EVERSOURCE ENERGY 10-K

es-20231231 UNITED STATES SECURITIES AND EXCHANGE COMMISSION WASHINGTON, D.C. 20549 FORM 10-K ☒ ANNUAL REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the fiscal year ended December 31 , 2023 or ☐ TRANSITION REPORT PURSUANT TO SECTION 13 OR 15(d) OF THE SECURITIES EXCHANGE ACT OF 1934 For the transition period from ____________ to ____________ 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 THE CONNECTICUT LIGHT AND POWER COMPANY (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. Eversource Energy Large accelerated filer ☒ Accelerated filer ☐ Non-accelerated filer ☐ Smaller reporting company ☐ Emerging growth company ☐ The Connecticut Light and Power Company Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting company ☐ Emerging growth company ☐ NSTAR Electric Company Large accelerated filer ☐ Accelerated filer ☐ Non-accelerated filer ☒ Smaller reporting company ☐ Emerging growth company ☐ Public Service Company of New Hampshire 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 Eversource Energy ☐ ☒ The Connecticut Light and Power Company ☐ ☒ NSTAR Electric Company ☐ ☒ Public Service Company of New Hampshire ☐ ☒ 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, 2023) was $ 24,734,207,777 based on a closing market price of $70.92 per share for the 348,762,095 common shares outstanding held by non-affiliates on June 30, 2023. 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, 2024 Eversource Energy Common Shares, $5.00 par value 349,687,183 shares The Connecticut Light and Power Company Common Stock, $10.00 par value 6,035,205 shares NSTAR Electric Company Common Stock, $1.00 par value 200 shares Public Service Company of New Hampshire Common Stock, $1.00 par value 301 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 2022 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, 2024, 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, HWP Company, 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 The Connecticut Light and Power Company NSTAR Electric NSTAR Electric Company PSNH Public Service Company of New Hampshire 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 North East Offshore North East Offshore, LLC, an offshore wind business being developed jointly by Eversource and Denmark-based Ørsted 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: BOEM U.S. Bureau of Ocean Energy Management 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 Accumulated Deferred Income Taxes 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 i ESOP Employee Stock Ownership Plan Eversource 2022 Form 10-K The Eversource Energy and Subsidiaries 2022 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 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) OREC Offshore Wind Renewable Energy Certificate 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 EVERSOURCE ENERGY AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES 2023 FORM 10-K ANNUAL REPORT TABLE OF CONTENTS Page PART I Item 1. Business 2 Item 1A. Risk Factors 16 Item 1B. Unresolved Staff Comments 22 Item 1C. Cybersecurity 22 Item 2. Properties 23 Item 3. Legal Proceedings 26 Item 4. Mine Safety Disclosures 26 Information About Our Executive Officers 26 PART II Item 5. Market for the Registrants’ Common Equity, Related Stockholder Matters and Issuer Purchases of Equity Securities 27 Item 6. Removed and Reserved 28 Item 7. Management’s Discussion and Analysis of Financial Condition and Results of Operations 29 Item 7A. Quantitative and Qualitative Disclosures about Market Risk 59 Item 8. Financial Statements and Supplementary Data 60 Item 9. Changes in and Disagreements with Accountants on Accounting and Financial Disclosure 143 Item 9A. Controls and Procedures 143 Item 9B. Other Information 143 PART III Item 10. Directors, Executive Officers and Corporate Governance 144 Item 11. Executive Compensation 144 Item 12. Security Ownership of Certain Beneficial Owners and Management and Related Stockholder Matters 144 Item 13. Certain Relationships and Related Transactions, and Director Independence 145 Item 14. Principal Accountant Fees and Services 145 PART IV Item 15. Exhibits and Financial Statement Schedules 147 Item 16. Form 10-K Summary 147 Signatures E- 9 iii EVERSOURCE ENERGY AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES 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," "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, • our ability to complete the offshore wind investments sales process on the timelines, terms and pricing we expect; if we and the counterparties are unable to satisfy all closing conditions and consummate the purchase and sale transactions with respect to our offshore wind assets; if Sunrise Wind does not win in the OREC contract solicitation process; if we are unable to qualify for investment tax credits related to these projects; if we experience variability in the projected construction costs of the offshore wind projects, if there is a deterioration of market conditions in the offshore wind industry; and if the projects do not commence operation as scheduled or within budget or are not completed, • 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 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. 1 EVERSOURCE ENERGY AND SUBSIDIARIES THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES PART I 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. 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 has an offshore wind business, which includes 50 percent ownership interests in three offshore wind projects and a tax equity investment in one of the projects. For further information, see "Offshore Wind Business” below. 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. 2 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, 2023, CL&P furnished retail franchise electric service to approximately 1.28 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. CL&P's retail rates include a delivery service component, which includes distribution, transmission, conservation, renewable energy programs and other charges that are assessed on all customers. 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. The rates established by PURA for CL&P are comprised of the following: • 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 the PURA, with any differences refunded to, or recovered from, customers. • 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 the PURA, with any differences refunded to, or recovered from, customers. • 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. The FMCC has both a bypassable component and a non-bypassable component, and 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. • 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. • 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. • 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. 3 As required by regulation, CL&P has entered into long-term contracts for the purchase of (i) products from renewable energy facilities, which may include energy, renewable energy certificates, or capacity, (ii) capacity-related contracts with generation facilities, and (iii) contracts for peaking capacity. Some of these contracts are subject to sharing agreements with UI, whereby CL&P is responsible for 80 percent and UI for 20 percent of the net costs or benefits. CL&P's portion of the costs and benefits of these contracts will be paid by, or refunded to, CL&P's customers. Distribution Rate Case : 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. CL&P Settlement Agreement : 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. 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. 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 2023, CL&P supplied approximately 56 percent of its customer load at SS or LRS rates while the other 44 percent of its customer load had migrated to competitive energy suppliers. In terms of the total number of CL&P customers, this equates to 25 percent being on competitive supply, while 75 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 2024. For the second half of 2024, CL&P has 70 percent of its SS load under full requirements supply contracts and intends to purchase an additional 30 percent of full requirements. Ten percent of the SS load for 2025 has been procured. CL&P obtained a full requirements supply contract for its LRS load through June 2024 and intends to purchase 100 percent of full requirements for LRS for the remainder of 2024. 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, 2023, NSTAR Electric furnished retail franchise electric service to approximately 1.49 million customers in 161 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. 4 The rates established by the DPU for NSTAR Electric are comprised of the following: • 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. • 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. As approved by the DPU, NSTAR Electric has signed long-term commitments for the purchase of energy from renewable energy facilities. 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 2023 performance as the company achieved results at or above target for all of its SQ metrics in 2023. 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 32 percent of its residential and 29 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 7 percent of its large C&I customers every three months. During 2023, NSTAR Electric supplied approximately 18 percent of its overall customer load at basic service rates. The remaining 82 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. 5 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, 2023, PSNH furnished retail franchise electric service to approximately 539,000 retail customers in 215 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. The rates established by the NHPUC for PSNH are comprised of the following: • 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. • 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. • A Stranded Cost Recovery Charge (SCRC), which allows PSNH to recover its stranded costs, including above-market expenses incurred under mandated power purchase obligations, other long-term investments and obligations, and the remaining costs associated with the 2018 sales of its generation facilities. • 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. • 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. 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 . The default energy service charge changes semi-annually, the SCRC rate changes annually with the option to change semi-annually beginning in 2023, and the transmission and SBC rates change annually. These rates are reconciled annually in accordance with the policies and procedures of the NHPUC, with any differences refunded to, or recovered from, customers. As approved by the NHPUC, PSNH has signed long-term commitments for the purchase of energy from renewable energy facilities. Distribution Rate Case : PSNH’s distribution rates were established in a December 2020 NHPUC-approved settlement agreement, with rates effective January 1, 2021. PSNH was also permitted three step increases, effective January 1, 2021, August 1, 2021, and August 1, 2022, to reflect plant additions in calendar years 2019, 2020 and 2021, respectively. The NHPUC approved a rate increase effective February 1, 2022 designed to collect $1.1 million dollars annually to fund a reserve account to pay for arrearage forgiveness for customers with past due balances and the New Start Program. On October 20, 2022, the NHPUC approved the third step adjustment for 2021 plant in service to recover a revenue requirement of $8.9 million, with rates effective November 1, 2022. The total approved revenue requirement increase was collected over the remainder of the rate year (November 1, 2022 – July 31, 2023). 6 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 64 percent of its residential and small C&I customers and for 9 percent of its large C&I customers. During 2023, PSNH supplied approximately 37 percent of its customer load at default energy service rates while the other 63 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 Wholesale transmission revenues are recovered through FERC-approved formula rates. Annual transmission revenue requirements include recovery of transmission costs and include a return on equity applied to transmission rate base. Transmission revenues are collected from New England customers, including distribution customers of CL&P, NSTAR Electric and PSNH. The transmission rates provide for an annual true-up of estimated to actual costs. The financial impacts of differences between actual and estimated costs are deferred for future recovery from, or refund to, transmission customers. 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 2023, our estimated transmission rate base was approximately $9.8 billion, including approximately $4.1 billion at CL&P, $3.9 billion at NSTAR Electric, and $1.8 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. At this time, Eversource cannot predict how and when FERC will address the Court’s findings on the remand of the MISO FERC opinions or any potential associated impact on the NETOs’ four pending ROE complaint cases. Given the significant uncertainty regarding the applicability of the FERC opinions in the MISO transmission owners' two complaint cases to the NETOs' pending four complaint cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaint periods at this time. As well, Eversource cannot reasonably estimate a range of loss for any of the four complaint proceedings at this time. 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. 7 NATURAL GAS DISTRIBUTION SEGMENT NSTAR Gas distributes natural gas to approximately 307,000 customers in 59 communities in central and eastern Massachusetts. EGMA distributes natural gas to approximately 336,000 customers in 66 communities throughout Massachusetts. Yankee Gas distributes natural gas to approximately 252,000 customers in 85 cities and towns in Connecticut. Total throughput (sales and transportation) in 2023 was approximately 67.1 Bcf for NSTAR Gas, 54.2 Bcf for EGMA, and 56.4 Bcf for Yankee Gas. 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. 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 50 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 1.8 Bcf of LNG and 0.1 Bcf of LPG storage, with a total vaporization capacity of 0.14 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 delivery and supply rates are established by the DPU and the PURA and are comprised of: • 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 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 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. 8 • 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 : 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, occurring on November 1, 2024 and 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. 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. 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 2023 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. 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. At this time, Eversource cannot predict the ultimate outcome of this proceeding, as the Company and other LDCs are seeking formal clarity from the DPU to fully understand the resulting impact to their natural gas businesses and the associated timing of any impacts. The Company does not believe there is any indication of an inability to recover costs or risk of impairment of our natural gas assets at this time. 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. 9 In September 2021, PURA undertook a review of Connecticut natural gas companies’ infrastructure system expansion plan (SEP) to determine if the SEP continues to be in the best interest of the state’s comprehensive energy strategy. On April 27, 2022, PURA issued an order for the immediate winding down of the SEP by (1) ending the enrollment of new customers in the SEP program and permitting only a specific group of potential customers who have executed a services agreement with a natural gas company on or before a specified date (subsequently approved as August 16, 2022) to qualify for incentives under the current SEP; (2) directing all surplus non-firm margin to be deferred as a regulatory liability and applied to rate base in a future rate proceeding; and (3) directing the natural gas companies to cease all outbound and passive marketing regarding the SEP. On July 15, 2022, Yankee Gas appealed the portion of this order pertaining to the deferral of non-firm margin as a reduction to future rate base. On October 24, 2023, Yankee Gas informed the Connecticut Superior Court that the parties mutually agreed to resolve the appeal through a stipulation, which clarified that PURA will decide in Yankee Gas’s next gas rate case the ratemaking treatment of the deferred non-firm margin. Yankee Gas evaluated the prospective impact of this proceeding and does not believe the impact will be material to its future financial position, results of operations and cash flows. 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 8.6 Bcf, and 1.9 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 241,000 residential, commercial, industrial, municipal and fire protection and other customers, in 72 towns and cities in Connecticut, Massachusetts and New Hampshire. As of December 31, 2023, approximately 92 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. 10 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. 