reflected in the price of service in subsequent periods.

 Eversource's ARPs include the revenue decoupling mechanism, the annual reconciliation adjustment to transmission formula rates, and certain capital tracker mechanisms. Certain Eversource electric, natural gas and water companies, including CL&P and NSTAR Electric, have revenue decoupling mechanisms approved by a regulatory commission (decoupled companies). Decoupled companies' distribution revenues are not directly based on sales volumes. The decoupled companies reconcile their annual base distribution rate recovery to pre-established levels of baseline distribution delivery service revenues, with any difference between the allowed level of distribution revenue and the actual amount realized adjusted through subsequent rates. The transmission formula rates provide for the annual reconciliation and recovery or refund of estimated costs to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refund to, transmission customers. This transmission deferral reconciles billed transmission revenues to the revenue requirement for our transmission businesses.

 Other Revenues: Other Revenues include certain fees charged to customers that are not considered revenue from contracts with customers. Other revenues also include lease revenues under lessor accounting guidance of $ 2.5 million ($ 0.5 million at CL&P and $ 1.2 million at NSTAR Electric), $ 4.6 million ($ 0.7 million at CL&P and $ 2.5 million at NSTAR Electric), and $ 4.0 million, ($ 0.8 million at CL&P and $ 2.5 million at NSTAR Electric) for the years ended December 31, 2024, 2023 and 2022, respectively.

 Intercompany Eliminations: Intercompany eliminations are primarily related to the Eversource electric transmission revenues that are derived from ISO-NE regional transmission charges to the distribution businesses of CL&P, NSTAR Electric and PSNH that recover the costs of the wholesale transmission business, and revenues from Eversource's service company. Intercompany revenues and expenses between the Eversource wholesale transmission businesses and the Eversource distribution businesses and from Eversource's service company are eliminated in consolidation and included in "Eliminations" in the tables above.

 Receivables: Receivables, Net on the balance sheet primarily includes trade receivables from retail customers and customers related to wholesale transmission contracts, wholesale market sales, sales of RECs, and property rentals. In general, retail tariff customers and wholesale transmission customers are billed monthly and the payment terms are generally due and payable upon receipt of the bill.

 Unbilled Revenues: Unbilled Revenues on the balance sheet represent estimated amounts due from retail customers for electricity, natural gas or water delivered to customers but not yet billed. The utility company has satisfied its performance obligation and the customer has received and consumed the commodity as of the balance sheet date, and therefore, the utility company records revenue for those services in the period the services were provided. Only the passage of time is required before the company is entitled to payment for the satisfaction of the performance obligation. Payment from customers is due monthly as services are rendered and amounts are billed. Actual amounts billed to customers when meter readings become available may vary from the estimated amount.

 Unbilled revenues are recognized by allocating estimated unbilled sales volumes to the respective customer classes, and then applying an estimated rate by customer class to those sales volumes. Unbilled revenue estimates reflect seasonality, weather, customer usage patterns, customer rates in effect for customer classes, and the timing of customer billing. The companies that have a decoupling mechanism record a regulatory deferral to reflect the actual allowed amount of revenue associated with their respective decoupled distribution rate design.

 Practical Expedients: Eversource has elected practical expedients in the accounting guidance that allow the company to record revenue in the amount that the company has a right to invoice, if that amount corresponds directly with the value to the customer of the company's performance to date, and not to disclose related unsatisfied performance obligations. Retail and wholesale transmission tariff sales fall into this category, as these sales are recognized as revenue in the period the utility provides the service and completes the performance obligation, which is the same as the monthly amount billed to customers. There are no other material revenue streams for which Eversource has unsatisfied performance obligations.

 23. SEGMENT INFORMATION

 Eversource is organized into the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reportable segments and Other based on a combination of factors, including the characteristics of each segments' services, the sources of operating revenues and expenses and the regulatory environment in which each segment operates. The Electric Distribution segment consists of the rate-regulated distribution businesses of CL&P, NSTAR Electric and PSNH, and includes the results of NSTAR Electric's solar power facilities. The Electric Transmission segment consists of the rate-regulated electric transmission businesses of CL&P, NSTAR Electric and PSNH. The Natural Gas Distribution segment consists of the rate-regulated businesses of Yankee Gas, NSTAR Gas and EGMA. The Water Distribution segment consists of the rate-regulated business of Aquarion. These reportable segments represent substantially all of Eversource's total consolidated revenues. Revenues from the sale of electricity, natural gas and water primarily are derived from residential, commercial and industrial customers and are not dependent on any single customer.

 Eversource's reportable segments are determined based upon the level at which Eversource's chief operating decision maker assesses performance and makes decisions about the allocation of company resources. The chief operating decision maker uses the net income of each reportable segment to evaluate return generated from assets and decide how to reinvest profits and allocate resources, to monitor budget-to-actual results, in the planning and forecasting process, in determining compensation achievement, and in benchmarking to Eversource's peers. Eversource's chief operating decision maker is its chief executive officer. The accounting policies of the segments are the same as those described in the summary of significant accounting policies.

 The remainder of Eversource's operations is presented as Other in the tables below and primarily consists of 1) the equity in earnings of Eversource parent from its subsidiaries and intercompany interest income, both of which are eliminated in consolidation, and interest expense related to the debt of Eversource parent, 2) the revenues and expenses of Eversource Service, most of which are eliminated in consolidation, 3) the operations of CYAPC and YAEC, 4) the results of other unregulated subsidiaries, which are not part of its core business, and 5) Eversource parent's equity ownership interests that are not consolidated, which primarily included the offshore wind investments until sale of the three offshore wind projects in 2024 and a natural gas pipeline owned by Enbridge, Inc.

 In the ordinary course of business, Yankee Gas, NSTAR Gas and EGMA purchase natural gas transmission services from the Enbridge, Inc. natural gas pipeline project described above. These affiliate transaction costs total $ 77.7 million annually and are classified as Purchased Power, Purchased Natural Gas and Transmission on the Eversource statements of income.

 Each of Eversource's subsidiaries, including CL&P, NSTAR Electric and PSNH, has one reportable segment.

 Cash flows used for investments in plant included in the segment information below are cash capital expenditures that do not include amounts incurred on capital projects but not yet paid, cost of removal, AFUDC related to equity funds, and the capitalized and deferred portions of pension and PBOP income/expense. Eversource's segment information is as follows:

 Electric Transmission
 Other
 Total

 $
 9,066.5
 $
 2,103.9
 $
 2,121.0
 $
 229.3
 $
 1,701.3
 $
 ( 3,321.2)
 $
 11,900.8

 Depreciation and Amortization
 ( 934.7)
 ( 216.6)
 ( 405.1)
 ( 32.3)
 ( 198.7)
 11.0
 ( 1,776.4)

 Operations and Maintenance (1)

 Operations, Excluding Storm Costs
 ( 447.3)
 ( 180.9)
 ( 135.1)

 Corporate Shared Services
 ( 457.1)
 ( 106.1)
 ( 74.6)

 Storm Costs
 ( 76.8)
 —
 —

 ( 202.5)
 ( 76.9)
 ( 52.7)

 ( 182.8)
 ( 48.4)
 —

 Other
 ( 135.9)
 ( 29.2)
 ( 71.1)

 ( 1,502.4)
 ( 441.5)
 ( 333.5)
 ( 98.7)
 ( 1,350.5)
 1,713.7
 ( 2,012.9)

 Purchased Power, Purchased Natural Gas and Transmission, Other Taxes and Energy Efficiency (2)

 ( 5,685.3)
 ( 1,007.1)
 ( 276.0)
 ( 26.3)
 ( 7.6)
 1,596.5
 ( 5,405.8)

 —
 —
 —
 ( 297.0)
 —
 —
 ( 297.0)

 Operating Income/(Loss)
 944.1
 438.7
 1,106.4
 ( 225.0)
 144.5
 —
 2,408.7

 ( 359.1)
 ( 99.2)
 ( 172.4)
 ( 36.2)
 ( 662.7)
 218.3
 ( 1,111.3)

 Loss on Offshore Wind Investments
 —
 —
 —
 —
 ( 464.0)
 —
 ( 464.0)

 114.6
 23.2
 0.3
 0.1
 218.3
 ( 218.3)
 138.2

 134.7
 22.4
 50.5
 7.2
 1,416.9
 ( 1,359.4)
 272.3

 Income Tax (Expense)/Benefit
 ( 198.0)
 ( 94.1)
 ( 257.3)
 0.2
 124.5
 —
 ( 424.7)

 636.3
 291.0
 727.5
 ( 253.7)
 777.5
 ( 1,359.4)
 819.2

 —
 ( 2.9)
 —
 —
 —
 ( 7.5)

 Net Income/(Loss) Attributable to
 Common Shareholders
 $
 631.7
 $
 291.0
 $
 724.6
 $
 ( 253.7)
 $
 777.5
 $
 ( 1,359.4)
 $
 811.7

 Total Assets (as of)
 $
 32,031.9
 $
 9,786.7
 $
 16,070.9
 $
 2,515.8
 $
 29,041.1
 $
 ( 29,851.9)
 $
 59,594.5