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. OFFSHORE WIND BUSINESS Eversource’s offshore wind business includes 50 percent ownership interests in wind partnerships, which collectively hold the Revolution Wind, South Fork Wind and Sunrise Wind projects, and a tax equity investment in South Fork Wind. The offshore wind projects are being developed and constructed through joint and equal partnerships with Ørsted. Revolution Wind is a 704 MW offshore wind power project located approximately 15 miles south of the Rhode Island coast, and South Fork Wind is a 130 MW offshore wind power project located approximately 35 miles east of Long Island. Sunrise Wind is a 924 MW offshore wind facility located 35 miles east of Montauk Point, Long Island. The completion dates for these projects are subject to federal permitting through BOEM, engineering, state siting and permitting in New York, Rhode Island and Massachusetts and construction schedules. We are in the process of selling our existing 50 percent interests in the three jointly-owned offshore wind projects. In connection with the sales process, we have recorded impairments to the carrying value of the offshore wind investments to reflect the investments at estimated fair value. For more information on these projects, the sales process, and the impairment evaluations, 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 . CAPITAL EXPENDITURES For information on capital expenditures and projects during 2023, 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. 11 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 2023, the total RPS obligation was 35.0 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 2023, the RPS and Clean Energy Standard (CES) requirements were 59.2 percent, and will ultimately reach 63.1 percent in 2025. Massachusetts electric suppliers were also required to meet Alternative Energy Portfolio Standards (APS) of 5.75 percent and Clean Peak Energy Standards (CPS) of 6.0 percent in 2023. Those requirements will reach 6.25 and 9.00 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 2023, the total RPS obligation was 23.4 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, resource areas, 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 Board’s Governance, Environmental and Social Responsibility Committee 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, 2023, 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 $128.2 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 $117.1 million of the total $128.2 million as of December 31, 2023. 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. 12 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 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 continues to receive increasing focus from the federal and state governments. The Biden administration has 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 calls 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 offer opportunities for Eversource to invest in projects that have the ability to reduce emissions in the region while benefiting our communities and shareholders. Similarly, 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. Similarly, the Massachusetts “Future of Gas” docket (DPU 20-80) looks to identify ways 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 or heating change. Eversource continually evaluates the evolving regulatory landscape concerning climate change, which could potentially lead to additional requirements and additional rules and regulations that could impact how we operate our businesses. Potential future environmental statutes and regulations, such as additional greenhouse gas reduction regulations to address global 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 event-driven 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; • 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 and electric vehicle infrastructure; • 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; • Investigating emerging technologies such as energy storage and automation programs that improve reliability; • Implementing programs to address risks that may impact water availability and water quality; and • Evaluating opportunities for our natural gas system and exploring alternative, less carbon-intense, technologies like renewable natural gas and geothermal for heating. 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 all future substations are being “flood hardened” to better protect our system against storm surges associated with the increasing risk of severe weather. 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 has made a corporate commitment to reduce Scope 1 and 2 GHG emissions from our operations and reach carbon neutrality by 2030. In December 2023, we submitted an application to the Science Based Target initiative (SBTi) seeking validation of a broader GHG target, which will expand our emission reduction efforts and include indirect Scope 3 sources. Greenhouse gas emissions from our operations consist primarily 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, operating our facilities and vehicle fleet, and sulfur hexafluoride (SF6) leaks from electric equipment. To measure our influences on climate change, we quantify and publicly report our operational carbon footprint through a third-party verified GHG emission inventory on an annual basis. Our initiatives to reduce GHG emissions across our company include improving energy efficiency and expanding the use of renewable energy at our buildings, utilizing alternative fuels and introducing more hybrid vehicles into the company fleet, reducing fugitive emissions of methane and SF6 by replacing leak-prone natural gas pipes, improving maintenance of SF6 electrical equipment, and piloting innovative technologies, such as alternative SF6 electrical equipment. 13 Our business is also exposed to climate-related transitional risks, 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 clean energy 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 low carbon 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, diverse 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 our employees. 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, developing talent, fostering teamwork and creating a diverse, equitable and inclusive workplace. We have established metrics and annual goals on our corporate scorecard, including safety performance, talent diversity and employee engagement, that drive accountability for progress across all areas of the business. As of December 31, 2023, Eversource Energy employed a total of 10,171 employees, excluding temporary employees, of which 1,529 were employed by CL&P, 2,044 were employed by NSTAR Electric, and 830 were employed by PSNH. In addition, 4,007 were employed by Eversource Service, Eversource's service company, that provides support services to all Eversource operating companies. Approximately 49 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 Eversource Corporate Days Away Restricted Time (DART) and High Energy Field Observations, among others, to monitor safety performance. Our DART safety performance was 0.81 in 2023, measured by days away, restricted or transferred per 100 workers, using the DART-OSHA method of measurement. Diversity, Equity & Inclusion. Our commitment to Diversity, Equity & Inclusion (DEI) is critical to building a diverse, empowered and engaged team that delivers superior service safely to our customers. A diverse workforce and inclusive culture contribute to our success and sustainability by driving innovation and creating trusted relationships with our employees, customers, suppliers, and community partners. We continue to identify and support many programs and agencies that address disparities in our communities and beyond. We also remain committed to developing a workforce that fully reflects the diversity of the people and communities we serve. Our hiring practices emphasize inclusion, and we encourage employees to embrace different people, perspectives, and experiences in our workplace and within our communities. Additionally, our leadership behaviors underscore the importance of creating inclusive teams, where employees’ voices and contributions are essential to delivering superior customer service. Eversource continues to develop a diverse workforce and has DEI goals and initiatives for diversity in leadership promotions and new hires, diverse external hires, number of diverse applicants for jobs, key talent, workforce representation including female employees, diverse employees, and veteran hires, leadership engagement, community support and supplier spending. Eversource drives accountability for DEI progress throughout the company and executive compensation is linked to meeting these goals. We sustained our successful drive to increase workforce diversity in 2023 with 55.9% of our external hires being women and/or people of color and 48.1% percent of new hires and promotions into leadership roles being women and/or people of color. Eversource’s executive leadership team promotes and supports DEI by building and leading diverse, inclusive work teams with high engagement. Leaders are committed to growing a pipeline of diverse talent, leveraging multiple perspectives to improve customer service, using diverse suppliers, and engaging with multicultural organizations in our communities. Our DEI council, business resource groups, and cross-functional pro- 14 equity advisory team, which developed equity guidelines and began to implement justice and equity training to all employees starting in 2022 and continuing into 2024, provide our leaders with valuable feedback on the impact of our DEI and environmental justice efforts. Eversource's Board of Trustees is committed to diversity, equity and inclusion and receives regular monthly progress updates. 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 diversity in gender, race, ethnicity and personal background 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 needs and to ensure that Eversource acquires, develops and retains diverse, capable talent. Eversource supports and develops its employees through training and development programs that build and strengthen employees’ leadership and skill set. 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, with a focus on environmental justice and historically marginalized communities. 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 Item 11, Executive Compensation , included in this Annual Report on Form 10-K, as well as our 2022 Sustainability Report and our 2022 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 (http://www.sec.gov/edgar/searchedgar/companysearch.html), 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, 107 Selden Street, Berlin, CT 06037. 15 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 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, 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. Offshore Wind Business Risk: Our financial position and future results could be materially adversely affected if we are unable to sell our 50 percent interests in three offshore wind projects on the timelines, terms and pricing we expect, if we and the counterparties are unable to satisfy all closing conditions and consummate the purchase and sale transactions with respect to our offshore wind assets, if Sunrise Wind does not win in the OREC contract solicitation process, if we are unable to qualify for investment tax credits related to these projects, if we experience variability in the projected construction costs of the offshore wind projects, if there is a deterioration of market conditions in the offshore wind industry, and if the projects do not commence operation as scheduled or within budget or are not completed. 16 Our offshore wind business includes 50 percent ownership interests in three jointly-owned offshore wind projects being developed and constructed. The development and construction of these offshore wind electric generation facilities involves numerous significant risks including meeting construction schedules, federal, state and local permitting and regulatory approval processes, scheduling or permitting delays, cost overruns, higher interest rates, tax strategies and changes to federal tax laws impacting the offshore wind partnership’s ability to monetize tax attributes, new legislation impacting the industry, the cancellation of any projects, and actions of our strategic partner . Operational risks of these offshore wind electric generation facilities include maintaining continuing interconnection arrangements, power purchase agreements, or other market mechanisms, as well as interconnecting utility and Regional Transmission Organizations rules, policies, procedures and FERC tariffs that permit future offshore wind project operations , and capacity factors once projects are placed in operation. These risks could impact our offshore wind partnership’s ability to generate returns from its offshore wind projects and result in lower investment returns. We have entered into agreements to sell our interest in the three offshore wind projects, however we may be unable to complete the sales of these projects on the timelines and for the sales value we expect. If the ultimate sales value of our interest in these projects is lower than expected, or we are unable to sell our interests, it could have an adverse effect on our financial condition and results of operations. The sales agreements are subject to certain regulatory approvals as well as other conditions, and we may be unable to satisfy all closing conditions necessary to consummate the purchase and sale transactions. The purchaser of the Revolution Wind and South Fork Wind projects may be unable to reach a partnership agreement with Ørsted, which is a condition of closing that transaction. The sale of the Sunrise Wind project to Ørsted is dependent on the successful outcome of Sunrise Wind’s re-bidding process of its OREC contract in the New York solicitation. If Sunrise Wind were to lose to a competing bid in the New York solicitation, then the existing OREC contract for Sunrise Wind will be cancelled according to the state’s requirements, and Eversource and Ørsted’s joint venture for Sunrise Wind will remain in place. That scenario could adversely impact the ability to sell the Sunrise Wind project in the future, and could result in the project to be abandoned. If the Sunrise Wind project were to be abandoned, there would be cancellation and other abandonment costs incurred, and those costs could be above amounts already assumed in our impairment evaluation and reflected in the current fair value on our balance sheet, which could have an adverse effect on our financial condition and results of operations. Future cash flows resulting from the expected sales are also impacted by the ability to qualify the Revolution Wind project for investment tax credit adders, as included in the Inflation Reduction Act. Evaluating the project’s qualifications to achieve these investment tax credit adders requires significant judgment, and we may be unable to meet these qualifications. Additionally, for Revolution Wind and South Fork Wind, there could be cost overruns on the projects through each project's respective commercial operation date, which would not be recovered in the expected sales price and other potential future payments to maintain transaction economics required of Eversource. Amounts incurred above those that have already been assumed in our impairment evaluation and reflected in the current fair value on our balance sheet would adversely impact our financial position, results of operations and cash flows. These risks could adversely affect the ultimate value of the wind projects and result in an additional, significant impairment in a future period, which could have a material adverse effect on our financial condition and results of operations. Lower-than-expected sales prices, or the inability to sell the wind projects, could also result in liquidity issues, negatively impact certain of our financial metrics and operations plan, or could result in a downgrade in our credit rating, which could increase our cost of borrowing and cost of capital or restrict our ability to access the capital markets. 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 or earn an adequate return. Adverse decisions in our proceedings could adversely affect our 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 w ater businesses. 17 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 decisions may 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 could have an adverse effect on our 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 financial position, results of operations and cash flows. 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, results of operations , financial condition 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 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, and increased customer energy demand, the cost of energy supply in New England remains 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. The significant supply 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 t o 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. 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 bus iness, compliance with proposed water quality regulations, including those for PFAS and lead, could require the construction of facilities and replacement of customer lead service lines, respectively. 18 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. For further information, see Item 1, Business – Other Regulatory and Environmental Matters , included in this Annual Report on Form 10-K. 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 extreme weather events. Customers’ energy and water needs vary with weather conditions, primarily 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 snow storms, tornadoes, micro-bursts, hurricanes, floods, droughts, wildfires, and other natural disasters, 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 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 and lead. Our water systems include impounding dams and reservoirs of various sizes. Although we believe our dams are structurally sound and well-maintained, significant damage to these facilities, or a significant decrease in the water in our reservoirs, could adversely affect our ability to provide water to our customers until the facilities and a sufficient amount of water in our reservoirs 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. 