 Cash Flows Used for Investments in Plant
 $
 1,807.4
 $
 934.5
 $
 1,343.3
 $
 161.8
 $
 233.5
 $
 —
 $
 4,480.5

 Other
 Total

 $
 8,973.5
 $
 2,221.7
 $
 1,915.9
 $
 232.5
 $
 1,636.6
 $
 ( 3,069.5)
 $
 11,910.7

 Depreciation and Amortization
 ( 18.2)
 ( 214.2)
 ( 371.2)
 ( 56.0)
 ( 158.8)
 2.7
 ( 815.7)

 Operations and Maintenance (1)

 Operations, Excluding Storm Costs
 ( 418.2)
 ( 172.8)
 ( 124.7)

 Corporate Shared Services
 ( 397.2)
 ( 103.0)
 ( 62.5)

 Storm Costs
 ( 71.1)
 —

 ( 175.6)
 ( 76.6)
 ( 46.1)

 ( 161.9)
 ( 64.8)
 —

 Other
 ( 167.9)
 ( 27.5)
 ( 57.4)

 ( 1,391.9)
 ( 444.7)
 ( 292.0)
 ( 93.2)
 ( 1,325.6)
 1,651.7
 ( 1,895.7)

 Purchased Power, Purchased Natural Gas and Transmission, Other Taxes and Energy Efficiency (2)

 ( 6,712.7)
 ( 1,217.9)
 ( 258.5)
 ( 23.9)
 ( 4.2)
 1,417.2
 ( 6,800.0)

 850.7
 344.9
 994.2
 59.4
 148.0
 2.1
 2,399.3

 ( 291.7)
 ( 85.7)
 ( 163.7)
 ( 38.5)
 ( 425.3)
 149.5
 ( 855.4)

 Loss on Offshore Wind Investments
 —
 —
 —
 —
 ( 2,167.0)
 —
 ( 2,167.0)

 74.5
 18.2
 0.4
 —
 150.6
 ( 149.5)
 94.2

 Other Income/(Loss), Net
 136.2
 20.4
 41.2
 5.9
 ( 261.8)
 312.0
 253.9

 Income Tax (Expense)/Benefit
 ( 157.1)
 ( 73.0)
 ( 225.8)
 6.3
 289.9
 —
 ( 159.7)

 612.6
 224.8
 646.3
 33.1
 ( 2,265.6)
 314.1
 ( 434.7)

 —
 ( 2.9)
 —
 —
 —
 ( 7.5)

 Net Income/(Loss) Attributable to
 Common Shareholders
 $
 608.0
 $
 224.8
 $
 643.4
 $
 33.1
 $
 ( 2,265.6)
 $
 314.1
 $
 ( 442.2)

 Total Assets (as of)
 $
 29,426.4
 $
 8,775.3
 $
 14,806.5
 $
 2,944.8
 $
 26,337.7
 $
 ( 26,678.5)
 $
 55,612.2

 Cash Flows Used for Investments in Plant
 $
 1,668.1
 $
 844.1
 $
 1,406.3
 $
 167.0
 $
 251.3
 $
 —
 $
 4,336.8

 Other
 Total

 $
 9,405.3
 $
 2,215.6
 $
 1,808.7
 $
 222.5
 $
 1,435.5
 $
 ( 2,798.3)
 $
 12,289.3

 Depreciation and Amortization
 ( 970.4)
 ( 157.6)
 ( 337.4)
 ( 50.9)
 ( 132.6)
 5.8
 ( 1,643.1)

 Operations and Maintenance (1)

 Operations, Excluding Storm Costs
 ( 416.0)
 ( 182.5)
 ( 117.7)

 Corporate Shared Services
 ( 371.0)
 ( 109.8)
 ( 58.4)

 Storm Costs
 ( 74.4)
 —

 ( 189.6)
 ( 79.8)
 ( 39.6)

 ( 107.3)
 ( 36.0)
 —

 Other
 ( 153.0)
 ( 30.3)
 ( 72.6)

 ( 1,311.3)
 ( 438.4)
 ( 288.4)
 ( 88.4)
 ( 1,184.6)
 1,445.8
 ( 1,865.3)

 Purchased Power, Purchased Natural Gas and Transmission, Other Taxes and Energy Efficiency (2)

 ( 6,352.4)
 ( 1,288.6)
 ( 260.0)
 ( 23.4)
 ( 4.5)
 1,346.2
 ( 6,582.7)

 771.2
 331.0
 922.9
 59.8
 113.8
 2,198.2

 ( 253.1)
 ( 71.4)
 ( 145.5)
 ( 34.7)
 ( 247.8)
 74.2
 ( 678.3)

 45.1
 10.2
 0.5
 —
 66.3
 ( 71.6)
 50.5

 180.4
 33.6
 37.9
 8.5
 1,600.8
 ( 1,565.6)
 295.6

 Income Tax (Expense)/Benefit
 ( 146.2)
 ( 69.2)
 ( 216.3)
 3.2
 ( 25.1)
 —
 ( 453.6)

 597.4
 234.2
 599.5
 36.8
 1,508.0
 ( 1,563.5)
 1,412.4

 —
 ( 2.9)
 —
 —
 —
 ( 7.5)

 Net Income Attributable to Common Shareholders
 $
 592.8
 $
 234.2
 $
 596.6
 $
 36.8
 $
 1,508.0
 $
 ( 1,563.5)
 $
 1,404.9

 Cash Flows Used for Investments in Plant
 $
 1,172.6
 $
 710.3
 $
 1,144.0
 $
 154.4
 $
 260.6
 $
 —
 $
 3,441.9

 (1) The significant expense categories and amounts align with the segment-level information that is regularly provided to the chief operating decision maker. Costs of the operations organization include labor and overtime, outside services, vehicles, vegetation management, employee expenses, fees and payments, regulatory assessments, and materials, partially offset by reimbursements. Corporate shared services include corporate centralized functions. Costs within these corporate functions primarily include labor, services by vendors, fees and payments, insurance, and regulatory assessments. Other includes information technology system depreciation at Eversource Service charged to the operating businesses, as well as storm funding, capitalization and various other corporate costs. The segment-level operating expense for information technology system depreciation is eliminated and reflected in depreciation in Eversource's consolidation.

 For the water distribution segment, the chief operating decision maker is provided with total operations and maintenance expense information to manage its operations. Operations and maintenance expenses primarily include employee costs, benefits, and outside services.

 (2) Other segment line items for the electric distribution, electric transmission and natural gas distribution segments primarily include purchased power, purchased natural gas and transmission, taxes other than income taxes including property, payroll-related and Connecticut gross earnings taxes, and energy efficiency program expenses. Other segment line items for the water distribution business primarily include taxes other than income taxes.

 24. ASSETS HELD FOR SALE

 In early 2024, Eversource initiated an exploratory assessment of the potential sale of the Aquarion water distribution business. In December 2024, final bids were received, and Eversource obtained approval from its Board of Trustees to sell the Aquarion water distribution business. On January 27, 2025, Eversource entered into a definitive agreement to sell Aquarion. Subject to certain closing adjustments, the aggregate enterprise value of the sale is approximately $ 2.4 billion in cash, which includes approximately $ 1.6 billion for the equity and $ 800 million of net debt that will be extinguished at closing. The sale is subject to approval by PURA, DPU and the NHPUC, as well as other approvals pursuant to the Hart-Scott-Rodino Antitrust Improvements Act as well as other customary closing conditions. The sale is expected to close in late 2025. Eversource plans to use the net proceeds from the pending sale to pay down parent company debt.

 The assets and liabilities of the Aquarion water distribution business met the criteria to be classified as held for sale and have been classified separately as current or long-term assets and liabilities held for sale on the Eversource balance sheet as of December 31, 2024. As Eversource concluded this is the sale of a business, all goodwill held by the water distribution reporting unit was included in the carrying amount of the business and is also classified within assets held for sale. Long-term debt will be repaid by Eversource upon closing and is therefore excluded from liabilities held for sale. Assets and liabilities classified as held for sale are measured at the lower of carrying amount or fair value less costs to sell. In the fourth quarter of 2024, upon classifying the assets and liabilities as held for sale, Eversource concluded that the likely sale of Aquarion at a loss resulted in the requirement to test water distribution goodwill for impairment. Eversource performed an impairment test by comparing the fair value of the business to its carrying value and recorded a goodwill impairment of $ 297 million, as the estimated fair value of the business based on the anticipated sale was less than the carrying value. The fair value included future cash outflows of approximately $ 140 million of estimated income taxes as a result of the transaction. The goodwill impairment charge is presented separately within Operating Income on the Eversource statement of income for the year ended December 31, 2024. The water distribution business did not and will not meet the criteria to be presented as a discontinued operation.