19 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, economic events or factors, environmental and community 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 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 remains volatile, and as a result, we are seeing delivery delays of certain goods , particularly certain types 20 of transformers. If significant difficulties in the global supply chain cycle or inflationary impacts were to worsen, 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 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 have increased and may continue to 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. A downgrade 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, 2023 , totaled $4. 53 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 condition 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. 21 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 risks, 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 which 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. 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 or ransomware 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 National Institute of Standards and Technology framework; a widely accepted framework utilized by 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. • 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. 22 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, 2023, there were no risks from cybersecurity threats, including due to any previous cybersecurity 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, 2023, Eversource and our electric operating subsidiaries owned the following: Electric Distribution Electric Transmission Eversource Number of substations owned 455 76 Transformer capacity (in kVa) 47,706,000 16,222,000 Overhead lines (in circuit miles) 40,673 3,992 Underground lines (in circuit miles) 18,119 423 Capacity range of overhead transmission lines (in kV) N/A 69 to 345 Capacity range of underground transmission lines (in kV) N/A 69 to 345 CL&P NSTAR Electric PSNH Distribution Transmission Distribution Transmission Distribution Transmission Number of substations owned 157 21 174 30 124 25 Transformer capacity (in kVa) 21,850,000 3,184,000 21,420,000 8,688,000 4,436,000 4,350,000 Overhead lines (in circuit miles) 16,738 1,679 11,619 1,260 12,316 1,053 Underground lines (in circuit miles) 6,884 143 9,135 277 2,100 3 Capacity range of overhead transmission lines (in kV) N/A 69 to 345 N/A 69 to 345 N/A 115 to 345 Capacity range of underground transmission lines (in kV) N/A 69 to 345 N/A 115 to 345 N/A 115 Eversource CL&P NSTAR Electric PSNH Underground and overhead line transformers in service 638,464 293,942 173,705 170,817 Aggregate capacity (in kVa) 39,360,574 16,730,938 15,327,341 7,302,295 Electric Generating Plants As of December 31, 2023, NSTAR Electric owned the following solar power facilities: Type of Plant Number of Sites Year Installed Capacity (kilowatts, dc) Solar Fixed Tilt, Photovoltaic 22 2010 - 2019 70,000 CL&P and PSNH do not own any electric generating plants. Natural Gas Distribution System As of December 31, 2023, NSTAR Gas owned 22 active gate stations, 147 district regulator stations, and approximately 3,330 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, 2023, EGMA owned 14 active gate stations, 191 district regulator stations, and approximately 5,033 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. 23 As of December 31, 2023, Yankee Gas owned 28 active gate stations, 200 district regulator stations, and approximately 3,540 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, 2023, NSTAR Gas owned 0.65 miles of intrastate transmission natural gas pipeline. NSTAR Gas reclassified 0.35 miles of transmission pipeline from 49 CFR 192 Pipeline regulated to 49 CFR 193 LNG regulated at the Hopkinton LNG facility. As of December 31, 2023, EGMA did not own any miles of intrastate transmission natural gas pipeline. EGMA replaced its last remaining 0.5 miles of transmission pipeline. The replacement pipeline was designed and engineered to be Distribution class. 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, 2023, Aquarion owned and operated sources of water supply with a combined yield of approximately 135 million gallons per day; 3,802 miles of transmission and distribution mains; 10 surface water treatment plants; 36 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. 24 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. 25 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, 2024. All of Eversource Energy’s officers serve terms of one year and until their successors are elected and qualified. Name Age Title Joseph R. Nolan, Jr. 60 Chairman of the Board, President, Chief Executive Officer and a Trustee John M. Moreira 62 Executive Vice President, Chief Financial Officer and Treasurer Gregory B. Butler 66 Executive Vice President and General Counsel Paul Chodak III 60 Executive Vice President and Chief Operating Officer Penelope M. Conner 60 Executive Vice President-Customer Experience and Energy Strategy James W. Hunt, III 52 Executive Vice President-Corporate Relations and Sustainability and Secretary Susan Sgroi 59 Executive Vice President-Human Resources and Information Technology Jay S. Buth 54 Vice President, Controller and Chief Accounting Officer 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. 26 PART II 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, 2024, there were 29,025 registered common shareholders of our company on record. As of the same date, there were a total of 349,687,183 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 2018 in Eversource Energy common stock, as compared with the S&P 500 Stock Index and the EEI Index for the period 2018 through 2023, assuming all dividends are reinvested. December 31, 2018 2019 2020 2021 2022 2023 Eversource Energy $100 $134 $140 $152 $144 $111 EEI Index $100 $126 $124 $146 $147 $134 S&P 500 $100 $131 $156 $200 $164 $207 27 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, 2023 — $ — — — November 1 - November 30, 2023 — — — — December 1 - December 31, 2023 2,941 61.80 — — Total 2,941 $ 61.80 — — Item 6. Removed and Reserved 28 Item 7. Management's Discussion and Analysis of Financial Condition and Results of Operations EVERSOURCE ENERGY AND SUBSIDIARIES 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 2023 compared to fiscal year 2022 is included herein. Unless expressly stated otherwise, for discussion and analysis of fiscal year 2021 items and of fiscal year 2022 compared to fiscal year 2021, please refer to Item 7, Management's Discussion and Analysis of Financial Condition and Results of Operations, in our combined 2022 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 the impairment charges for the offshore wind investments, a loss on the disposition of land that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned, certain transaction and transition costs, and our earnings and EPS excluding charges at CL&P related to an October 2021 settlement agreement that included credits to customers and funding of various customer assistance initiatives and a 2021 storm performance penalty imposed on CL&P by PURA. 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 impairment charges for the offshore wind investments, the loss on the disposition of land associated with an abandoned project, transaction and transition costs, and the CL&P October 2021 settlement agreement, and the 2021 storm performance penalty imposed on CL&P by PURA 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 had a loss of $442.2 million, or $1.26 per share, in 2023, compared with earnings of $1.40 billion, or $4.05 per share, in 2022. Our 2023 results include after-tax impairment charges of $1.95 billion, or $5.58 per share, recorded at Eversource parent to reflect our current estimate of the fair value of the offshore wind projects. Our 2023 results also include after-tax land abandonment and other charges recorded at Eversource parent of $6.9 million, or $0.02 per share. Our 2022 results include after-tax transaction and transition costs of $15.0 million, or $0.04 per share. Excluding the offshore wind impairments and these other charges, our non-GAAP earnings were $1.52 billion, or $4.34 per share, in 2023, compared with $1.42 billion, or $4.09 per share, in 2022. • We project that we will earn within a 2024 non-GAAP earning guidance range of between $4.50 per share and $4.67 per share, which excludes the impact of the expected sales of our 50 percent interests in three jointly-owned offshore wind projects and related transaction costs. We also project that our long-term EPS growth rate through 2028 from our regulated utility businesses will be in a 5 to 7 percent range. 29 Liquidity: • Cash flows provided by operating activities totaled $1.65 billion in 2023, compared with $2.40 billion in 2022. Investments in property, plant and equipment totaled $4.34 billion in 2023 and $3.44 billion in 2022. • Cash and Cash Equivalents totaled $53.9 million as of December 31, 2023, compared with $374.6 million as of December 31, 2022. Our available borrowing capacity under our commercial paper programs totaled $512.3 million as of December 31, 2023. • In 2023, we issued $5.20 billion of new long-term debt and we repaid $2.01 billion of long-term debt. • In 2023, we paid dividends totaling $2.70 per common share, compared with dividends of $2.55 per common share in 2022. Our quarterly common share dividend payment was $0.675 per share in 2023, as compared to $0.6375 per share in 2022. On January 31, 2024, our Board of Trustees approved a common share dividend payment of $0.715 per share, payable on March 29, 2024 to shareholders of record as of March 5, 2024. • We project to make capital expenditures of $23.12 billion from 2024 through 2028, of which we expect $9.71 billion to be in our electric distribution segment, $5.44 billion to be in our natural gas distribution segment, $5.77 billion to be in our electric transmission segment, and $1.08 billion to be in our water distribution segment. We also project to invest $1.12 billion in information technology and facilities upgrades and enhancements. • On February 13, 2024, we initiated an exploratory assessment of monetizing our water distribution business and are exploring the potential sale of the business. Strategic Developments: • On February 13, 2024, Eversource announced that it has executed an agreement to sell its existing 50 percent interests in the South Fork Wind and Revolution Wind projects to Global Infrastructure Partners (GIP). As part of this transaction, Eversource expects to receive approximately $1.1 billion of cash proceeds upon closing, which includes the sales value related to the 10 percent energy community ITC adder of approximately $170 million related to Revolution Wind, and to exit these projects while retaining certain cost sharing obligations for the construction of Revolution Wind. The purchase price is subject to future post-closing adjustment payments based on, among other things, the progress, timing and expense of construction at each project. The cost sharing obligations provide that Eversource would share equally with GIP in GIP’s funding obligations for up to approximately $240 million of incremental capital expenditure overruns incurred during the construction phase for the Revolution Wind project, after which GIP’s obligations for any additional capital expenditure overruns would be shared equally by Eversource and Ørsted. Additionally, Eversource’s financial exposure will be adjusted by certain purchase price adjustments to be made following commercial operation of the Revolution Wind project and closing of South Fork as a result of final project economics, which includes Eversource’s obligation to maintain GIP’s internal rate of return for each project as specified in the agreement. Eversource currently expects that South Fork Wind will reach full commercial operation prior to closing of the sale with GIP and Eversource does not expect any material cost sharing or other purchase price adjustment payments for South Fork Wind. Closing of the transaction is currently expected to occur in mid-2024. • On January 24, 2024, Ørsted signed an agreement with Eversource to acquire Eversource’s 50 percent share of Sunrise Wind. The sale is subject to the successful selection of Sunrise Wind in the ongoing New York fourth solicitation for offshore wind capacity, signing of an OREC contract with NYSERDA, finalization of sale agreements, receipt of final federal construction permits, and relevant regulatory approvals. If Sunrise Wind is not successful in the solicitation, then the existing OREC contract for Sunrise Wind will be cancelled according to the state’s requirements, and Eversource and Ørsted’s joint venture for Sunrise Wind will remain in place. In that scenario, Ørsted and Eversource would then assess their options in determining the best path forward for Sunrise Wind and its assets, which include the BOEM offshore lease area. • On January 25, 2024, Eversource and Ørsted submitted a new proposal for Sunrise Wind in the New York fourth offshore wind solicitation. • Four of South Fork Wind’s twelve turbines were installed and placed into service by January 1, 2024, meeting the project commercial operation date requirements under the power purchase agreement with LIPA. All wind turbines are expected to be installed and placed into service by the end of March 2024. 30 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 (Loss)/Income Attributable to Common Shareholders and diluted EPS. For the Years Ended December 31, 2023 2022 2021 (Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share Net (Loss)/Income Attributable to Common Shareholders (GAAP) $ (442.2) $ (1.26) $ 1,404.9 $ 4.05 $ 1,220.5 $ 3.54 Regulated Companies (Non-GAAP) $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21 $ 1,342.4 $ 3.89 Eversource Parent and Other Companies (Non-GAAP) 8.4 0.03 (40.5) (0.12) (12.2) (0.03) Non-GAAP Earnings $ 1,517.7 $ 4.34 $ 1,419.9 $ 4.09 $ 1,330.2 $ 3.86 Impairments of Offshore Wind Investments (after-tax) (1) (1,953.0) (5.58) — — — — Land Abandonment Loss and Other Charges (after-tax) (2) (6.9) (0.02) — — — — Transaction and Transition Costs (after-tax) (3) — — (15.0) (0.04) (23.6) (0.07) CL&P Settlement Impacts (after-tax) (4) — — — — (86.1) (0.25) Net (Loss)/Income Attributable to Common Shareholders (GAAP) $ (442.2) $ (1.26) $ 1,404.9 $ 4.05 $ 1,220.5 $ 3.54 (1) We recorded impairment charges resulting from the expected sales of our offshore wind investments and to reflect our current estimate of the fair value of the offshore wind projects. 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 2023 charges primarily include a loss on the disposition of land. The land was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned. (3) Transaction costs in 2022 and 2021 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. (4) The 2021 after-tax costs are associated with the October 1, 2021 CL&P settlement agreement approved by PURA that included credits to customers and funding of various customer assistance initiatives and a 2021 storm performance penalty imposed on CL&P by PURA. 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: For the Years Ended December 31, 2023 2022 2021 (Millions of Dollars, Except Per Share Amounts) Amount Per Share Amount Per Share Amount Per Share Net Income - Regulated Companies (GAAP) $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21 $ 1,256.3 $ 3.64 Electric Distribution, excluding CL&P Settlement Impacts (Non-GAAP) $ 608.0 $ 1.74 $ 592.8 $ 1.71 $ 556.2 $ 1.61 Electric Transmission 643.4 1.84 596.6 1.72 544.6 1.58 Natural Gas Distribution 224.8 0.64 234.2 0.67 204.8 0.59 Water Distribution 33.1 0.09 36.8 0.11 36.8 0.11 Net Income - Regulated Companies (Non-GAAP) $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21 $ 1,342.4 $ 3.89 CL&P Settlement Impacts (after-tax) — — — — (86.1) (0.25) Net Income - Regulated Companies (GAAP) $ 1,509.3 $ 4.31 $ 1,460.4 $ 4.21 $ 1,256.3 $ 3.64 Our electric distribution segment earnings increased $15.2 million in 2023, as compared to 2022, due primarily to a base distribution rate increase effective January 1, 2023 at NSTAR Electric, higher earnings from CL&P's capital tracking mechanism due to increased electric system improvements, an increase in interest income primarily on regulatory deferrals, the impact of a new regulatory tracking mechanism at PSNH that allows for the recovery of previously incurred operating expenses associated with poles acquired on May 1, 2023, and higher AFUDC equity income. Those earnings increases were partially offset by higher operations and maintenance expense, higher interest expense, higher property and other tax expense, higher depreciation expense and lower pension income. Our electric transmission segment earnings increased $46.8 million in 2023, as compared to 2022, due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure and a lower effective tax rate. 31 Our natural gas distribution segment earnings decreased $9.4 million in 2023, as compared to 2022, due primarily to higher depreciation expense, higher interest expense, a higher effective tax rate, an unfavorable regulatory adjustment resulting from NSTAR Gas’ GSEP reconciliation filing, higher operations and maintenance expense arising primarily from higher uncollectible expense, and higher property tax expense. Those earnings decreases were partially offset by higher earnings from capital tracking mechanisms due to continued investments in natural gas infrastructure, base distribution rate increases effective November 1, 2023 and November 1, 2022 at NSTAR Gas and effective November 1, 2022 at EGMA, and an increase in interest income primarily on regulatory deferrals. Our water distribution segment earnings decreased $3.7 million in 2023, as compared to 2022, due primarily to higher depreciation, operations and maintenance expense and higher interest expense. Eversource Parent and Other Companies: Eversource parent and other companies’ losses increased $1.90 billion in 2023, as compared to 2022, due primarily to the 2023 impairments of Eversource parent’s offshore wind investments, which resulted in a total after-tax charge of $1.95 billion, or $5.58 per share. Earnings were also unfavorably impacted by higher interest expense and a loss on the disposition of land in 2023 that was initially acquired to construct the Northern Pass Transmission project and was subsequently abandoned. Earnings benefited by a lower effective tax rate as a result of the ability to utilize tax credits and benefits in 2023, as well as a decrease in after-tax transaction and transition costs. Additionally, 2023 earnings were favorably impacted from the liquidation of Eversource parent’s equity method investment in a renewable energy fund, partially offset by a charitable contribution made with a portion of the proceeds from the liquidation in 2023. 