 As of December 31, 2024, the major classes of Aquarion's assets and liabilities presented in current and long-term Assets Held for Sale and Liabilities Held for Sale on the Eversource balance sheet, which are included in the Water Distribution reportable segment, were as follows:

 Restricted Cash
 $
 5.8

 Receivables, Net
 14.4

 11.5

 24.6

 Total Current Assets Held for Sale
 $
 56.3

 $
 1,885.2

 51.2

 Goodwill
 662.5

 12.2

 Total Long-Term Assets Held for Sale
 $
 2,611.1

 $
 24.2

 28.4

 Total Current Liabilities Held for Sale
 $
 52.6

 $
 132.2

 266.7

 Total Long-Term Liabilities Held for Sale
 $
 398.9

 For the years ended December 31, 2024, 2023 and 2022, pre-tax income associated with the held for sale water distribution business (excluding the goodwill impairment recognized in 2024) was $ 43.1 million, $ 26.8 million and $ 33.6 million, respectively.

 25. GOODWILL

 In a business combination, the excess of the purchase price over the estimated fair values of the assets acquired and liabilities assumed is recognized as goodwill. The following table presents Eversource's goodwill by reportable segment:

 Water
 Total

 Balance as of January 1, 2023
 $
 2,543.6
 $
 576.8
 $
 451.0
 $
 951.2
 $
 4,522.6

 Water Acquisitions
 —
 —
 —
 9.5
 9.5

 $
 2,543.6
 $
 576.8
 $
 451.0
 $
 960.7
 $
 4,532.1

 Water Sale and Acquisition, net
 —
 —
 —

 Water Goodwill Impairment
 —
 —
 —
 ( 297.0)
 ( 297.0)

 Water Goodwill Reclassified as Held for Sale
 —
 —
 —
 ( 662.5)
 ( 662.5)

 $
 2,543.6
 $
 576.8
 $
 451.0
 $
 —
 $
 3,571.4

 In 2023, Eversource completed two water acquisitions resulting in the addition of $ 9.5 million of goodwill. In 2024, Eversource completed the sale of its unregulated water business resulting in a reduction to goodwill of $ 5.4 million and completed a water acquisition resulting in the addition of $ 4.2 million of goodwill.

 Goodwill is not amortized but is subject to an assessment for impairment at least annually and more frequently if indicators of impairment arise that would more likely than not reduce the fair value of Eversource's reporting units below their carrying amounts. Eversource's reporting units for the purpose of testing goodwill are Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution. These reporting units are consistent with the operating segments underlying the reportable segments identified in Note 23, "Segment Information," to the financial statements.

 In assessing goodwill for impairment, an entity is permitted to first assess qualitatively whether it is more likely than not that goodwill impairment exists as of the annual impairment test date. If after performing the qualitative assessment it is determined that it is more likely than not that the fair value of a reporting unit is less than its carrying value (including goodwill), then a quantitative goodwill impairment test is performed. A quantitative impairment test is required only if it is concluded that it is more likely than not that a reporting unit's carrying value may not be recoverable. The quantitative assessment compares the estimated fair value of a reporting unit to its carrying amount, and to the extent the carrying amount exceeds the fair value, an impairment of goodwill is recognized for the excess up to the amount of goodwill allocated to the reporting unit. A resulting write-down, if any, would be charged to Operating Expenses.

 Eversource completed its annual goodwill impairment assessment for the Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution reporting units as of October 1, 2024 and determined that no impairment existed. The annual goodwill assessment included a qualitative evaluation of multiple factors that impact the fair value of the reporting units, including general, macroeconomic and market conditions, and entity-specific assumptions that affect the future cash flows of the reporting units. Key considerations include discount rates, utility sector market performance and merger transaction multiples, the Company's share price and credit ratings, analyst reports, financial performance, cost and risk factors, internal estimates and projections of future cash flows and net income, long-term strategy, the timing and outcome of rate cases, and recent regulatory and legislative proceedings.

 In the fourth quarter of 2024, Eversource concluded that the likely sale of Aquarion at a loss resulted in the requirement to perform an interim goodwill impairment test for Water Distribution goodwill. Eversource compared the estimated fair value of the business from the anticipated transaction to its carrying value. Assumptions used in the valuation were the future cash flows from the sale, including approximately $ 140 million of estimated income tax impacts as a result of the transaction. Based on the interim impairment test, Eversource recorded a goodwill impairment of $ 297 million to write down the carrying value of the water distribution reporting unit to its estimated fair value. The goodwill impairment charge is presented separately within Operating Income on the Eversource statement of income for the year ended December 31, 2024.

 The remaining goodwill held by the water distribution reporting unit was reclassified to Assets Held for Sale on the Eversource balance sheet as of December 31, 2024.

 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure

 No events that would be described in response to this item have occurred with respect to Eversource, CL&P, NSTAR Electric or PSNH.

 Item 9A. Controls and Procedures

 Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, is responsible for the preparation, integrity, and fair presentation of the accompanying Financial Statements and other sections of this combined Annual Report on Form 10-K. Eversource's internal controls over financial reporting were audited by Deloitte & Touche LLP.

 Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, is responsible for establishing and maintaining adequate internal controls over financial reporting. The internal control framework and processes have been designed to provide reasonable assurance regarding the reliability of financial reporting and the preparation of financial statements for external purposes in accordance with GAAP. There are inherent limitations of internal controls over financial reporting that could allow material misstatements due to error or fraud to occur and not be prevented or detected on a timely basis by employees during the normal course of business. Additionally, internal controls over financial reporting may become inadequate in the future due to changes in the business environment. Under the supervision and with the participation of the principal executive officer and principal financial officer, an evaluation of the effectiveness of internal controls over financial reporting was conducted based on criteria established in Internal Control - Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission (COSO). Based on this evaluation under the framework in COSO, management concluded that internal controls over financial reporting at Eversource, CL&P, NSTAR Electric and PSNH were effective as of December 31, 2024.

 Management, on behalf of Eversource, CL&P, NSTAR Electric and PSNH, evaluated the design and operation of the disclosure controls and procedures as of December 31, 2024 to determine whether they are effective in ensuring that the disclosure of required information is made timely and in accordance with the Securities Exchange Act of 1934 and the rules and regulations of the SEC. This evaluation was made under management's supervision and with management's participation, including the principal executive officer and principal financial officer as of the end of the period covered by this Annual Report on Form 10-K. There are inherent limitations of disclosure controls and procedures, including the possibility of human error and the circumventing or overriding of the controls and procedures. Accordingly, even effective disclosure controls and procedures can only provide reasonable assurance of achieving their control objectives. The principal executive officer and principal financial officer have concluded, based on their review, that the disclosure controls and procedures of Eversource, CL&P, NSTAR Electric and PSNH are effective to ensure that information required to be disclosed by us in reports filed under the Securities Exchange Act of 1934 (i) is recorded, processed, summarized, and reported within the time periods specified in SEC rules and regulations and (ii) is accumulated and communicated to management, including the principal executive officer and principal financial officer, as appropriate to allow timely decisions regarding required disclosures.

 There have been no changes in internal controls over financial reporting for Eversource, CL&P, NSTAR Electric and PSNH during the quarter ended December 31, 2024 that have materially affected, or are reasonably likely to materially affect, internal controls over financial reporting.

 Item 9B. Other Information

 During the quarter ended December 31, 2024, none of the Company's directors or officers adopted, modified, or terminated a "Rule 10b5-1 trading arrangement" or a "non-Rule 10b5-1 trading arrangement," as such terms are defined under Item 408 of Regulation S-K.

 No additional information is required to be disclosed under this item as of December 31, 2024, as this information has been previously disclosed in applicable reports on Form 8-K during the fourth quarter of 2024.

 Item 10. Directors, Executive Officers and Corporate Governance

 The information required by this Item 10 for Eversource Energy is incorporated herein by reference to certain information contained in the sections captioned "Election of Trustees," and "Governance of Eversource Energy" plus related subsections, of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2025.

 Information concerning executive officers of Eversource Energy required by this Item 10 is reported under a separate caption entitled "Information About Our Executive Officers" in Part I of this report.

 Certain information required by this Item 10 is omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly Owned Subsidiaries.

 Item 11. Executive Compensation

 The information required by this Item 11 for Eversource Energy is incorporated herein by reference to certain information contained in Eversource Energy's definitive proxy statement for solicitation of proxies, which is expected to be filed with the SEC on or about March 21, 2025, under the sections captioned "Compensation Discussion and Analysis," plus related subsections, and "Compensation Committee Report," plus related subsections following such Report.

 Certain information required by this Item 11 has been omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters

 In addition to the information below under "Securities Authorized for Issuance Under Equity Compensation Plans," incorporated herein by reference is the information contained in the sections "Securities Ownership of Certain Beneficial Owners" and "Common Share Ownership of Trustees and Management" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2025.

 Certain information required by this Item 12 has been omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

 SECURITIES AUTHORIZED FOR ISSUANCE UNDER EQUITY COMPENSATION PLANS

 The following table sets forth the number of Eversource Energy common shares issuable under Eversource Energy equity compensation plans, as well as their weighted exercise price, as of December 31, 2024, in accordance with the rules of the SEC:
 Plan Category
 Number of securities to be issued upon exercise of outstanding options, warrants and rights (1)

 Weighted-average exercise price of outstanding options, warrants and rights (2)

 Number of securities remaining available for future issuance under equity compensation plans (excluding securities reflected in column (1))

 Equity compensation plans approved by security holders
 1,579,634
 $—
 3,790,353

 Equity compensation plans not approved by security holders (3)

 —
 —
 —

 Total
 1,579,634
 $—
 3,790,353

 (1) Includes 715,442 common shares for distribution in respect of restricted share units, and 864,192 performance shares issuable at target, all pursuant to the terms of our Incentive Plans.

 (2) The weighted-average exercise price does not take into account restricted share units or performance shares, which have no exercise price.

 (3) Securities set forth in this table are authorized for issuance under compensation plans that have been approved by shareholders of Eversource Energy.

 For information regarding our Incentive Plans, see Note 11C, "Employee Benefits - Share Based Payments," to the financial statements.

 Item 13. Certain Relationships and Related Transactions, and Director Independence

 Incorporated herein by reference is the information contained in the sections captioned "Trustee Independence" and "Related Person Transactions" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2025.

 Certain information required by this Item 13 has been omitted for CL&P, NSTAR Electric and PSNH pursuant to Instruction I(2)(c) to Form 10-K, Omission of Information by Certain Wholly-Owned Subsidiaries.

 Item 14. Principal Accountant Fees and Services

 Incorporated herein by reference is the information contained in the section "Relationship with Principal Independent Registered Public Accounting Firm" of Eversource Energy's definitive proxy statement for solicitation of proxies, expected to be filed with the SEC on or about March 21, 2025.

 Pre-Approval of Services Provided by Principal Auditors

 None of CL&P, NSTAR Electric and PSNH is subject to the audit committee requirements of the SEC, the national securities exchanges or the national securities associations. CL&P, NSTAR Electric and PSNH obtain audit services from the independent auditor engaged by the Audit Committee of Eversource Energy's Board of Trustees. Eversource Energy's Audit Committee has established policies and procedures regarding the pre-approval of services provided by the principal auditors. Those policies and procedures delegate pre-approval of services to the Eversource Energy Audit Committee Chair provided that such offices are held by Trustees who are "independent" within the meaning of the Sarbanes-Oxley Act of 2002 and that all such pre-approvals are presented to the Eversource Energy Audit Committee at the next regularly scheduled meeting of the Committee.

 The following relates to fees and services for the entire Eversource Energy system, including Eversource Energy, CL&P, NSTAR Electric and PSNH.

 Fees Billed By Principal Independent Registered Public Accounting Firm

 The aggregate fees billed to the Company and its subsidiaries by Deloitte & Touche LLP, the member firms of Deloitte Touche Tohmatsu, and their respective affiliates (collectively, the Deloitte Entities), for the years ended December 31, 2024 and 2023 totaled $7,454,414 and $7,070,914, respectively. In addition, affiliates of Deloitte & Touche LLP as noted below provide other accounting services to the Company.

 Audit and Non-Audit Fees
 2024
 2023

 Audit Fees (1)

 $
 5,984,500
 $
 5,310,000

 Audit Related Fees (2)

 1,386,000
 1,759,000

 All Other Fees (3)

 83,914
 1,914

 TOTAL
 $
 7,454,414
 $
 7,070,914

 (1) Audit Fees consisted of fees related to the audits of financial statements of Eversource Energy and its subsidiaries in the Annual Report on Form 10-K, reviews of financial statements in the Combined Quarterly reports on Form 10-Q of Eversource Energy and its subsidiaries, consultations with management, regulatory and compliance filings, system conversion quality assurance, out of pocket expenses, and audits of internal controls over financial reporting for the years ended December 31, 2024 and 2023.

 (2) Audit Related Fees were incurred for procedures performed in the ordinary course of business in support of Eversource's ATM equity offering program, certain regulatory filings, comfort letters, consents, and other costs related to registration statements and financials for the years ended December 31, 2024 and 2023.

 (3) All Other Fees for the years ended December 31, 2024 and 2023 related to an annual license for access to an accounting standards research tool. All Other Fees for the year ended December 31, 2024 also related to a system pre-implementation control review.

 The Audit Committee pre-approves all auditing services and permitted audit-related or other services (including the fees and terms thereof) to be performed for us by our independent registered public accounting firm, subject to the de minimis exceptions for non-audit services described in

 Section 10A(i)(1)(B) of the Securities Exchange Act of 1934, which are approved by the Audit Committee prior to the completion of the audit. The Audit Committee may form and delegate its authority to subcommittees consisting of one or more members when appropriate, including the authority to grant pre-approvals of audit and permitted non-audit services, provided that decisions of such subcommittees to grant pre-approvals are presented to the full Audit Committee at its next scheduled meeting. During 2024, all services described above were pre-approved by the Audit Committee or its Chair.

 The Audit Committee has considered whether the provision by the Deloitte Entities of the non-audit services described above was allowed under Rule 2-01(c)(4) of Regulation S-X and was compatible with maintaining the independence of the registered public accountants and has concluded that the Deloitte Entities were and are independent of us in all respects.

 Item 15. Exhibits and Financial Statement Schedules

 (a)
 1.
 Financial Statements:

 The financial statements filed as part of this Annual Report on Form 10-K are set forth under Item 8, "Financial Statements and Supplementary Data."

 2.
 Schedules

 I.
 Financial Information of Registrant:

 Eversource Energy (Parent) Balance Sheets as of December 31, 2024 and 2023

 S-1

 Eversource Energy (Parent) Statements of Income for the Years Ended
 December 31, 2024, 2023 and 2022

 S-2

 Eversource Energy (Parent) Statements of Comprehensive Income for the Years Ended
 December 31, 2024, 2023 and 2022

 S-2

 Eversource Energy (Parent) Statements of Cash Flows for the Years Ended
 December 31, 2024, 2023 and 2022

 S-3

 II.
 Valuation and Qualifying Accounts and Reserves for Eversource, CL&P, NSTAR Electric and PSNH
 for 2024, 2023 and 2022

 S-4

 All other schedules of the companies for which inclusion is required in the applicable regulations of the SEC are permitted to be omitted under the related instructions or are not applicable, and therefore have been omitted.

 3.

 Exhibit Index
 E-1

 Item 16. Form 10-K Summary

 Not applicable.

 SCHEDULE I
 EVERSOURCE ENERGY (PARENT)
 FINANCIAL INFORMATION OF REGISTRANT
 BALANCE SHEETS
 AS OF DECEMBER 31, 2024 AND 2023

 2024
 2023

 Cash
 $
 1,083
 $

 Accounts Receivable from Subsidiaries
 100,320
 60,191

 Notes Receivable from Subsidiaries
 2,051,400
 2,045,570

 Prepayments and Other Current Assets, Including Assets Held for Sale
 96,313
 103,735

 2,249,116
 2,210,038

 Investments in Subsidiary Companies, at Equity
 20,080,215
 17,977,812

 Notes Receivable from Subsidiaries
 2,296,500
 2,296,500

 113,718
 10,131

 Goodwill
 3,231,811
 3,852,524

 Long-Term Assets Held for Sale
 335,393
 —

 24,582
 28,287

 26,082,219
 24,165,254

 $
 28,331,335
 $
 26,375,292

 Notes Payable
 $
 1,538,011
 $
 1,564,575

 Long-Term Debt - Current Portion
 600,000
 364,653

 Accounts Payable to Subsidiaries
 45,326
 38,051

 Accrued Interest
 168,748
 106,070

 57,923
 41,268

 2,410,008
 2,114,617

 Long-Term Liabilities Held for Sale
 15,028
 —

 137,656
 134,432

 152,684
 134,432

 10,729,256
 9,952,351

 Common Shareholders' Equity:

 Common Shares
 1,878,622
 1,799,920

 Capital Surplus, Paid in
 9,428,905
 8,460,876

 3,929,141
 4,142,515

 Accumulated Other Comprehensive Loss
 ( 26,472)
 ( 33,737)

 Treasury Stock
 ( 170,809)
 ( 195,682)

 Common Shareholders' Equity
 15,039,387
 14,173,892

 $
 28,331,335
 $
 26,375,292

 See the Combined Notes to Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to Eversource parent, including the pending sale of Aquarion as described in Note 24, "Assets Held for Sale," Eversource common shares information as described in Note 18, "Common Shares," material obligations and guarantees as described in Note 13, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt."
 S-1

 SCHEDULE I
 EVERSOURCE ENERGY (PARENT)
 FINANCIAL INFORMATION OF REGISTRANT
 STATEMENTS OF INCOME/(LOSS)

 FOR THE YEARS ENDED DECEMBER 31, 2024, 2023 AND 2022
 (Thousands of Dollars, Except Share Information)

 2024
 2023
 2022

 $
 4,442
 $
 $
 —

 Other
 12,769
 26,708

 297,000
 —
 —

 297,020
 12,769
 26,708

 Operating Loss
 ( 292,578)
 ( 11,929)
 ( 26,708)

 549,511
 397,281
 237,773

 Other Income, Net:

 Equity in Earnings/(Losses) of Subsidiaries
 1,359,297
 ( 312,040)
 1,565,474

 Other, Net
 214,444
 188,003
 79,383

 Other Income/(Loss), Net
 1,573,741
 ( 124,037)
 1,644,857

 Income/(Loss) Before Income Tax Benefit
 731,652
 ( 533,247)
 1,380,376

 Income Tax Benefit
 ( 80,001)
 ( 91,007)
 ( 24,499)

 $
 811,653
 $
 ( 442,240)
 $
 1,404,875

 Basic Earnings/(Loss) per Common Share
 $
 2.27
 $
 ( 1.27)
 $
 4.05

 Diluted Earnings/(Loss) per Common Share
 $
 2.27
 $
 ( 1.26)
 $
 4.05

 Weighted Average Common Shares Outstanding:

 Basic
 357,482,965
 349,580,638
 346,783,444

 Diluted
 357,779,408
 349,840,481
 347,246,768

 STATEMENTS OF COMPREHENSIVE INCOME/(LOSS)

 2024
 2023
 2022

 $
 811,653
 $
 ( 442,240)
 $
 1,404,875

 Other Comprehensive Income, Net of Tax:

 Qualified Cash Flow Hedging Instruments

 —
 1,252
 ( 1,636)

 Changes in Funded Status of Pension, SERP and PBOP Benefit Plans
 7,245
 4,412
 4,470

 Other Comprehensive Income, Net of Tax
 7,265
 5,684
 2,854

 Comprehensive Income/(Loss)
 $
 818,918
 $
 ( 436,556)
 $
 1,407,729

 See the Combined Notes to Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to Eversource parent, including the pending sale of Aquarion as described in Note 24, "Assets Held for Sale," Eversource common shares information as described in Note 18, "Common Shares," material obligations and guarantees as described in Note 13, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt."

 S-2

 SCHEDULE I
 EVERSOURCE ENERGY (PARENT)
 FINANCIAL INFORMATION OF REGISTRANT
 STATEMENTS OF CASH FLOWS
 FOR THE YEARS ENDED DECEMBER 31, 2024, 2023 and 2022

 2024
 2023
 2022

 $
 811,653
 $
 ( 442,240)
 $
 1,404,875

 Adjustments to Reconcile Net Income to Net Cash Flows Provided by Operating Activities:

 Equity in (Earnings)/Losses of Subsidiaries
 ( 1,359,297)
 312,040
 ( 1,565,474)

 Cash Dividends Received from Subsidiaries
 1,273,700
 1,027,400
 855,600

 ( 99,692)
 ( 22,256)
 25,823

 297,000
 —
 —

 Other
 57,469
 ( 12,834)
 26,455

 Accounts Receivables from Subsidiaries
 ( 40,129)
 ( 6,853)
 ( 9,935)

 22,464
 ( 80,968)
 ( 21,627)

 Accounts Payable to Subsidiaries
 7,275
 4,521
 ( 4,079)

 58,572
 35,357
 35,090

 1,029,015
 814,167
 746,728

 Capital Contributions to Subsidiaries
 ( 2,026,500)
 ( 1,369,700)
 ( 1,499,300)

 Return of Capital from Subsidiaries
 17,000
 438,000
 12,000

 Increase/(Decrease) in Notes Receivable from Subsidiaries
 201,500
 ( 1,578,100)
 ( 724,400)

 —
 147,567
 ( 1,289)

 ( 1,808,000)
 ( 2,362,233)
 ( 2,212,989)

 Issuance of Common Shares, Net of Issuance Costs
 989,447
 —
 197,058

 Cash Dividends on Common Shares
 ( 1,001,488)
 ( 918,995)
 ( 860,033)

 2,400,000
 3,350,000
 2,800,000

 ( 1,350,000)
 ( 1,200,000)
 ( 750,000)

 (Decrease)/Increase in Notes Payable
 ( 233,894)
 329,705
 99,250

 ( 24,539)
 ( 13,076)
 ( 19,193)

 Net Cash Flows Provided by Financing Activities
 779,526
 1,547,634
 1,467,082

 Net Increase/(Decrease) in Cash and Restricted Cash
 ( 432)

 Cash and Restricted Cash - Beginning of Year
 1,047

 Cash and Restricted Cash - End of Year
 $
 1,156
 $
 $
 1,047

 Supplemental Cash Flow Information:

 Cash Paid/(Received) During the Year for:

 Interest
 $
 483,101
 $
 366,645
 $
 215,053

 Income Taxes
 $
 $
 23,984
 $
 ( 20,992)

 See the Combined Notes to Financial Statements in this Annual Report on Form 10-K for a description of significant accounting matters related to Eversource parent, including the pending sale of Aquarion as described in Note 24, "Assets Held for Sale," Eversource common shares information as described in Note 18, "Common Shares," material obligations and guarantees as described in Note 13, "Commitments and Contingencies," and debt agreements as described in Note 8, "Short-Term Debt," and Note 9, "Long-Term Debt."

 S-3

 SCHEDULE II
 VALUATION AND QUALIFYING ACCOUNTS AND RESERVES
 FOR THE YEARS ENDED DECEMBER 31, 2024, 2023 AND 2022

 Column A
 Column B
 Column C
 Column D
 Column E

 Additions

 (1)
 (2)

 Description:
 Balance as of Beginning of Year
 Charged to Costs and Expenses
 Charged to Other
Accounts -
Describe (a)
 Deductions -Describe (b)
 Balance as of End of Year

 Eversource:

 Reserves Deducted from Assets -

 Reserves for Uncollectible Accounts:

 2024
 $
 554,455
 $
 74,069
 $
 119,659
 $
 192,019
 $
 556,164

 2023
 486,297
 72,468
 158,205
 162,515
 554,455

 2022
 417,406
 61,876
 112,533
 105,518
 486,297

 CL&P:

 Reserves Deducted from Assets -

 Reserves for Uncollectible Accounts:

 2024
 $
 296,030
 $
 17,190
 $
 46,840
 $
 80,952
 $
 279,108

 2023
 225,320
 11,675
 126,360
 67,325
 296,030

 2022
 181,319
 15,578
 59,485
 31,062
 225,320

 NSTAR Electric:

 Reserves Deducted from Assets -

 Reserves for Uncollectible Accounts:

 2024
 $
 97,026
 $
 33,607
 $
 37,653
 $
 53,376
 $
 114,910

 2023
 94,958
 22,791
 17,488
 38,211
 97,026

 2022
 97,005
 21,550
 12,412
 36,009
 94,958

 PSNH:

 Reserves Deducted from Assets -

 Reserves for Uncollectible Accounts:

 2024
 $
 14,322
 $
 4,688
 $
 5,131
 $
 10,051
 $
 14,090

 2023
 29,236
 3,989
 ( 8,735)
 10,168
 14,322

 2022
 24,331
 9,211
 2,539
 6,845
 29,236

 (a) Amounts relate to uncollectible accounts receivables reserved for that are not charged to bad debt expense. CL&P, NSTAR Electric, NSTAR Gas, EGMA and Yankee Gas are allowed to recover in rates, amounts associated with certain uncollectible hardship accounts receivable. CL&P, NSTAR Electric, PSNH, NSTAR Gas and EGMA are also allowed to recover uncollectible energy supply costs through regulatory tracking mechanisms.

 (b) Amounts written off, net of recoveries.

 S-4

 EXHIBIT INDEX

 Each document described below is incorporated by reference by the registrant(s) listed to the files identified, unless designated with a (*), which exhibits are filed herewith. Management contracts and compensation plans or arrangements are designated with a (+).

 Exhibit
 Number Description

 3. Articles of Incorporation and By-Laws

 3.1 Declaration of Trust of Eversource Energy, as amended through May 3, 2017 (Exhibit 3.1, Eversource Form 10-Q filed on May 5, 2017)

 (B) The Connecticut Light and Power Company

 3.1 Amended and Restated Certificate of Incorporation (Exhibit 3(i), CL&P Current Report on Form 8-K filed on January 9, 2012, File No. 000-00404)

 3.2 By-laws of CL&P, as amended and restated effective September 29, 2014 (Exhibit 3.1, CL&P Current Report on Form 8-K filed October 2, 2014, File No. 000-00404)

 (C) NSTAR Electric Company

 3.1 Restated Articles of Organization of NSTAR Electric Company, fka Boston Edison Company (Exhibit 3.1, NSTAR Electric Form 10-Q for the Quarter Ended June 30, 1994 filed August 12, 1994, File No. 001-02301)

 3.2 Bylaws of NSTAR Electric Company, as amended and restated effective September 29, 2014 (Exhibit 3.1, NSTAR Electric Current Report on Form 8-K filed October 2, 2014, File No. 000-02301)

 (D) Public Service Company of New Hampshire

 3.1 Articles of Incorporation, as amended to May 16, 1991 (Exhibit 3.3.1, 1993 PSNH Form 10-K filed March 25, 1994, File No. 001-06392)

 3.2 By-laws of PSNH, as in effect June 27, 2008 (Exhibit 3, PSNH Form 10-Q for the Quarter Ended June 30, 2008 filed August 7, 2008, File No. 001-06392)

 4. Instruments defining the rights of security holders, including indentures

 4.1 Indenture between Eversource Energy and The Bank of New York as Trustee dated as of April 1, 2002 (Exhibit A-3, Eversource Energy 35-CERT filed April 16, 2002, File No. 070-09535)