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 other corporate obligations, such as pension contributions. 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. In addition, Eversource uses its capital resources to fund investments in its offshore wind business, which are recognized as long-term assets. These factors have resulted in current liabilities exceeding current assets by $2.09 billion, $308.5 million and $143.6 million at Eversource, NSTAR Electric and PSNH, respectively, as of December 31, 2023. 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, 2023, $1.95 billion of Eversource's long-term debt, including $1.35 billion at Eversource parent and $139.8 million at CL&P, matures within the next 12 months. Eversource, with its solid 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. Cash and Cash Equivalents totaled $53.9 million as of December 31, 2023, compared with $374.6 million as of December 31, 2022. 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 13, 2028. This re volving 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 13, 2028, and serves to backstop NSTAR Electric's $650 million commercial paper program. 32 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, (Millions of Dollars) 2023 2022 2023 2022 2023 2022 Eversource Parent Commercial Paper Program $ 1,771.9 $ 1,442.2 $ 228.1 $ 557.8 5.60 % 4.63 % NSTAR Electric Commercial Paper Program 365.8 — 284.2 650.0 5.40 % — % There were no borrowings outstanding on the revolving credit facilities as of December 31, 2023 or 2022. CL&P and PSNH have uncommitted line of credit agreements totaling $375 million and $250 million, respectively, which will expire in 2024. There are no borrowings outstanding on either the CL&P or PSNH uncommitted line of credit agreements as of December 31, 2023. 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 as 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, 2023, there were intercompany loans from Eversource parent to CL&P of $457.0 million and to PSNH of $233.0 million. As of December 31, 2022, there were intercompany loans from Eversource parent to PSNH of $173.3 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 June 14, 2022, the DPU approved NSTAR Gas’ request for authorization to issue up to $325 million in long-term debt through December 31, 2024. On November 30, 2022, the PURA approved CL&P's request for authorization to issue up to $1.15 billion in long-term debt through December 31, 2024. As a result of CL&P’s January 2024 long-term debt issuance, CL&P has now fully utilized this authorization. On June 7, 2023, PURA approved Yankee Gas’ request for authorization to issue up to $350 million in long-term debt through December 31, 2024. On November 21, 2023, NSTAR Electric petitioned the DPU requesting authorization to issue up to $2.4 billion in long-term debt through December 31, 2026. On February 8, 2024, the NHPUC approved PSNH’s request for authorization to issue up to $300 million in long-term debt through December 31, 2024. 33 Long-Term Debt Issuances and Repayments: The following table summarizes long-term debt issuances and repayments: (Millions of Dollars) Interest Rate Issuance/ (Repayment) Issue Date or Repayment Date Maturity Date Use of Proceeds for Issuance/ Repayment Information CL&P 2023 Series A First Mortgage Bonds 5.25 % $ 500.0 January 2023 January 2053 Repaid 2013 Series A Bonds at maturity and short-term debt, and paid capital expenditures and working capital CL&P 2013 Series A First Mortgage Bonds 2.50 % (400.0) January 2023 January 2023 Paid at maturity CL&P 2023 Series B First Mortgage Bonds 4.90 % 300.0 July 2023 July 2033 Repaid short-term debt, paid capital expenditures and working capital CL&P 2024 Series A First Mortgage Bonds 4.65 % 350.0 January 2024 January 2029 Repaid short-term debt, paid capital expenditures and working capital NSTAR Electric 2023 Debentures 5.60 % 150.0 September 2023 October 2028 Repaid Series G Senior Notes at maturity and short-term debt and for general corporate purposes NSTAR Electric 2013 Series G Senior Notes 3.88 % (80.0) November 2023 November 2023 Paid at maturity PSNH Series W First Mortgage Bonds 5.15 % 300.0 January 2023 January 2053 Repaid short-term debt, paid capital expenditures and working capital PSNH Series X First Mortgage Bonds 5.35 % 300.0 September 2023 October 2033 Repaid Series S Bonds at maturity and for general corporate purposes PSNH Series S First Mortgage Bonds 3.50 % (325.0) November 2023 November 2023 Paid at maturity Eversource Parent Series Z Senior Notes 5.45 % 750.0 March 2023 March 2028 Repaid Series F Senior Notes at maturity and short-term debt Eversource Parent Series F Senior Notes 2.80 % (450.0) May 2023 May 2023 Paid at maturity Eversource Parent Series Z Senior Notes 5.45 % 550.0 May 2023 March 2028 Repaid Series T Senior Notes and Series N Senior Notes at maturity and short-term debt Eversource Parent Series AA Senior Notes 4.75 % 450.0 May 2023 May 2026 Repaid Series T Senior Notes and Series N Senior Notes at maturity and short-term debt Eversource Parent Series BB Senior Notes 5.125 % 800.0 May 2023 May 2033 Repaid Series T Senior Notes and Series N Senior Notes at maturity and short-term debt Eversource Parent Variable Rate Series T Senior Notes SOFR plus 0.25% (350.0) August 2023 August 2023 Paid at maturity Eversource Parent Series CC Senior Notes 5.95 % 800.0 November 2023 February 2029 Repaid Series N Senior Notes at maturity and short-term debt Eversource Parent Series N Senior Notes 3.80 % (400.0) December 2023 December 2023 Paid at maturity Eversource Parent Series DD Senior Notes 5.00 % 350.0 January 2024 January 2027 Repaid short-term debt Eversource Parent Series EE Senior Notes 5.50 % 650.0 January 2024 January 2034 Repaid short-term debt Yankee Gas Series V First Mortgage Bonds 5.51 % 170.0 August 2023 August 2030 Repaid short-term debt and general corporate purposes EGMA Series D First Mortgage Bonds 5.73 % 58.0 November 2023 November 2028 Repaid short-term debt, paid capital expenditures and working capital Aquarion Water Company of Connecticut Senior Notes 5.89 % 50.0 September 2023 October 2043 Repaid existing indebtedness, paid capital expenditures and general corporate purposes 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 as Long-Term Debt on CL&P’s and Eversource parent’s balance sheets as of December 31, 2023. 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 2023 and 2022, and paid $16.2 million and $17.6 million of interest payments in 2023 and 2022, respectively. Common Share Issuances and 2022 Equity Distribution Agreement: On May 11, 2022, Eversource entered into an equity distribution agreement pursuant to which it may 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 2023, no shares were issued under this agreement. In 2022, Eversource issued 2,165,671 common shares, which resulted in proceeds of $197.1 million, net of issuance costs. Eversource used the net proceeds received for general corporate purposes. 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 $1.65 billion in 2023, compared with $2.40 billion in 2022. Operating cash flows were unfavorably impacted by an increase in regulatory under-recoveries driven primarily by the timing of collections for the CL&P non-bypassable FMCC and other regulatory tracking mechanisms, the timing of cash payments made on our accounts payable, a $26.7 million increase in cash payments to vendors for storm costs, an $11.9 million increase in cost of removal expenditures, and the timing of other working capital items. In 2023, CL&P increased the flow back to customers of net revenues generated by long-term state-approved energy contracts by providing these credits to customers through the non-bypassable FMCC retail rate. The reduction in the CL&P non-bypassable FMCC retail rate decreased the regulatory over-recovery balance and created an under-recovery balance as of December 31, 2023 , which resulted in a decrease to amortization expense of $802.3 million in 2023, as compared to 2022, and is presented as a cash outflow in Amortization on the statement of cash 34 flows. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization on the statements of cash flows. These unfavorable impacts were partially offset by the timing of cash collections on our accounts receivable, the absence in 2023 of $78.4 million of payments in 2022 related to withheld property taxes at our Massachusetts companies, a decrease of $76.3 million in pension contributions made in 2023 compared to 2022, the absence in 2023 of $72.0 million of customer credits distributed in 2022 at CL&P as a result of the October 2021 settlement agreement and the 2021 storm performance penalty for CL&P’s response to Tropical Storm Isaias, and a $38.7 million increase in operating cash flows due to lower income tax payments. 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. In 2022, we paid cash dividends of $860.0 million and issued non-cash dividends of $23.1 million in the form of treasury shares, totaling dividends of $883.1 million, or $2.55 per common share. Our quarterly common share dividend payment was $0.675 per share in 2023, as compared to $0.6375 per share in 2022. On January 31, 2024, our Board of Trustees approved a common share dividend payment of $0.715 per share, payable on March 29, 2024 to shareholders of record as of March 5, 2024. 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 2023, CL&P, NSTAR Electric and PSNH paid $330.4 million, $327.4 million and $112.0 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 2023, investments for Eversource, CL&P, NSTAR Electric, and PSNH were $4.34 billion, $1.09 billion, $1.38 billion and $605.1 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. Capital contributions in the offshore wind investments, including the 2023 contribution for the tax equity investment in South Fork Wind, are included in Investments in Unconsolidated Affiliates on the statements of cash flows. Proceeds received from the sale of the uncommitted lease area of $625 million in 2023 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, are included in Proceeds from Unconsolidated Affiliates on the statement of cash flows. Proceeds from the October 2023 distribution were used to pay down short-term debt. Proceeds from Unconsolidated Affiliates also includes proceeds received from the liquidation of an equity method investment in a renewable energy investment fund of $147.6 million in 2023. 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, 2023 and are as follows: (Millions of Dollars) 2024 2025 2026 2027 2028 Thereafter Total Eversource $ 933.3 $ 868.1 $ 827.5 $ 774.5 $ 671.6 $ 6,860.6 $ 10,935.6 Our commitments to make payments in addition to these contractual obligations include other liabilities reflected on our balance sheets, future funding of our offshore wind equity method investments until the expected sales are completed, and guarantees of certain obligations primarily associated with our offshore wind investments. The future funding and guarantee obligations associated with our offshore wind investments will be impacted by the expected sales of our offshore wind investments and related developments. For information regarding our projected capital expenditures over the next five years, see "Business Development and Capital Expenditures - Projected Capital Expenditures" and for further information on the expected sales of our 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 . 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 Current Outlook Current Outlook Current Outlook Eversource Parent A- Watch Neg Baa2 Negative BBB Stable CL&P A Watch Neg A3 Stable A- Stable NSTAR Electric A Watch Neg A2 Negative A- Stable PSNH A Watch Neg A3 Stable A- Stable 35 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 Current Outlook Current Outlook Current Outlook Eversource Parent BBB+ Watch Neg Baa2 Negative BBB Stable CL&P A+ Watch Neg A1 Stable A+ Stable NSTAR Electric A Watch Neg A2 Negative A Stable PSNH A+ Watch Neg A1 Stable A+ Stable 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 $4.59 billion in 2023, $3.79 billion in 2022, and $3.54 billion in 2021. These amounts included $214.4 million in 2023, $266.5 million in 2022, and $238.0 million in 2021 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 increased by $240.8 million in 2023, as compared to 2022. A summary of electric transmission capital expenditures by company is as follows: For the Years Ended December 31, (Millions of Dollars) 2023 2022 2021 CL&P $ 470.4 $ 416.8 $ 400.0 NSTAR Electric 567.4 438.4 480.3 PSNH 410.0 351.8 235.0 Total Electric Transmission $ 1,447.8 $ 1,207.0 $ 1,115.3 Our transmission projects are designed to improve the reliability of the electric grid, meet customer demand for power and increases in electrification of municipal infrastructure, strengthen the electric grid's resilience against extreme weather and other safety and security threats, and enable integration of increasing amounts of clean power generation from renewable sources, such as solar, battery storage, and offshore wind. 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. Distribution Business: A summary of distribution capital expenditures is as follows: For the Years Ended December 31, (Millions of Dollars) CL&P NSTAR Electric PSNH Total Electric Natural Gas Water Total 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 2021 Basic Business $ 256.2 $ 179.9 $ 56.0 $ 492.1 $ 206.1 $ 16.5 $ 714.7 Aging Infrastructure 178.0 219.1 67.7 464.8 509.6 127.1 1,101.5 Load Growth and Other 80.2 169.9 37.1 287.2 83.3 0.6 371.1 Total Distribution $ 514.4 $ 568.9 $ 160.8 $ 1,244.1 $ 799.0 $ 144.2 $ 2,187.3 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. 36 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. Projected Capital Expenditures: A summary of the projected capital expenditures for the regulated companies' electric transmission and for the total electric distribution, natural gas distribution and water distribution for 2024 through 2028, including information technology and facilities upgrades and enhancements on behalf of the regulated companies, is as follows: Years (Millions of Dollars) 2024 2025 2026 2027 2028 2024 - 2028 Total CL&P Transmission $ 393 $ 332 $ 255 $ 279 $ 194 $ 1,453 NSTAR Electric Transmission 450 526 640 838 903 3,357 PSNH Transmission 357 349 158 49 49 962 Total Electric Transmission 1,200 1,207 1,053 1,166 1,146 5,772 Electric Distribution 2,009 1,869 2,051 2,006 1,770 9,705 Natural Gas Distribution 1,044 1,087 1,142 1,089 1,079 5,441 Total Electric and Natural Gas Distribution 3,053 2,956 3,193 3,095 2,849 15,146 Water Distribution 169 204 218 234 251 1,076 Information Technology and All Other 225 234 223 202 239 1,123 Total $ 4,647 $ 4,601 $ 4,687 $ 4,697 $ 4,485 $ 23,117 The projections do not include investments related to offshore wind projects. Actual capital expenditures could vary from the projected amounts for the companies and years above. Offshore Wind Business: Eversource’s offshore wind business includes 50 percent ownership interests in wind partnerships, which collectively hold the Revolution Wind, South Fork Wind and Sunrise Wind projects, and a tax equity investment in South Fork Wind. The offshore wind projects are being developed and constructed through joint and equal partnerships with Ørsted. As of December 31, 2023 and 2022, Eversource's total equity investment balance in its offshore wind business was $515.5 million and $1.95 billion, respectively. Expected Sales of Offshore Wind Investments : 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 Ørsted for $625 million in an all-cash transaction. In September of 2023, Eversource made a contribution of $528 million using the proceeds from the lease area sale to invest 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. As a result of this investment, Eversource expects to receive investment tax credits after the turbines are placed in service for South Fork Wind and meet the requirements to qualify for the ITC. These credits will be utilized to reduce Eversource’s federal tax liability or generate tax refunds over the next 24 months. All of South Fork Wind’s twelve turbines are expected to be installed and placed into service by the end of March 2024. On January 24, 2024, Ørsted signed an agreement with Eversource to acquire Eversource’s 50 percent share of Sunrise Wind. The sale is subject to the successful selection of Sunrise Wind in the ongoing New York fourth solicitation for offshore wind capacity, signing of an OREC contract with NYSERDA, finalization of sale agreements, receipt of final federal construction permits, and relevant regulatory approvals. If Sunrise Wind is not successful in the solicitation, then the existing OREC contract for Sunrise Wind will be cancelled according to the state’s requirements, and Eversource and Ørsted’s joint venture for Sunrise Wind will remain in place. In that scenario, Ørsted and Eversource would then assess their options in determining the best path forward for Sunrise Wind and its assets, which include the BOEM offshore lease area. If Sunrise Wind’s revised bid is successful in the new solicitation, Sunrise Wind would have 90 days to negotiate a new OREC agreement at the re-bid price. In a successful re-bid, Ørsted would become the sole owner of Sunrise Wind, while Eversource would remain contracted to lead the project’s onshore construction. If Sunrise Wind is successful in the re-bid, Ørsted would pay Eversource 50 percent of the negotiated purchase price upon closing the sale transaction, with the remaining 50 percent paid when onshore construction is completed and certain other milestones are achieved. On January 25, 2024, Eversource and Ørsted submitted a new proposal for Sunrise Wind in the New York fourth offshore wind solicitation. 