 4.1.1 Seventh Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 7, 2016, relating to $250 million of Senior Notes, Series J, due 2026 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed March 15, 2016, File No. 001-05324)

 4.1.2 Tenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2018, relating to $450 million of Senior Notes, Series M, Due 2028 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed January 12, 2018, File No. 001-05324)

 4.1.3 Eleventh Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of December 1, 2018, relating to $400 million of Senior Notes, Series N, Due 2023 and $500 million of Senior Notes, Series O, Due 2029 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed December 18, 2018, File No. 001-05324)

 4.1.4 Twelfth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2020, relating to $650 million of Senior Notes, Series P, Due 2050 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed January 16, 2020, File No. 001-05324)
 E-1

 4.1.5 Thirteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of August 1, 2020, relating to $300 million aggregate principal amount of Senior Notes, Series Q, Due 2025 and $600 million aggregate principal amount of Senior Notes, Series R, Due 2030 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed August 20, 2020, File No. 001-05324)

 4.1.6 Fourteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 1, 2021, relating to $350 million aggregate principal amount of Senior Notes, Series S, Due 2031 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed March 16, 2021, File No. 001-05324)

 4.1.7 Fifteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of August 1, 2021, relating to $350 million aggregate principal amount of Floating Rate Senior Notes, Series T and $300 million aggregate principal amount of Senior Notes, Series U, Due 2026 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed August 13, 2021, File No. 001-05324)

 4.1.8 Sixteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of February 1, 2022, relating to $650 million aggregate principal amount of Senior Notes, Series V, Due 2027 and $650 million aggregate principal amount of Senior Notes, Series W, Due 2032 ( Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed February 25, 2022, File No. 001-05324)

 4.1.9 Seventeenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of June 1, 2022, relating to $900 million aggregate principal amount of Senior Notes, Series X, Due 2024 and $600 million aggregate principal amount of Senior Notes, Series Y, Due 2027 ( Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed June 27, 2022, File No. 001-05324)

 4.1.10 Eighteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of March 1, 2023, relating to $1.3 billion aggregate principal amount of Senior Notes, Series Z, Due 2028 ( Exhibit 4.1, Eversource Energy Current Report on Form 8 K filed March 6, 2023, File No. 001-05324)

 4.1.11 Nineteenth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of May 1, 2023, relating to $450 million aggregate principal amount of Senior Notes, Series AA, Due 2026 and $800 million aggregate principal amount of Senior Notes, Series BB, Due 2033 ( Exhibit 4.3, Eversource Energy Current Report on Form 8 K filed May 11, 2023, File No. 001-05324)

 4.1.12 Twentieth Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of November 1, 2023, relating to $800 million aggregate principal amount of Senior Notes, Series CC, Due 2029 ( Exhibit 4.1, Eversource Energy Current Report on Form 8 K filed November 13, 2023, File No. 001-05324)

 4.1.13 Twenty-First Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of January 1, 2024, relating to $350 million aggregate principal amount of Senior Notes, Series DD, Due 2027 and $650 million aggregate principal amount of Senior Notes, Series EE, Due 2034 ( Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed January 19, 2024, File No. 001-05324)

 4.1.14 Twenty-Second Supplemental Indenture between Eversource Energy and The Bank of New York Trust Company N.A., as Trustee, dated as of April 1, 2024, relating to $700 million aggregate principal amount of Senior Notes, Series FF, Due 2031 and $700 million aggregate principal amount of Senior Notes, Series GG, Due 2034 (Exhibit 4.1, Eversource Energy Current Report on Form 8-K filed April 18, 2024, File No. 001-05324)

 4.2 Eversource Energy Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.3, Eversource Energy Annual Report on Form 10-K filed February 27, 2020, File No. 001-05324)

 (B) The Connecticut Light and Power Company

 4.1 Indenture of Mortgage and Deed of Trust between CL&P and Bankers Trust Company, Trustee, dated as of May 1, 1921 (Composite including all twenty-four amendments to May 1, 1967) (Exhibit 4.1, 2017 Eversource 10-K filed on February 26, 2018)

 E-2

 4.1.1 Series B Supplemental Indenture between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2004 (Exhibit 99.5, CL&P Current Report on Form 8-K filed September 22, 2004, File No. 000-00404)

 4.2 Composite Indenture of Mortgage and Deed of Trust between CL&P and Deutsche Bank Trust Company Americas f/k/a Bankers Trust Company, dated as of May 1, 1921, as amended and supplemented by seventy-three supplemental mortgages to and including Supplemental Mortgage dated as of April 1, 2005 (Exhibit 99.5, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)

 4.2.1 Supplemental Indenture (2005 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2005 (Exhibit 99.2, CL&P Current Report on Form 8-K filed April 13, 2005, File No. 000-00404)

 4.2.2 Supplemental Indenture (2006 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2006 (Exhibit 99.2, CL&P Current Report on Form 8-K filed June 7, 2006, File No. 000-00404)

 4.2.3 Supplemental Indenture (2007 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2007 (Exhibit 99.2, CL&P Current Report on Form 8-K filed March 29, 2007, File No. 000-00404)

 4.2.4 Supplemental Indenture (2007 Series D Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2007 (Exhibit 4, CL&P Current Report on Form 8-K filed September 19, 2007, File No. 000-00404)

 4.2.5 Supplemental Indenture (2014 Series A Bond) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of April 1, 2014 (Exhibit 4.1, CL&P Current Report on Form 8-K filed April 29, 2014, File No. 000-00404)

 4.2.6 Supplemental Indenture (2015 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of May 1, 2015 (Exhibit 4.1, CL&P Current Report on Form 8-K filed May 26, 2015, File No. 000-00404)

 4.2.7 Supplemental Indenture (2015 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of November 1, 2015 (Exhibit 4.1, CL&P Current Report on Form 8-K filed December 4, 2015, File No. 000-00404)

 4.2.8 Supplemental Indenture (2017 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2017 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on March 16, 2017, File No. 000-00404)

 4.2.9 Supplemental Indenture (2014 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of August 1, 2017 (Exhibit 4.1, CL&P Current Report on Form 8-K filed August 23, 2017, File No. 000-00404)

 4.2.10 Supplemental Indenture (2018 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2018 (Exhibit 4.1, CL&P Current Report on Form 8-K filed April 2, 2018, File No. 000-00404)

 4.2.11 Supplemental Indenture (2018 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of March 1, 2019 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on April 4, 2019, File No. 000-00404)

 4.2.12 Supplemental Indenture (2017 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of September 1, 2019 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on September 23, 2019, File No. 000-00404)

 4.2.13 Supplemental Indenture (2020 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of December 1, 2020 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on December 4, 2020, File No. 000-00404)

 4.2.14 Supplemental Indenture (2021 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of June 1, 2021 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on July 2, 2021, File No. 000-00404)

 E-3

 4.2.15 Supplemental Indenture (2023 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2023 ( Exhibit 4.1, CL&P Current Report on Form 8-K filed on January 10, 2023, File No. 000-00404)

 4.2.16 Supplemental Indenture (2023 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of July 1, 2023 ( Exhibit 4.1, CL&P Current Report on Form 8-K filed on July 6, 2023, File No. 000-00404)

 4.2.17 Supplemental Indenture (2024 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2024 ( Exhibit 4.1, CL&P Current Report on Form 8-K filed on January 23, 2024, File No. 000-00404)

 4.2.18 Supplemental Indenture (2024 Series B Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of August 1, 2024 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on August 13, 2024, File No. 000-00404)

 4.2.19 Supplemental Indenture (2025 Series A Bonds) between CL&P and Deutsche Bank Trust Company Americas, as Trustee dated as of January 1, 2025 (Exhibit 4.1, CL&P Current Report on Form 8-K filed on January 13, 2025, File No. 000-00404)

 4.3 CL&P Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.4, Eversource Energy Annual Report on Form 10-K filed February 27, 2020, File No. 001-05324)

 (C) NSTAR Electric Company

 4.1 Indenture between Boston Edison Company and the Bank of New York (as successor to Bank of Montreal Trust Company) (Exhibit 4.1, 2017 Eversource Form 10-K filed February 26, 2018)

 4.1.1 A Form of 5.75% Debenture Due March 15, 2036 (Exhibit 99.2, Boston Edison Company Current Report on Form 8 K filed March 17, 2006, File No. 001-02301)

 4.1.2 A Form of 5.50% Debenture Due March 15, 2040 (Exhibit 99.2, NSTAR Electric Company Current Report on Form 8 K filed March 15, 2010, File No. 001-02301)

 4.1.3 A Form of 4.40% Debenture Due 2044 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed March 13, 2014, File No. 001-02301)

 4.1.4 A Form of 3.25% Debenture due 2025 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on November 20, 2015, File No. 001-02301)

 4.1.5 A Form of 2.70% Debenture due 2026 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on May, 31, 2016, File No. 001-02301)

 4.1.6 Form of 3.20% Debenture due May 15, 2027 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on May 18, 2017 File No. 001-02301)

 4.1.7 Form of 3.25% Debenture due May 15, 2029 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on May 23, 2019, File No. 001-02301)

 4.1.8 Form of 3.95% Debenture due April 1, 2030 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on March 26, 2020, File No. 001-02301)

 4.1.9 Form of 3.10% Debenture due June 1, 2051 (Exhibit 4, NSTAR Electric Company Current Report on Form 8-K filed on June 2, 2021, File No. 001-02301)

 4.1.10 Form of 1.95% Debenture due August 15, 2031 (Exhibit 4.1, NSTAR Electric Company Current Report on Form 8-K filed on August 23, 2021, File No. 001-02301)

 4.1.11 Form of 4.55% Debenture due June 1, 2052 ( Exhibit 4.1, NSTAR Electric Company Current Report on Form 8-K filed on May 17, 2022, File No. 001-02301)

 4.1.12 Form of 4.95% Debenture due September 15, 2052 ( Exhibit 4.1, NSTAR Electric Company Current Report on Form 8-K filed on September 15, 2022, File No. 001-02301)

 E-4

 4.1.13 Form of 5.60% Debenture due October 1, 2028 ( Exhibit 4.1, NSTAR Electric Company Current Report on Form 8-K filed on September 25, 2023, File No. 001-02301)

 4.1.14 Form of 5.40% Debenture due 2034 ( Exhibit 4.1, NSTAR Electric Company Current Report on Form 8 K filed on May 22, 2024, File No. 001-02301)

 4.2 Second Amended and Restated Credit Agreement, dated as of October 15, 2021, by and among NSTAR Electric Company and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender ( Exhibit 10.13, 2021 Eversource Form 10-K filed on February 17, 2022)

 4.2.1 First Amendment to Second Amended and Restated Credit Agreement and Extension Agreement, dated October 17, 2022, by and between NSTAR Electric Company and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender ( Exhibit 4.1, Eversource Form 10-Q filed on November 4, 2022)

 4.2.2 Second Amendment to Second Amended and Restated Credit Agreement, dated October 11, 2024, by and between NSTAR Electric Company and the Banks named therein, pursuant to which Barclays Bank PLC serves as Administrative Agent and Swing Line Lender (Exhibit 4, Eversource Form 10-Q filed on November 6, 2024)

 4.3 Indenture between NSTAR Electric Company, as successor to Western Massachusetts Electric Company (WMECO), and The Bank of New York, as Trustee, dated as of September 1, 2003 (Exhibit 99.2, WMECO Current Report on Form 8-K filed October 8, 2003, File No. 000-07624)

 4.3.1 Second Supplemental Indenture between NSTAR Electric Company, as successor to WMECO, and The Bank of New York, as Trustee dated as of September 1, 2004 (Exhibit 4.1, WMECO Current Report on Form 8-K filed September 27, 2004, File No. 000-07624)

 4.3.2 Fourth Supplemental Indenture between NSTAR Electric Company, as successor to WMECO, and The Bank of New York Trust, as Trustee, dated as of August 1, 2007 (Exhibit 4.1, WMECO Current Report on Form 8-K filed August 20, 2007, File No. 000-07624)

 4.3.3 Eighth Supplemental Indenture between NSTAR Electric Company, as successor to WMECO, and The Bank of New York Trust Company, N.A., as Trustee, dated as of June 1, 2016 (Exhibit 4.1, WMECO Current Report on Form 8-K filed June 29, 2016, File No. 000-07624)

 4.4 NSTAR Electric Company Description of Securities Registered Pursuant to Section 12 of the Securities Exchange Act of 1934 (Exhibit 4.4, Eversource Energy Annual Report on Form 10-K filed February 27, 2020, File No. 001-05324)

 (D) Public Service Company of New Hampshire

 4.1 First Mortgage Indenture between PSNH and First Fidelity Bank, National Association, New Jersey, now First Union National Bank, Trustee, dated as of August 15, 1978 (Composite including all amendments effective June 1, 2011) (included as Exhibit C to the Eighteenth Supplemental Indenture filed as Exhibit 4.1 to PSNH Current Report on Form 8-K filed June 2, 2011, File No. 001-06392)

 4.1.1 Fourteenth Supplemental Indenture between PSNH and Wachovia Bank, National Association successor to First Union National Bank, as successor to First Fidelity Bank, National Association, as Trustee dated as of October 1, 2005 (Exhibit 99.2, PSNH Current Report on Form 8-K filed October 6, 2005, File No. 001-06392)

 4.1.2 Twenty-Second Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of June 1, 2019 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on July 3, 2019 (File No. 001-06392)

 4.1.3 Twenty-Third Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of August 1, 2020 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on August 31, 2020 (File No. 001-06392)

 4.1.4 Twenty-Fourth Supplemental Indenture, between PSNH and U.S. Bank National Association, as Trustee dated as of June 1, 2021 (Exhibit 4.1, PSNH Current Report on Form 8-K filed on June 21, 2021 (File No. 001-06392)

 E-5

 4.1.5 Twenty-Fifth Supplemental Indenture, between PSNH and U.S. Bank Trust Company, National Association, as Trustee dated as of January 1, 2023 ( Exhibit 4.1, PSNH Current Report on Form 8-K filed on January 11, 2023 (File No. 001-06392)

 4.1.6 Twenty-Sixth Supplemental Indenture, between PSNH and U.S. Bank Trust Company, National Association, as Trustee dated as of September 1, 2023 ( Exhibit 4.1, PSNH Current Report on Form 8-K filed on September 25, 2023 (File No. 001-06392)

 4.1.7 Twenty-Seventh Supplemental Indenture, between PSNH and U.S. Bank Trust Company, National Association, as Trustee dated as of April 1, 2024 (Exhibit 4.3, PSNH Current Report on Form 8-K filed on April 1, 2024 (File No. 001-06392)

 4.2 Series A Loan and Trust Agreement among Business Finance Authority of the State of New Hampshire and PSNH and State Street Bank and Trust Company, as Trustee (Tax Exempt Pollution Control Bonds) dated as of October 1, 2001 (Exhibit 4.3.4, 2001 Eversource Energy Form 10-K filed March 22, 2002, File No. 001-05324)

 (F) Eversource Energy, The Connecticut Light and Power Company and Public Service Company of New Hampshire

 4.1 Second Amended and Restated Credit Agreement, dated as of October 15, 2021, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender ( Exhibit 10.12, 2021 Eversource Form 10-K filed on February 17, 2022)

 4.1.1 First Amendment to Second Amended and Restated Credit Agreement and Extension Agreement, dated October 17, 2022, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender ( Exhibit 4, Eversource Form 10-Q filed on November 4, 2022)

 4.1.2 Second Amendment to Second Amended and Restated Credit Agreement and Extension Agreement, dated November 29, 2023, by and among Eversource, Aquarion Water Company of Connecticut, NSTAR Gas, CL&P, PSNH, Yankee Gas and EGMA and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender (Exhibit 4.1.2, Eversource Form 10-K filed on February 14, 2024)

 4.1.3 Third Amendment to Second Amended and Restated Credit Agreement, dated October 11, 2024, by
 and among Eversource Energy, Aquarion Water Company of Connecticut, NSTAR Gas Company, The Connecticut Light and Power Company, Public Service Company of New Hampshire, Yankee Gas Services Company and Eversource Gas Company of Massachusetts and the Banks named therein, pursuant to which Bank of America, N.A. serves as Administrative Agent and Swing Line Lender ( Exhibit 4, Eversource Form 10-Q filed on November 6, 2024)

 10. Material Contracts

 10.1 Lease between The Rocky River Realty Company and Eversource Energy Service Company, dated as of July 1, 2008 (Exhibit 10.1, 2017 Eversource Form 10-K filed on February 26, 2018)

 *+10.2 Eversource Energy Board of Trustees' Compensation Arrangement Summary

 +10.3 Eversource Supplemental Executive Retirement Program, as amended to include the Eversource Supplemental Cash Balance Pension Plan, effective January 1, 2025 (Exhibit 10.1, 2015 Eversource Energy Form 8-K filed December 6, 2024, File No. 001-05324)

 +10.4 Eversource Energy Deferred Compensation Plan for Executives effective as of January 1, 2014 (Exhibit 10.6, 2015 Eversource Energy Form 10-K filed February 26, 2016, File No. 001-05324)

 +10.4.1 Amendment No 1 to the Eversource Deferred Compensation Plan effective February 7, 2018 (Exhibit 10.6.1, Eversource Energy Annual Report on Form 10-K filed February 27, 2020, File No. 001-05324)

 +10.5 NSTAR Excess Benefit Plan, effective August 25, 1999 (Exhibit 10.1 1999 NSTAR Form 10-K/A filed September 29, 2000, File No. 001-14768)

 E-6

 +10.5.1 NSTAR Excess Benefit Plan, incorporating the NSTAR 409A Excess Benefit Plan, as amended and restated effective January 1, 2008, dated December 24, 2008 (Exhibit 10.1.1 2008 NSTAR Form 10-K filed February 9, 2009, File No. 001-14768)