37 On February 13, 2024, Eversource announced that it has executed an agreement to sell its existing 50 percent interests in the South Fork Wind and Revolution Wind projects to Global Infrastructure Partners (GIP). As part of this transaction, Eversource expects to receive approximately $1.1 billion of cash proceeds upon closing, which includes the sales value related to the 10 percent energy community ITC adder of approximately $170 million related to Revolution Wind, and to exit these projects while retaining certain cost sharing obligations for the construction of Revolution Wind. The purchase price is subject to future post-closing adjustment payments based on, among other things, the progress, timing and expense of construction at each project. The cost sharing obligations provide that Eversource would share equally with GIP in GIP’s funding obligations for up to approximately $240 million of incremental capital expenditure overruns incurred during the construction phase for the Revolution Wind project, after which GIP’s obligations for any additional capital expenditure overruns would be shared equally by Eversource and Ørsted. Additionally, Eversource’s financial exposure will be adjusted by certain purchase price adjustments to be made following commercial operation of the Revolution Wind project and closing of South Fork as a result of final project economics, which includes Eversource’s obligation to maintain GIP’s internal rate of return for each project as specified in the agreement. Eversource currently expects that South Fork Wind will reach full commercial operation prior to closing of the sale with GIP and Eversource does not expect any material cost sharing or other purchase price adjustment payments for South Fork Wind. Factors that could result in Eversource’s total net proceeds from the transaction to be lower or higher include Revolution Wind’s eligibility for federal investment tax credits at other than the anticipated 40 percent level; the ultimate cost of construction and extent of cost overruns for Revolution Wind; delays in constructing Revolution Wind, which would impact the economics associated with the purchase price adjustment; and 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 date of the Revolution Wind project. Closing a transaction with GIP would be subject to customary conditions, including certain regulatory approvals under the Hart Scott Rodino Act and by the New York Public Service Commission and the FERC, as well as other conditions, among which is the completion and execution of the partnership agreements between GIP and Ørsted that will govern GIP’s new ownership interest in those projects following Eversource’s divestiture. Closing of the transaction is currently expected to occur in mid-2024. If closing of the sale is delayed, additional capital contributions made by Eversource would be recovered in the sales price. Under the agreement, Eversource’s existing credit support obligations are expected to roll off for each project around the time that each project completes its expected capital spend. Impairment: 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. 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. 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 reflects a total pre-tax other-than-temporary impairment charge of $2.17 billion ($1.95 billion after-tax) in its offshore wind investments for the year ended 2023. The 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. Additional assumptions in the fourth quarter assessment included revised projected construction costs and estimated project cost overruns, 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 are subject to inherent uncertainties and subjectivity. The use of different assumptions, estimates, or judgments with respect to the estimation of future cash flows could materially change the impairment charges. The impairment evaluations were based on best information available at the impairment assessment dates. New information from events or circumstances arising after the balance sheet date, such as the January 25, 2024 re-bid of Sunrise Wind in the New York solicitation, are not included in the December 31, 2023 impairment evaluation. All significant inputs into the impairment evaluations were Level 3 fair value measurements. 38 The expected cash flows arising from the anticipated sales are a significant input in the impairment evaluation. In the fourth quarter of 2023, project construction forecasts were updated, and these new forecasts reflected additional expenditures for construction and scheduling related pressures, including the availability and increased cost of installation vessels and supply chain cost increases related to foundation fabrication. In determining the current fair value of the investments, these updated projections exceeded the previously estimated projections for construction expenditures, which resulted in a revised sales price that was significantly lower than the previous bid value. Another significant assumption in the impairment evaluation includes the probability of payment of future cost overruns on the three wind projects through each project's respective commercial operation date, which would not be recovered in the expected sales price. This assumption was based on construction projections updated in the fourth quarter of 2023 exceeding prior estimates. An increase in expected cost overruns could result in a significant impairment in a future period. Another key assumption in the impairment model of our offshore wind investments was investment tax credit (“ITC”) adders that were included in the Inflation Reduction Act and were a separate part of the sales price value offered by GIP. An ITC adder is an additional 10 percent of credit value for ITC eligible costs and include two distinct qualifications related to either using domestic sourced materials (domestic content) or construction of an onshore substation in a designated community (energy community). Similar to the base ITC of 30 percent of the eligible costs, any ITC adders generated would be used to reduce an owner’s federal tax liability and could be used to receive tax refunds from prior years as well. Management believes there is a high likelihood that the 10 percent energy community ITC adder is realizable, and that ITC adder would amount to approximately $170 million of additional sales value related to Revolution Wind and that it would qualify for the ITC adder after it reaches commercial operation in 2025. Although management believes the ITC adder value is realizable, there is some uncertainty at this time as to whether or not 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 impairment in a future period. Another fourth quarter 2023 development included in the impairment evaluation is the key judgment regarding the probability of future cash inflows and outflows associated with the sale or abandonment of the Sunrise Wind project and the expected outcome of the New York fourth offshore wind solicitation in 2024. In June 2023, Sunrise Wind filed a petition with the New York State Public Service Commission for an order authorizing NYSERDA to amend the Sunrise Wind OREC contract to increase the contract price to cover increased costs and inflation. At that time, management expected the contract repricing would be successful given NYSERDA’s public support for pricing adjustments. On October 12, 2023, the New York State Public Service Commission denied this petition. Subsequent to the denial, on November 30, 2023, the general terms of an expedited offshore wind renewable energy solicitation in New York were released. A primary condition for Sunrise Wind to participate in this new solicitation was to agree to terminate its existing OREC agreement. As of December 31, 2023, Eversource and Ørsted were considering whether to submit a new bid for Sunrise Wind, the price at which a new bid would be made, and the probability of success in the new bidding process. The December 31, 2023 impairment evaluation included management’s judgment of the likelihood of possible future scenarios that included the Sunrise Wind project continuing with its existing OREC contract, the project re-bidding and being selected in the new solicitation, the project re-bidding and not being selected, or the project not moving forward. The unfavorable development of the October 2023 denial of the OREC pricing petition, management’s assessment of the likelihood of success in the competitive New York re-bidding process, and the increased costs to build the project, have resulted in management’s assumption that the Sunrise Wind project will ultimately be abandoned, and therefore, no sales value was modeled in the impairment evaluation. Additionally, in the abandonment assumption, management has assumed the loss of contingent sales value associated with any related ITC adders and has estimated future cash outflows for Eversource’s share of cancellation costs required under Sunrise Wind’s supplier contracts, partially offset by expected salvage value and expected cost overruns not incurred in the case of abandonment that are included in the fourth quarter 2023 impairment charge. An increase in expected cancellation costs could result in a significant impairment in a future period. A summary of the significant estimates and assumptions included in the 2023 impairment charges is as follows: Second Quarter 2023 Fourth Quarter 2023 Total (Millions of Dollars) Lower expected sales proceeds across all three wind projects $ 401 $ 525 $ 926 Expected cost overruns not recovered in the sales price — 441 441 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 — 800 800 Impairment Charges, pre-tax 401 1,766 2,167 Tax Benefit (70) (144) (214) Impairment Charges, after-tax $ 331 $ 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 (Millions of Dollars) Sunrise Wind Revolution Wind Carrying Value as of December 31, 2023, before Impairment Charge $ 699 $ 799 $ 299 $ 485 $ 2,282 Fourth Quarter 2023 Impairment Charge (1,218) (544) — (4) (1,766) Carrying Value as of December 31, 2023 $ (519) $ 255 $ 299 $ 481 $ 516 39 Management will continue to monitor and evaluate all facts and circumstances in the offshore wind sales process and the impact on its investment balance. Adverse changes in facts and circumstances of estimates and timing of future cash flows and the factors described above could result in the recognition of additional, significant impairment charges that could be material to the financial statements. The impairment charge was a non-cash charge and did not impact Eversource’s cash position. Eversource will continue to make future cash expenditures for required cash contributions to its offshore wind investments up to the time of disposition of each of the offshore wind projects. Capital contributions are expected until the sales are completed and changes in the timing and amounts of these contributions would be adjusted in the sales prices and therefore not result in an additional impairment charge. Proceeds from the transactions will be used to pay off parent company debt. Eversource’s offshore wind investments do not meet the criteria to qualify for presentation as a discontinued operation. Contracts, Permitting and Construction of Offshore Wind Projects: The following table provides a summary of the Eversource and Ørsted major projects with announced contracts: Wind Project State Servicing Size (MW) Term (Years) Price per MWh Pricing Terms Contract Status Revolution Wind Rhode Island 400 20 $98.43 Fixed price contract; no price escalation Approved Revolution Wind Connecticut 304 20 $98.43 - $99.50 Fixed price contracts; no price escalation Approved South Fork Wind New York (LIPA) 90 20 $160.33 2 percent average price escalation Approved South Fork Wind New York (LIPA) 40 20 $86.25 2 percent average price escalation Approved The offshore wind projects require receipt of federal, state and local approvals necessary to construct and operate the projects. The federal permitting process is led by BOEM, and state approvals are required from New York, Rhode Island and Massachusetts. South Fork Wind and Revolution Wind have received all required approvals to start construction. Significant delays in the siting and permitting process resulting from the timeline for obtaining approval from BOEM and the state and local agencies could adversely impact the timing of Sunrise Wind’s' in-service date. Federal Siting and Permitting Process: The federal siting and permitting process for each of our offshore wind projects commence with the filing of a Construction and Operations Plan (COP) application with BOEM. BOEM provides a review schedule for the project’s COP approval and conducts environmental and technical reviews of the COP. BOEM issues an Environmental Impact Statement (EIS) that assesses the environmental, social, and economic impacts of constructing the project and recommends measures to minimize impacts. The Final EIS will inform BOEM in deciding whether to approve the project or to approve with modifications and BOEM will then issue its Record of Decision. BOEM issues its final approval of the COP following the Record of Decision. Revolution Wind and Sunrise Wind filed their COP applications with BOEM in March 2020 and September 2020, respectively. For the Revolution Wind project, BOEM released its Draft EIS on September 2, 2022 and its Final EIS on July 17, 2023. On August 21, 2023, BOEM issued its Record of Decision, which concluded BOEM’s environmental review of the project and identified the recommended configuration. Final approval of the Revolution Wind project was received on November 20, 2023. For the Sunrise Wind project, BOEM released its Draft EIS on December 16, 2022 and its Final EIS on December 15, 2023. The Record of Decision is expected in the first quarter of 2024 and final approval of Sunrise Wind is expected in the second quarter of 2024. South Fork Wind, Revolution Wind and Sunrise Wind are each designated as a “Covered Project” pursuant to Title 41 of the Fixing America’s Surface Transportation Act (FAST41) and a Major Infrastructure Project under Section 3(e) of Executive Order 13807, which provides greater federal attention on meeting the projects’ permitting timelines. State and Local Siting and Permitting Process: State permitting applications in Rhode Island for Revolution Wind and in New York for Sunrise Wind were filed in December 2020. On July 8, 2022, the Rhode Island Energy Facilities Siting Board issued a Final Decision and Order approving the Revolution Wind project and granting a license to construct and operate. On November 17, 2022, the New York Public Service Commission approved an order adopting a Joint Proposal filed by Sunrise Wind and granting a Certificate of Environmental Compatibility and Public Need. On November 18, 2022, Sunrise Wind filed its Phase 1 Environmental Management and Construction Plan (EM&CP) with the New York Public Service Commission, which details the plans on limited onshore construction activities subject to state and local jurisdiction. On March 27, 2023, Sunrise Wind filed its EM&CP for Phase 2, which covers the remainder of the project components. On June 22, 2023, Sunrise Wind received approval of the Phase 1 EM&CP. On July 13, 2023, the New York State Public Service Commission approved Sunrise Wind’s notice for authorization to proceed with construction for Phase 1. On December 18, 2023, Sunrise Wind received approval of the Phase 2 EM&CP. On November 9, 2022, the Towns of Brookhaven and Suffolk County executed the easements and other real estate rights necessary to construct the Sunrise Wind project. On November 28, 2022, the Town of North Kingstown and the Quonset Development Corporation approved Revolution Wind’s real estate PILOT terms and the personal property PILOT agreement necessary to construct the Revolution Wind project. Construction Process: South Fork Wind received all required approvals to start construction and the project entered the construction phase in early 2022. All major onshore construction activities, including the project’s underground onshore transmission line and the onshore interconnection facility located in East Hampton, New York are complete. Offshore construction activities began in the fourth quarter of 2022, and installation of the subsea transmission cable, the monopile foundations and offshore substation was completed in 2023. Installation of the project’s 11-megawatt wind turbines continued throughout 2023 and four of South Fork Wind’s twelve turbines were placed into service by January 1, 2024, meeting the project commercial operation date requirements under the power purchase agreement with LIPA. All wind turbines are expected to be installed 40 and placed into service by the end of March 2024. South Fork Wind faces several challenges and appeals of New York State and federal agency approvals, however we believe it is probable we will be able to overcome these challenges. For Revolution Wind, on October 31, 2023, the joint venture made its final investment decision to advance to full onshore and offshore construction and installation, and major construction began in the fourth quarter of 2023 upon receipt of all necessary federal, state and local approvals. For Sunrise Wind, once all necessary federal, state and local approvals are received and the joint venture has made its final investment decision, informed in part by the outcome of the New York fourth solicitation, then major construction is expected to begin. Sunrise Wind has started limited onshore construction activities. Projected In-Service Dates: We expect the South Fork Wind project to be in-service by the end of March 2024 and the Revolution Wind project to be in-service in late 2025. For Sunrise Wind, based on the updated BOEM permit schedule outlining when BOEM will complete its review of the COP, we currently expect an in-service date in 2026. 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, 2023 and 2022. 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, 2023 and 2022. 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 its 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. At this time, Eversource cannot predict how and when FERC will address the Court’s findings on the remand of the MISO FERC opinions or any potential associated impact on the NETOs’ four pending ROE complaint cases. Given the significant uncertainty regarding the applicability of the FERC opinions in the MISO transmission owners’ two complaint cases to the NETOs’ pending four complaint cases, Eversource concluded that there is no reasonable basis for a change to the reserve or recognized ROEs for any of the complaint periods at this time. As well, Eversource cannot reasonably estimate a range of loss for any of the four complaint proceedings at this time. 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. 41 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 2023 rate base, a change of 10 basis points to the base ROE would impact Eversource’s future annual after-tax earnings by approximately $5.5 million per year, and will increase slightly over time as we continue to invest in our transmission infrastructure. FERC Notice of Proposed Rulemaking on Transmission Incentives: On March 20, 2020, FERC issued a Notice of Proposed Rulemaking (NOPR) on transmission incentives. The NOPR intends to revise FERC’s electric transmission incentive policies to reflect competing uses of transmission due to generation resource mix, technological innovation and shifts in load patterns. FERC proposes to grant transmission incentives based on measurable project economics and reliability benefits to consumers rather than its current project risks and challenges framework. On July 1, 2020, Eversource filed comments generally supporting the NOPR. On April 15, 2021, FERC issued a Supplemental NOPR that proposes to eliminate the existing 50 basis point return on equity for utilities that have been participating in a regional transmission organization (RTO ROE incentive) for more than three years. On June 25, 2021, the NETOs jointly filed comments strongly opposing FERC’s proposal. On July 26, 2021, the NETOs filed Supplemental NOPR reply comments responding to various parties advocating for the elimination of the RTO Adder. If FERC issues a final order eliminating the RTO ROE incentive as proposed in the Supplemental NOPR, the estimated annual impact (using 2023 estimated rate base) on Eversource's after-tax earnings is approximately $19.5 million. The Supplemental NOPR contemplates an effective date 30 days from the final order. At this time, Eversource cannot predict the ultimate outcome of these proceedings, including possible appellate review, and the resulting impact on its transmission incentives. 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, electric, natural gas and water utilities serving more than seventy-five thousand customers are required to file a distribution rate case within four years of the last rate case. 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. CL&P's and Yankee Gas' base distribution rates were each established in 2018 PURA-approved rate case settlement agreements. On October 27, 2021, PURA approved a settlement agreement for CL&P that included a current base distribution rate freeze until no earlier than January 1, 2024. 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. On March 15, 2023, PURA issued a final decision that rejected Aquarion Water Company of Connecticut’s (AWC-CT) application with PURA to amend its existing rate schedules. AWC-CT filed an appeal on the decision and on May 25, 2023, the State of Connecticut Superior Court granted a permanent stay of certain orders affecting base rates, which will keep existing rates in place until the appeal is completed. For further information, see "Regulatory Developments and Rate Matters - Connecticut," below . 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. NSTAR Electric's base distribution rates were established in a November 2022 DPU-approved rate case. NSTAR Gas' base distribution rates were established in an October 2020 DPU-approved rate case. EGMA's base distribution rates were established in an October 2020 DPU-approved rate settlement agreement. Aquarion is not required to initiate a rate review with the DPU. Aquarion’s base distribution rates were established in a 2018 DPU-approved rate case. In New Hampshire, PSNH's base distribution rates were established in a December 2020 NHPUC-approved rate case settlement agreement. Aquarion's 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. 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. 42 The electric and natural gas distribution companies also recover certain other costs 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, 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, which would apply at the time of CL&P’s next distribution rate case. The straw proposal is not authoritative and technical sessions are continuing prior to a final decision. PURA is expected to issue a straw proposal in the second reopener focusing on performance incentive mechanisms (PIMs) in the first quarter of 2024. The three reopener dockets continue to progress through the Phase 2 process. 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 Filing: On December 22, 2023, CL&P initiated a docket seeking a prudency review of approximately $634 million of catastrophic storm costs for twenty-four weather events from January 1, 2018 to December 31, 2021. In the filing, CL&P requested PURA establish a rate to collect $50 million annually from customers from the date of the final decision in this proceeding. This rate would be effective until the next distribution rate case and would replenish the under-collected storm reserve and reduce future carrying charges for customers. CL&P Advanced Metering Infrastructure Filing: On July 31, 2020, CL&P submitted to PURA its proposed $512 million Advanced Metering Infrastructure investment and implementation plan. On August 17, 2021, PURA issued a Notice of Request for an Amended EDC Advanced Metering Infrastructure Proposal. On November 8, 2021, CL&P submitted an Amended Proposal in response to this request with an updated schedule for the years 2022 through 2028, which included additional information as required by PURA. As required, the plan includes a full deployment of advanced metering functionality and a composite business case in support of the Advanced Metering Infrastructure plan. On January 3, 2024, PURA issued a final decision regarding CL&P’s Advanced Metering Infrastructure investment and implementation plan, which CL&P most recently estimated at $766.4 million for capital costs and one-time operating expenses. In CL&P’s view, the final decision does not provide a reasonable path for cost recovery and delays implementation by a year. In addition, 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. Termination of Park City Wind’s Power Purchase Agreement with CL&P : On October 2, 2023, Park City Wind LLC and CL&P signed an agreement to terminate the Park City Wind offshore wind generation PPA, at the request of Park City Wind LLC. The termination agreement was effective on October 13, 2023, the date of PURA approval. In October 2023, Park City Wind LLC paid a termination payment of $12.9 million to CL&P resulting from the termination of the PPA, which CL&P will return to customers. 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 base distribution rate decrease of $2.0 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 will 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. A hearing on the merits of the appeal was held on January 11, 2024. A decision from the State of Connecticut Superior Court is pending. Massachusetts: NSTAR Electric Distribution Rates : On November 30, 2022, the DPU issued its decision in the NSTAR Electric distribution rate case and approved a base distribution rate increase of $64 million effective January 1, 2023. 43 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. 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 K-bar 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 Electric’s Electric Sector Modernization Plan (ESMP) Filing : Massachusetts state law requires the electric distribution companies to file a comprehensive distribution system plan by January 29, 2024, 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. On January 29, 2024, NSTAR Electric filed its ESMP with the DPU. 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 taking into account the needs of environmental justice communities. For the five-year period from 2025 through 2029, the proposed incremental capital investment is $608 million and the incremental expense amount is $211 million. The DPU must approve, approve with modification, or reject the ESMP filing within seven months after filing. Termination of SouthCoast Wind’s Power Purchase Agreements with NSTAR Electric : On August 28, 2023, SouthCoast Wind Energy LLC and NSTAR Electric signed agreements to terminate three SouthCoast Wind offshore wind generation PPAs, at the request of SouthCoast Wind Energy LLC. The termination agreements were effective on September 29, 2023, the date of DPU approval. In October 2023, SouthCoast Wind Energy, LLC paid a termination payment totaling $32.5 million to NSTAR Electric resulting from the termination of the PPAs, which NSTAR Electric will return to customers. Termination of Commonwealth Wind’s Power Purchase Agreement with NSTAR Electric : On July 13, 2023, Commonwealth Wind, LLC and NSTAR Electric signed an agreement to terminate the Commonwealth Wind offshore wind generation PPA, at the request of Commonwealth Wind, LLC. The termination agreement was effective on August 23, 2023, the date of DPU approval. In October 2023, Commonwealth Wind, LLC paid a termination payment of $25.9 million to NSTAR Electric, which NSTAR Electric will return to customers. NSTAR Gas Distribution Rates: NSTAR Gas’ PBR mechanism allows for an annual adjustment to base distribution rates for inflation and exogenous events. 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. New Hampshire: 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 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. PSNH Energy Efficiency Plan : On February 24, 2022, a state law was enacted that directed that the joint utility energy efficiency plan and programming framework in effect on January 1, 2021 be utilized going forward, including utility performance incentive payments, lost base revenue calculations, and Evaluation, Measurement, and Verification process. Additionally, the law established a process for future plan proposals, including the 2024 through 2026 triennial plan, and includes a mechanism for future rate increases based on the consumer price index. On November 30, 2023, the NHPUC approved a three-year joint utility energy efficiency plan for 2024 through 2026, of which, $158 million is the PSNH program budget over the next three years. Additionally, on December 22, 2023, the NHPUC approved the annual LBR rate for 2024, allowing PSNH to recover approximately $14 million in revenue that would have been collected if not for the implementation of energy efficiency measures. Legislative and Policy Matters Connecticut: On June 29, 2023, Connecticut enacted Public Act No. 23-102 (Substitute Senate Bill No. 7) (the Act) that encompasses 40 sections. The Act prohibits recovery in retail rates of certain costs incurred by utilities, including costs for consultants and outside counsel for rate cases, membership dues, and lobbying. None of the rate-setting provisions will result in an immediate change to rates, as all will require some future process, primarily a general distribution rate proceeding before PURA. 44 The Act also makes prospective adjustments to the timing and procedures used in the retail rate setting process, including (1) requiring additional procedural steps to be satisfied for proposed settlements of cases; (2) increasing the deadline to issue a final decision on an application from a water company to amend base rates from 200 days to 270 days; (3) authorizing PURA to elect to evaluate if rates should be reduced on an interim basis if a utility earns an ROE that exceeds its authorized ROE by 50 basis points over a rolling 12-month period ending with the two most recent consecutive financial quarters (instead of the current standard of 100 basis points); and (4) authorizing PURA to 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. The Act is prospective, not retroactive and therefore, does not change obligations or rate provisions established by settlements implemented prior to the Act. The Act also prohibits CL&P’s electric system improvements (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. The Act also excludes storms and other emergencies affecting 70 percent or more of an electric distribution company’s customers from the 2020 law requiring credits for residential customers who are without power for 96 or more consecutive hours. Lastly, the Act was amended by Public Act No. 23-204 (House Bill No. 6941) to require the Governor to designate the chairperson of PURA from among the sitting commissioners by June 30, 2023 and every two years thereafter; and to delete the changes in Section 21 of the Act to the duties and powers of PURA commissioners. Designation of the chairperson does not constitute a renomination for a full commission term, as otherwise provided by law. 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 $1.75 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, 2023. Tropical Storm Isaias resulted in deferred storm restoration costs of approximately $232 million at CL&P as of December 31, 2023. 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. 45 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 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, 2023, 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 2024 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, 2023, the discount rates used to determine the funded status 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. As of December 31, 2022, the discount rates used were within a range of 5.1 percent to 5.2 percent for the Pension and SERP Plans, and 5.2 percent for the PBOP Plans. The decrease in the discount rates used to calculate the funded status resulted in an increase to the Pension and SERP Plans’ projected benefit obligation of $98.9 million and an increase to the PBOP Plans' projected benefit obligation of $12.0 million as of December 31, 2023. 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 2023 expense were within a range of 4.9 percent to 5.3 percent for the Pension and SERP Plans, and within a range of 5.1 percent to 5.4 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 2023, 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, 2023 and 2022, the compensation/progression rates used to determine the 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, 2023, for the Aquarion PBOP Plan, the health care trend rate used to determine the funded status for pre-65 retirees is 6.75 percent, with an ultimate rate of 5 percent in 2031, and for post-65 retirees, the health care trend rate and ultimate rate is 3.5 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 seven 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 2023. 46 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 $108.4 million and $181.6 million for the years ended December 31, 2023 and 2022, respectively, and there was pre-tax net periodic benefit expense of $23.6 million for the year ended December 31, 2021. For the PBOP Plans, pre-tax net periodic benefit income was $57.3 million, $79.8 million and $60.5 million for the years ended December 31, 2023, 2022 and 2021, 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 2024 for the Pension and SERP Plans will be approximately $90 million and for the PBOP Plans will be approximately $65 million. The decrease in pension income from 2023 to 2024 is driven primarily by higher amortization of actuarial loss due to unrecognized actuarial loss arising in 2023, partially offset by the absence in 2024 of a 2023 SERP settlement charge and a decrease in the interest cost component due to a lower discount rate. The increase in PBOP income from 2023 to 2024 is driven primarily by favorable expected return on assets due to a higher asset balance and a decrease in the interest cost component due to a lower discount rate. For the PBOP Plans, there is no amortization of actuarial loss in 2024. 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, there is no minimum funding requirement for our Eversource Service Pension Plan in 2024 and we do not expect to make pension contributions in 2024. 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 2024. 