 +10.6 Amended and Restated Change in Control Agreement by and between Joseph R. Nolan, Jr. and NSTAR, dated November 15, 2007 (Exhibit 10.13, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

 +10.7 Amended and Restated Change in Control Agreement by and between Senior Vice President and NSTAR, dated November 15, 2007 (Exhibit 10.15, 2007 NSTAR Form 10-K filed February 11, 2008, File No. 001-14768)

 (B) Eversource Energy, The Connecticut Light and Power Company, NSTAR Electric Company and Public Service Company of New Hampshire

 10.1 Amended and Restated Form of Service Contract between each of Eversource Energy, CL&P, NSTAR Electric Company and Eversource Energy Service Company dated as of January 1, 2014. (Exhibit 10.1, Eversource Energy Form 10-K filed on February 25, 2014, File No. 001-05324)

 10.2 Transmission Operating Agreement between the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc. dated as of February 1, 2005 (Exhibit 10.29, 2004 Eversource Energy Form 10-K filed March 17, 2005, File No. 001-05324)

 10.2.1 Rate Design and Funds Disbursement Agreement among the Initial Participating Transmission Owners, Additional Participating Transmission Owners and ISO New England, Inc., effective June 30, 2006 (Exhibit 10.22.1, 2006 Eversource Energy Form 10-K filed March 1, 2007, File No. 001-05324)

 10.3 Eversource Energy's Third Amended and Restated Tax Allocation Agreement dated as of April 10, 2012, (Exhibit 10.1 Eversource Energy Form 10-Q for Quarter Ended June 30, 2012 filed August 7, 2012, File No. 001-05324)

 +10.4 Amended and Restated Incentive Plan Effective January 1, 2009 (Exhibit 10.3, Eversource Energy Form 10-Q for the Quarter Ended September 30, 2008 filed November 10, 2008, File No. 001-05324)

 +10.5 2018 Eversource Energy Incentive Plan (Exhibit 99.2, Eversource Energy Current Report on Form 8-K dated May 3, 2018)

 10.5.1 Amendment Number 1 to the 2018 Eversource Incentive Plan, effective May 3, 2023 ( Appendix A to the Eversource Energy Definitive Proxy Statement for the 2023 Eversource Energy Annual Meeting of Shareholders, dated March 24, 2023)

 +10.6 Trust under Supplemental Executive Retirement Plan dated May 2, 1994 (Exhibit 10.33, 2002 Eversource Energy Form 10-K filed March 21, 2003, File No. 001-05324)

 +10.6.1 First Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of December 10, 2002 (Exhibit 10 (B) 10.19.1, 2003 Eversource Energy Form 10-K filed March 12, 2004, File No. 001-05324)

 +10.6.2 Second Amendment to Trust Under Supplemental Executive Retirement Plan, effective as of November 12, 2008 (Exhibit 10.12.2, 2008 Eversource Energy Form 10-K filed February 27, 2009, File No. 001-05324)

 +10.7 Amended and Restated Employment Agreement with Gregory B. Butler, effective January 1, 2009 (Exhibit 10.7, 2008 Eversource Energy 2010 Form 10-K filed February 27, 2009, File No. 001-05324)

 (C) Eversource Energy, The Connecticut Light and Power Company, Public Service Company of New Hampshire and NSTAR Electric Company

 10.1 Eversource Energy Service Company Transmission and Ancillary Service Wholesale Revenue Allocation Methodology among The Connecticut Light and Power Company, NSTAR Electric Company, Public Service Company of New Hampshire, Holyoke Water Power Company and Holyoke Power and Electric Company Trustee dated as of January 1, 2008 (Exhibit 10.1, Eversource Energy Form 10-Q for the Quarter Ended March 31, 2008 filed May 9, 2008, File No. 001-05324)

 *19. Insider Trading Policy

 *21. Subsidiaries of the Registrant

 E-7

 *23. Consents of Independent Registered Public Accounting Firm

 *31. Rule 13a - 14(a)/15 d - 14(a) Certifications

 31 Certification by the Chairman of the Board, President and Chief Executive Officer of Eversource Energy pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 31.1 Certification by the Chief Financial Officer of Eversource Energy pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 (B) The Connecticut Light and Power Company

 31 Certification by the Chairman and Chief Executive Officer of CL&P pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 31.1 Certification by the Chief Financial Officer of CL&P pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 (C) NSTAR Electric Company

 31 Certification by the Chairman of NSTAR Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 31.1 Certification by the Chief Financial Officer of NSTAR Electric Company pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 (D) Public Service Company of New Hampshire

 31 Certification by the Chairman of PSNH pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 31.1 Certification by the Chief Financial Officer of PSNH pursuant to Section 302 of the Sarbanes-Oxley Act of 2002

 *32 18 U.S.C. Section 1350 Certifications

 32 Certification by the Chairman of the Board, President and Chief Executive Officer and the Chief Financial Officer of Eversource Energy pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 (B) The Connecticut Light and Power Company

 32 Certification by the Chairman and Chief Executive Officer and the Chief Financial Officer of CL&P pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 (C) NSTAR Electric Company

 32 Certification by the Chairman and the Chief Financial Officer of NSTAR Electric Company pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 (D) Public Service Company of New Hampshire

 32 Certification by the Chairman and the Chief Financial Officer of PSNH pursuant to 18 U.S.C. Section 1350, as adopted pursuant to Section 906 of the Sarbanes-Oxley Act of 2002

 *97 Clawback Policy

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 E-9

 EVERSOURCE ENERGY

 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.

 EVERSOURCE ENERGY

 By:
 /s/

 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.

 POWER OF ATTORNEY

 Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his or her true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him or her and in his or her name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he or she might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his or her substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

 Title
 Date

 /s/
 Chairman of the Board, President and

 Chief Executive Officer

 (Principal Executive Officer)

 /s/
 Executive Vice President, Chief Financial Officer

 and Treasurer

 (Principal Financial Officer)

 /s/
 Vice President, Controller

 and Chief Accounting Officer

 /s/
 Cotton M. Cleveland

 Cotton M. Cleveland

 /s/
 Linda Dorcena Forry

 Linda Dorcena Forry

 /s/
 Gregory M. Jones

 Gregory M. Jones

 /s/
 Loretta D. Keane

 Loretta D. Keane

 E-10

 Title
 Date

 /s/
 John Y. Kim

 John Y. Kim

 /s/
 David H. Long

 David H. Long

 /s/
 Daniel J. Nova

 Daniel J. Nova

 /s/
 Frederica M. Williams

 Frederica M. Williams

 E-11

 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.

 By:
 /s/

 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.

 POWER OF ATTORNEY

 Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

 Title
 Date

 /s/
 Chairman and Chief Executive Officer

 and a Director

 (Principal Executive Officer)

 /s/
 Executive Vice President, Chief Financial Officer

 and Treasurer and a Director

 (Principal Financial Officer)

 /s/
 Executive Vice President and General Counsel

 and a Director

 /s/
 Vice President, Controller

 and Chief Accounting Officer

 /s/
 Penelope M. Conner

 Director

 Penelope M. Conner

 /s/
 Chandler J. Howard

 Director

 Chandler J. Howard

 /s/
 Patrick J. McGrath

 Director

 Patrick J. McGrath

 /s/
 Ian G. Nicholson

 Director

 Ian G. Nicholson

 E-12

 NSTAR ELECTRIC COMPANY

 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.

 NSTAR ELECTRIC COMPANY

 By:
 /s/

 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.

 POWER OF ATTORNEY

 Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

 Title
 Date

 /s/
 Chairman and a Director

 (Principal Executive Officer)

 /s/
 Chief Executive Officer and a Director

 /s/
 Executive Vice President, Chief Financial Officer

 and Treasurer and a Director

 (Principal Financial Officer)

 /s/
 Executive Vice President and General Counsel

 and a Director

 /s/
 Vice President, Controller

 and Chief Accounting Officer

 E-13

 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

 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.

 PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE

 By:
 /s/

 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.

 POWER OF ATTORNEY

 Each person whose signature appears below constitutes and appoints Gregory B. Butler, John M. Moreira and Jay S. Buth and each of them, his true and lawful attorneys-in-fact and agents, with full power of substitution and resubstitution, for him and in his name, place and stead, in any and all capacities, to sign any and all amendments to this Annual Report on Form 10-K, and to file the same, with all exhibits thereto, and other documents in connection therewith, with the Securities and Exchange Commission, granting unto said attorneys-in-fact and agents, and each of them, full power and authority to do and perform each and every act and thing requisite and necessary to be done, as fully to all intents and purposes as he might or could do in person, hereby ratifying and confirming all that said attorneys-in-fact and agents or any of them, or their or his substitute or substitutes, may lawfully do or cause to be done by virtue hereof.

 Title
 Date

 /s/
 Chairman and a Director

 (Principal Executive Officer)

 /s/
 Chief Executive Officer and a Director

 /s/
 Executive Vice President, Chief Financial Officer

 and Treasurer and a Director

 (Principal Financial Officer)

 /s/
 Executive Vice President and General Counsel

 and a Director

 /s/
 Vice President, Controller

 and Chief Accounting Officer

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