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 in Plan Income (Millions of Dollars) For the Years Ended December 31, For the Years Ended December 31, Eversource 2023 2022 2023 2022 Lower expected long-term rate of return $ 29.1 $ 32.5 $ 0.2 $ 5.6 Lower discount rate 24.7 32.6 4.7 1.7 Higher compensation rate 8.1 7.6 N/A N/A Goodwill: We recorded goodwill on our balance sheet associated with previous mergers and acquisitions, all of which totaled $4.53 billion as of December 31, 2023. We have identified our reporting units for purposes of allocating and testing goodwill as Electric Distribution, Electric Transmission, Natural Gas Distribution and Water Distribution. 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, 2023, goodwill was allocated to the reporting units as follows: $2.54 billion to Electric Distribution, $577 million to Electric Transmission, $451 million to Natural Gas Distribution and $961 million to Water Distribution. 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 deemed to be impaired, it would be written down in the current period to the extent of the impairment. 47 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. A quantitative impairment test is required only if it is concluded that it is more likely than not that a reporting unit’s fair value is less than its carrying amount. We performed an impairment assessment of goodwill as of October 1, 2023 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. The 2023 goodwill impairment assessment resulted in a conclusion that goodwill is not impaired. We believe that the fair value of the reporting units 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 impairments occurred during the year 2023. 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. 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. 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 estimate 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 are subject to inherent uncertainties and subjectivity. The use of different assumptions, estimates, or judgments with respect to the estimation of future cash flows could materially change the impairment charges. The impairment evaluations were based on best information available at the impairment assessment date. Management will continue to monitor and evaluate all facts and circumstances in the offshore wind sales process and the impact on its investment balance. Adverse changes in facts and circumstances of estimates and timing of future cash flows and the factors described above could result in the recognition of additional, significant impairment charges and could be material to the financial statements. See Note 6, “Investments in Unconsolidated Affiliates,” to the financial statements for further information on the impairments to Eversource’s offshore wind equity method investments carrying value. 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. 48 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. 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. 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. 49 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, 2023 and 2022 included in this Annual Report on Form 10-K: For the Years Ended December 31, (Millions of Dollars) 2023 2022 Increase/(Decrease) Operating Revenues $ 11,910.7 $ 12,289.3 $ (378.6) Operating Expenses: Purchased Power, Purchased Natural Gas and Transmission 5,168.2 5,014.1 154.1 Operations and Maintenance 1,895.7 1,865.3 30.4 Depreciation 1,305.8 1,194.2 111.6 Amortization (490.1) 448.9 (939.0) Energy Efficiency Programs 691.4 658.0 33.4 Taxes Other Than Income Taxes 940.4 910.6 29.8 Total Operating Expenses 9,511.4 10,091.1 (579.7) Operating Income 2,399.3 2,198.2 201.1 Interest Expense 855.4 678.3 177.1 Impairments of Offshore Wind Investments 2,167.0 — 2,167.0 Other Income, Net 348.1 346.1 2.0 (Loss)/Income Before Income Tax Expense (275.0) 1,866.0 (2,141.0) Income Tax Expense 159.7 453.6 (293.9) Net (Loss)/Income (434.7) 1,412.4 (1,847.1) Net Income Attributable to Noncontrolling Interests 7.5 7.5 — Net (Loss)/Income Attributable to Common Shareholders $ (442.2) $ 1,404.9 $ (1,847.1) Operating Revenues 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: Electric Firm Natural Gas Water Sales Volumes (GWh) Percentage Decrease Sales Volumes (MMcf) Percentage Decrease Sales Volumes (MG) Percentage Decrease 2023 2022 2023 2022 2023 2022 Traditional 7,590 7,764 (2.2) % — — — % 1,488 1,857 (19.9) % Decoupled 41,978 43,493 (3.5) % 142,328 152,291 (6.5) % 23,129 23,154 (0.1) % Total Sales Volumes 49,568 51,257 (3.3) % 142,328 152,291 (6.5) % 24,617 25,011 (1.6) % 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 2023, as compared to 2022, is as follows: (Millions of Dollars) Increase/(Decrease) Electric Distribution $ (431.8) Natural Gas Distribution 6.1 Electric Transmission 107.2 Water Distribution 10.0 Other 201.1 Eliminations (271.2) Total Operating Revenues $ (378.6) 50 Electric and Natural Gas Distribution Revenues : Base Distribution Revenues: • Base electric distribution revenues increased $36.6 million due primarily to a base distribution rate increase at NSTAR Electric effective January 1, 2023. • Base natural gas distribution revenues increased $18.5 million due primarily to base distribution rate increases effective November 1, 2023 and November 1, 2022 at NSTAR Gas and effective November 1, 2022 at EGMA. Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. 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. Costs recovered through cost tracking mechanisms include, among others, energy supply and natural gas supply procurement 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. 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 each 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 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 each 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. Tracked distribution revenues increased/(decreased) in 2023, as compared to 2022, due primarily to the following: (Millions of Dollars) Electric Distribution Natural Gas Distribution Retail Tariff Tracked Revenues: Energy supply procurement $ 506.4 $ (153.5) CL&P FMCC (330.1) — Retail transmission (80.9) — Energy efficiency 2.3 38.1 Other distribution tracking mechanisms (11.4) 36.7 Wholesale Market Sales Revenue (565.9) 65.9 The increase in energy supply procurement within electric distribution was driven by higher average prices, partially offset by lower average supply-related sales volumes. The decrease in energy supply procurement within natural gas distribution was driven by lower average prices and lower average supply-related sales volumes. Fluctuations in retail transmission revenues are driven by the recovery of the costs of our wholesale transmission business, such as those billed by ISO-NE and Local and Regional Network Service charges. For further information, see " Purchased Power, Purchased Natural Gas and Transmission " expense below. The decrease in CL&P’s FMCC revenues was driven by a decrease in the retail Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate, which reflects the impact of returning net benefits of higher wholesale market sales received in the ISO-NE market for long-term state approved energy contracts at CL&P, which are then credited back to customers through the retail NBFMCC rate. CL&P’s average NBFMCC rate in effect from January 1, 2022 through April 30, 2022 was $0.01423 per kWh and from May 1 through August 31, 2022 was $0.01251 per kWh. As a result of the CL&P RAM proceeding in Docket No. 22-01-03, CL&P reduced the average NBFMCC rate effective September 1, 2022 from $0.01251 per kWh to $0.00000 per kWh. As part of a November 2022 rate relief plan, CL&P further reduced the average NBFMCC rate effective January 1, 2023 to a credit of $0.01524 per kWh. These rate reductions returned to customers the net revenues generated by long-term state-approved energy contracts with the Millstone and Seabrook nuclear power plants. The average NBFMCC rate changed to $0.00000 per kWh effective July 1, 2023. As a result of the 2023 CL&P RAM decision, the average NBFMCC rate changed to $0.00293 per kWh effective September 1, 2023. The decrease in electric distribution wholesale market sales revenue was due primarily to lower average electricity market prices received for wholesale sales at CL&P, NSTAR Electric and PSNH. ISO-NE average market prices received for CL&P’s wholesale sales decreased to an average price of $36.60 per MWh in 2023, as compared to $82.88 per MWh in 2022, driven primarily by lower natural gas prices in New England. Volumes sold into the market were primarily from the sale of output generated by the Millstone PPA and Seabrook PPA that CL&P entered into in 2019, as required by regulation. CL&P sells the energy purchased from Millstone and Seabrook into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net sales or net cost amount is refunded to, or recovered from, customers in the non-bypassable component of the CL&P FMCC rate. 51 Electric Transmission Revenues : Electric transmission revenues increased $107.2 million due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure. 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 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. 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 2023, as compared to 2022, is due primarily to the following: (Millions of Dollars) Increase/(Decrease) Energy supply procurement costs $ 495.3 Other electric distribution costs (68.7) Natural gas supply costs (113.9) Transmission costs (87.1) Eliminations (71.5) Total Purchased Power, Purchased Natural Gas and Transmission $ 154.1 The variance in energy supply procurement costs is offset in Operating Revenues (tracked energy supply procurement revenues). The decrease in other electric distributions costs was primarily the result of a decrease in long-term renewable contract costs and lower net metering costs at NSTAR Electric, partially offset by higher long-term contractual energy-related costs at CL&P that are recovered in the non-bypassable component of the FMCC mechanism, and by higher net metering 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 lower average prices and lower average purchased supply volumes, partially offset by an increase in the retail cost deferral. The decrease in transmission costs was primarily the result of a decrease in the retail transmission cost deferral, which reflects the actual cost of transmission service compared to estimated amounts billed to customers and a decrease in costs billed by ISO-NE that support regional grid investments. These decreases were partially offset by an increase in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network. 52 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 2023, as compared to 2022, is due primarily to the following: (Millions of Dollars) Increase/(Decrease) Base Electric Distribution (Non-Tracked Costs): Shared corporate costs (including IT system depreciation at Eversource Service) $ 41.4 Storm costs 13.3 Uncollectible expense 5.1 General costs (including vendor services in corporate areas, insurance, fees and assessments) 4.7 Absence in 2023 of energy assistance program as part of CL&P rate relief plan (10.0) Employee-related expenses, including labor and benefits (9.2) Operations-related expenses (including vegetation management, vendor services and vehicles) (7.8) Total Base Electric Distribution (Non-Tracked Costs) 37.5 Tracked Electric Costs (Electric Distribution and Electric Transmission) - Increase due primarily to higher uncollectible expense and higher funding of NSTAR Electric storm reserve as part of January 1, 2023 rate change, partially offset by lower pension tracking mechanism at NSTAR Electric 44.7 Total Electric Distribution and Electric Transmission 82.2 Natural Gas Distribution: Base (Non-Tracked Costs) - Increase due primarily to higher uncollectible expense and shared corporate costs, partially offset by lower employee-related expenses 6.5 Tracked Costs (0.1) Total Natural Gas Distribution 6.4 Water Distribution 4.8 Parent and Other Companies and Eliminations: Eversource Parent and Other Companies - other operations and maintenance 158.8 Transaction and Transition Costs (17.8) Eliminations (204.0) Total Operations and Maintenance $ 30.4 Depreciation expense increased due primarily to higher net plant in service balances, partially offset by a decrease in approved depreciation rates as part of the rate case decision effective January 1, 2023 at NSTAR Electric. 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. Amortization decreased 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 decrease in the CL&P FMCC mechanism was driven primarily by the November 2022 rate relief plan, which reduced the non-bypassable FMCC rate effective January 1, 2023. The reduction in the CL&P non- bypassable FMCC retail rate decreased the regulatory over-recovery balance and created an under-recovery balance as of December 31, 2023, which resulted in a decrease to amortization expense of $802.3 million . The decrease was also driven by the impact of a new regulatory tracking mechanism at PSNH that allows for the recovery of 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. The decrease was partially offset by the amortization of historical exogenous property taxes that were approved for recovery effective January 1, 2023 at NSTAR Electric and effective November 1, 2022 at NSTAR Gas and EGMA, and an unfavorable regulatory adjustment resulting from NSTAR Gas’ GSEP reconciliation filing that resulted in an increase to amortization expense of $9.0 million recorded in 2023 . Energy Efficiency Programs expense increased due primarily to the deferral adjustment and the timing of the recovery of energy efficiency costs at NSTAR Gas and EGMA, partially offset by a decrease at NSTAR Electric. The deferral adjustment reflects the actual costs of energy efficiency programs compared to the amounts billed to customers. The costs for the majority of the state energy policy initiatives and expanded energy efficiency programs are recovered from customers in rates and have no impact on earnings. Taxes Other Than Income Taxes expense increased due primarily to higher employment-related taxes based on the timing of payroll pay periods, higher property taxes as a result of higher assessments and higher utility plant balances, and higher Connecticut gross earnings taxes. Interest Expense increased due primarily to an increase in interest on long-term debt as a result of new debt issuances ($200.3 million), an increase in interest on short-term notes payable ($43.8 million), higher amortization of debt discounts and premiums, net ($2.7 million), and an increase in interest expense on regulatory deferrals ($1.3 million), partially offset by an increase in capitalized AFUDC related to debt funds and other capitalized interest ($63.1 million), and a decrease in RRB interest expense ($1.3 million). 53 Impairments of Offshore Wind Investments relates to impairment charges in the second and fourth quarters of 2023 associated with Eversource’s offshore wind equity method investments resulting from the expected sale of the 50 percent interests in three jointly-owned offshore wind projects. See "Business Development and Capital Expenditures – Offshore Wind Business" included in this Management's Discussion and Analysis of Financial Condition and Results of Operations . Other Income, Net increased due primarily to an increase in interest income primarily from regulatory deferrals ($43.7 million) and an increase in capitalized AFUDC related to equity funds ($30.8 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($86.9 million), a loss on the disposition of land in 2023 compared to gains on the sales of property in 2022 ($9.0 million), a decrease in equity in earnings related to Eversource’s equity method investments ($7.4 million), and investment losses in 2023 compared to investment income in 2022 driven by market volatility ($6.8 million). Other Income, Net also increased due to 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. Income Tax Expense decreased due primarily to lower pre-tax earnings ($449.6 million), lower state taxes ($3.4 million), a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($7.4 million), an increase in amortization of EDIT ($2.4 million), and lower return to provision adjustments ($66.7 million), partially offset by lower share-based payment excess tax benefits ($2.6 million), and an increase in reserves ($233.0 million) primarily related to the impairment of Eversource’s offshore wind investment valuation allowance reserve of $224.0 million and $8.8 million relating to an uncertain tax position. RESULTS OF OPERATIONS – THE CONNECTICUT LIGHT AND POWER COMPANY NSTAR ELECTRIC COMPANY AND SUBSIDIARY PUBLIC SERVICE COMPANY OF NEW HAMPSHIRE AND SUBSIDIARIES 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, 2023 and 2022 included in this Annual Report on Form 10-K: For the Years Ended December 31, CL&P NSTAR Electric PSNH (Millions of Dollars) 2023 2022 Increase/ (Decrease) 2023 2022 Increase/ (Decrease) 2023 2022 Increase/ (Decrease) Operating Revenues $ 4,578.8 $ 4,817.7 $ (238.9) $ 3,515.5 $ 3,583.1 $ (67.6) $ 1,447.9 $ 1,474.8 $ (26.9) Operating Expenses: Purchased Power and Transmission 2,612.9 2,110.3 502.6 1,154.0 1,264.8 (110.8) 605.0 665.5 (60.5) Operations and Maintenance 733.3 707.2 26.1 668.5 640.8 27.7 284.4 256.0 28.4 Depreciation 376.9 355.5 21.4 372.6 362.0 10.6 140.4 128.0 12.4 Amortization of Regulatory (Liabilities)/Assets, Net (500.3) 335.6 (835.9) 16.1 83.9 (67.8) (16.3) 42.9 (59.2) Energy Efficiency Programs 133.5 134.2 (0.7) 325.6 332.3 (6.7) 39.6 37.4 2.2 Taxes Other Than Income Taxes 401.1 384.7 16.4 256.1 246.7 9.4 93.9 95.3 (1.4) Total Operating Expenses 3,757.4 4,027.5 (270.1) 2,792.9 2,930.5 (137.6) 1,147.0 1,225.1 (78.1) Operating Income 821.4 790.2 31.2 722.6 652.6 70.0 300.9 249.7 51.2 Interest Expense 193.4 169.4 24.0 189.2 162.9 26.3 72.8 59.5 13.3 Other Income, Net 61.6 83.3 (21.7) 164.1 142.7 21.4 26.6 32.7 (6.1) Income Before Income Tax Expense 689.6 704.1 (14.5) 697.5 632.4 65.1 254.7 222.9 31.8 Income Tax Expense 170.9 171.2 (0.3) 153.0 140.0 13.0 59.0 51.3 7.7 Net Income $ 518.7 $ 532.9 $ (14.2) $ 544.5 $ 492.4 $ 52.1 $ 195.7 $ 171.6 $ 24.1 Operating Revenues Sales Volumes: A summary of our retail electric GWh sales volumes is as follows: For the Years Ended December 31, 2023 2022 Decrease Percentage Decrease CL&P 19,577 20,560 (983) (4.8) % NSTAR Electric 22,401 22,933 (532) (2.3) % PSNH 7,590 7,764 (174) (2.2) % 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. 54 Operating Revenues: Operating Revenues, which consist of base distribution revenues and tracked revenues further described below, decreased $238.9 million at CL&P, $67.6 million at NSTAR Electric, and $26.9 million at PSNH in 2023, as compared to 2022. Base Distribution Revenues: • CL&P's distribution revenues were flat. • NSTAR Electric's distribution revenues increased $37.4 million due primarily to a base distribution rate increase effective January 1, 2023. • PSNH's distribution revenues decreased $0.8 million due primarily to a decrease in sales volumes as a result of milder weather in 2023 compared to 2022, partially offset by a base distribution rate increase effective August 1, 2022. Tracked Distribution Revenues: Tracked distribution revenues consist of certain costs that are recovered from customers in retail rates through regulatory commission-approved cost tracking mechanisms and therefore, recovery of these costs has no impact on earnings. 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. Costs recovered through cost tracking mechanisms include, among others, energy supply procurement 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. 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 each 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 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 2023, as compared to 2022, is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Retail Tariff Tracked Revenues: Energy supply procurement $ 442.8 $ 119.8 $ (56.2) CL&P FMCC (330.1) — — Retail transmission 40.4 (100.7) (20.6) Other distribution tracking mechanisms 22.0 (61.6) 30.5 Wholesale Market Sales Revenue (444.6) (83.2) (38.1) The increase in energy supply procurement at CL&P and NSTAR Electric was driven by higher average prices, partially offset by lower average supply-related sales volumes. The decrease in energy supply procurement at PSNH was driven by lower average supply-related sales volumes, partially offset by higher average prices. Fluctuations in retail transmission revenues are driven by the recovery of the costs of our wholesale transmission business, such as those billed by ISO-NE and Local and Regional Network Service charges. For further information, see " Purchased Power and Transmission " expense below. The decrease in CL&P’s FMCC revenues was driven by a decrease in the retail Non-Bypassable Federally Mandated Congestion Charge (NBFMCC) rate, which reflects the impact of returning net benefits of higher wholesale market sales received in the ISO-NE market for long-term state approved energy contracts at CL&P, which are then credited back to customers through the retail NBFMCC rate. CL&P’s average NBFMCC rate in effect from January 1, 2022 through April 30, 2022 was $0.01423 per kWh and from May 1 through August 31, 2022 was $0.01251 per kWh. As a result of the CL&P RAM proceeding in Docket No. 22-01-03, CL&P reduced the average NBFMCC rate effective September 1, 2022 from $0.01251 per kWh to $0.00000 per kWh. As part of a November 2022 rate relief plan, CL&P further reduced the average NBFMCC rate effective January 1, 2023 to a credit of $0.01524 per kWh. These rate reductions returned to customers the net revenues generated by long-term state-approved energy contracts with the Millstone and Seabrook nuclear power plants. The average NBFMCC rate changed to $0.00000 per kWh effective July 1, 2023. As a result of the 2023 CL&P RAM decision, the average NBFMCC rate changed to $0.00293 per kWh effective September 1, 2023. The decrease in wholesale market sales revenue was due primarily to lower average electricity market prices received for wholesale sales at CL&P, NSTAR Electric and PSNH. ISO-NE average market prices received for CL&P’s wholesale sales decreased to an average price of $36.60 per MWh in 2023, as compared to $82.88 per MWh in 2022, driven primarily by lower natural gas prices in New England. CL&P’s volumes sold into the market were primarily from the sale of output generated by the Millstone PPA and Seabrook PPA that CL&P entered into in 2019, as required by regulation. CL&P sells the energy purchased from Millstone and Seabrook into the wholesale market and uses the proceeds from the energy sales to offset the contract costs. The net sales or net cost amount is refunded to, or recovered from, customers in the non-bypassable component of the CL&P FMCC rate. Transmission Revenues: Transmission revenues increased $21.9 million at CL&P, $36.1 million at NSTAR Electric and $49.2 million at PSNH due primarily to a higher transmission rate base as a result of our continued investment in our transmission infrastructure. 55 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 increased revenues by $8.6 million at CL&P and $2.9 million at PSNH and decreased revenues by $18.2 million at NSTAR Electric. 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, 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 2023, as compared to 2022, is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Energy supply procurement costs $ 437.2 $ 117.6 $ (59.5) Other electric distribution costs 22.6 (109.6) 18.3 Transmission costs 35.7 (100.8) (22.0) Eliminations 7.1 (18.0) 2.7 Total Purchased Power and Transmission $ 502.6 $ (110.8) $ (60.5) 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 a decrease in long-term renewable contract costs and lower net metering costs, and at PSNH is due primarily to higher net metering 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 increase in transmission costs at CL&P was due primarily to an increase in Local Network Service charges, which reflect the cost of transmission service provided by Eversource over our local transmission network, and an increase resulting from the retail transmission cost deferral, which reflects the actual costs of transmission service compared to estimated amounts billed to customers. These increases were partially offset by a decrease in costs billed by ISO-NE that support regional grid investments. • The decrease in transmission costs at NSTAR Electric and PSNH was due primarily to a decrease resulting from the retail transmission cost deferral and a decrease in costs billed by ISO-NE. These decreases were partially offset by an increase in Local Network Service charges. 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 2023, as compared to 2022, is due primarily to the following: (Millions of Dollars) CL&P NSTAR Electric PSNH Base Electric Distribution (Non-Tracked Costs): Shared corporate costs (including IT system depreciation at Eversource Service) $ 14.2 $ 22.5 $ 4.7 Storm costs 17.4 (0.8) (3.3) General costs (including vendor services in corporate areas, insurance, fees and assessments) 6.6 0.2 (2.1) Absence in 2023 of energy assistance program as part of CL&P rate relief plan (10.0) — — Employee-related expenses, including labor and benefits (5.3) (5.2) 1.3 Operations-related expenses (including vegetation management, vendor services and vehicles) (4.7) 3.3 (6.4) Uncollectible expense (4.5) 4.5 5.1 Total Base Electric Distribution (Non-Tracked Costs) 13.7 24.5 (0.7) Total Tracked Costs 12.4 3.2 29.1 Total Operations and Maintenance $ 26.1 $ 27.7 $ 28.4 Depreciation expense increased for CL&P, NSTAR Electric and PSNH due to higher net plant in service balances. The increase at NSTAR Electric was partially offset by a decrease in approved depreciation rates as part of the rate case decision effective January 1, 2023. Amortization of Regulatory (Liabilities)/Assets, 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 (Liabilities)/Assets, Net is due primarily to the following: • The decrease 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 decrease in the FMCC mechanism was driven primarily by the CL&P November 2022 rate relief plan, which reduced the non-bypassable FMCC rate effective January 1, 2023. The reduction in the CL&P non- 56 bypassable FMCC retail rate decreased the regulatory over-recovery balance and created an under-recovery balance as of December 31, 2023, which resulted in a decrease to amortization expense of $802.3 million. • The decrease at NSTAR Electric was due to the deferral adjustment of energy-related costs and other tracked costs, partially offset by an increase due to the amortization of historical exogenous property taxes that were approved for recovery effective January 1, 2023 in the November 2022 NSTAR Electric distribution rate case decision. • The decrease at PSNH was due to the deferral adjustment of energy-related and other tracked costs, as well as the impact of a new regulatory tracking mechanism at PSNH that allows for the recovery of 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. The variance in Energy Efficiency Programs expense is due primarily to the following: • The decrease at NSTAR Electric was due to the deferral adjustment, which reflects the actual costs of energy efficiency programs compared to the amounts billed to customers, and the timing of the recovery of energy efficiency costs. • The increase at PSNH was due to the deferral adjustment and the timing of the recovery of energy efficiency costs. Taxes Other Than Income Taxes - the variance is due primarily to the following: • The increase at CL&P was related to higher Connecticut gross earnings taxes, higher employment-related taxes based on the timing of payroll pay periods, 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 assessments and higher utility plant balances and higher employment-related taxes based on the timing of payroll pay periods. • The decrease at PSNH was due to lower property taxes as a result of lower assessments accompanied by lower mill rates, partially offset by an increase due to higher employment-related taxes based on the timing of payroll pay periods. Interest Expense - the variance is due primarily to the following: • The increase at CL&P was due to higher interest on long-term debt ($23.2 million) and higher interest on short-term notes payable ($9.5 million), partially offset by a decrease in interest expense on regulatory deferrals ($4.6 million), an increase in capitalized AFUDC related to debt funds ($2.9 million), and lower amortization of debt discounts and premiums, net ($0.3 million). • The increase at NSTAR Electric was due primarily to higher interest on long-term debt ($16.0 million), higher interest on short-term notes payable ($10.1 million), and an increase in interest expense on regulatory deferrals ($8.0 million), partially offset by an increase in capitalized AFUDC related to debt funds ($6.5 million). • The increase at PSNH was due primarily to higher interest on long-term debt ($17.4 million) and higher interest on short-term notes payable ($5.4 million), partially offset by an increase in capitalized AFUDC related to debt funds ($4.7 million), a decrease in interest expense on regulatory deferrals ($3.7 million), and a decrease in RRB interest expense ($1.3 million). Other Income, Net - the variance is due primarily to the following: • The decrease at CL&P was due primarily to a decrease related to pension, SERP and PBOP non-service income components ($29.5 million) and an increase in investment losses driven by market volatility ($1.1 million), partially offset by an increase in capitalized AFUDC related to equity funds ($6.4 million) and an increase in interest income primarily on regulatory deferrals ($2.5 million). • The increase at NSTAR Electric was due primarily to an increase in interest income primarily on regulatory deferrals ($29.9 million) and an increase in capitalized AFUDC related to equity funds ($21.1 million), partially offset by a decrease related to pension, SERP and PBOP non-service income components ($28.1 million) and investment losses in 2023 compared to investment income in 2022 driven by market volatility ($1.4 million). • The decrease at PSNH was due primarily to a decrease related to pension, SERP and PBOP non-service income components ($10.6 million) and investment losses in 2023 compared to investment income in 2022 driven by market volatility ($0.9 million), partially offset by an increase in capitalized AFUDC related to equity funds ($2.9 million) and an increase in interest income primarily on regulatory deferrals ($2.2 million). Income Tax Expense - the variance is due primarily to the following: • The decrease at CL&P was due primarily to lower pre-tax earnings ($3.0 million), lower state taxes ($3.0 million), an increase in amortization of EDIT ($1.3 million), and a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.4 million), partially offset by higher return to provision adjustments ($7.3 million), lower share-based payment excess tax benefits ($0.9 million), and an increase in valuation allowances ($0.2 million). • The increase at NSTAR Electric was due primarily to higher pre-tax earnings ($13.7 million), higher state taxes ($1.6 million), lower share-based payment excess tax benefits ($1.0 million), and a decrease in amortization of EDIT ($0.8 million), partially offset by a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($4.1 million). 57 • The increase at PSNH was due primarily to higher pre-tax earnings ($6.7 million), higher state taxes ($1.6 million), and a decrease in amortization of EDIT ($0.9 million), partially offset by a decrease in items that impact our tax rate as a result of regulatory treatment (flow-through items) and permanent differences ($1.0 million), and lower return to provision adjustments ($0.5 million). EARNINGS SUMMARY CL&P's earnings decreased $14.2 million in 2023, as compared to 2022, due primarily to higher operations and maintenance expense, higher interest expense, higher depreciation expense, lower pension income, a higher effective tax rate, and higher property and other tax expense. The earnings decrease was partially offset by higher earnings from its capital tracking mechanism due to increased electric system improvements. NSTAR Electric's earnings increased $52.1 million in 2023, as compared to 2022, due primarily to higher revenues as a result of the base distribution rate increase effective January 1, 2023, an increase in transmission earnings driven by a higher transmission rate base, an increase in interest income primarily on regulatory deferrals, and higher AFUDC equity income. The earnings increase was partially offset by higher operations and maintenance expense, higher property and other tax expense, higher interest expense, and higher depreciation expense. PSNH's earnings increased $24.1 million in 2023, as compared to 2022, due primarily to an increase in transmission earnings driven by a higher transmission rate base and the impact of a new regulatory tracking mechanism at PSNH that allows for the recovery of previously incurred operating expenses associated with poles acquired on May 1, 2023. The earnings increase was partially offset by higher interest expense, higher depreciation expense, and lower pension income. LIQUIDITY Cash Flows: CL&P had cash flows provided by operating activities of $449.6 million in 2023, as compared to $869.6 million in 2022. The decrease in operating cash flows was due primarily to an increase in regulatory under-recoveries driven primarily by the timing of collections for the non-bypassable FMCC, the SBC and other regulatory tracking mechanisms, the timing of cash payments made on our accounts payable, and an $8.9 million increase in cost of removal expenditures. In 2023, CL&P increased the flow back to customers of net revenues generated by long-term state-approved energy contracts by providing these credits to customers through the non-bypassable FMCC retail rate. The reduction in the non-bypassable FMCC retail rate decreased the regulatory over-recovery balance and created an under-recovery balance as of December 31, 2023 , which resulted in a decrease to amortization expense of $802.3 million in 2023, as compared to 2022, and is presented as a cash outflow in Amortization of Regulatory (Liabilities)/Assets on the statement of cash flows. The impacts of regulatory collections are included in both Regulatory Recoveries and Amortization of Regulatory (Liabilities)/Assets on the statements of cash flows. These unfavorable impacts were partially offset by a $161.7 million increase in operating cash flows due to income tax refunds received in 2023 compared to income tax payments in 2022, the timing of cash collections on our accounts receivable, the absence in 2023 of $72.0 million of customer credits distributed in 2022 as a result of the October 2021 settlement agreement and the 2021 storm performance penalty for CL&P’s response to Tropical Storm Isaias, a $32.4 million decrease in cash payments to vendors for storm costs, and the timing of other working capital items. NSTAR Electric had cash flows provided by operating activities of $713.6 million in 2023, as compared to $771.5 million in 2022. The decrease in operating cash flows was due primarily to an increase in regulatory under-recoveries driven by the timing of collections for regulatory tracking mechanisms including transmission and net metering, the timing of other working capital items, the timing of cash collections on our accounts receivable, an $11.0 million increase in cost of removal expenditures, and a $7.5 million increase in income tax payments made. 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 the absence in 2023 of $76.3 million of payments in 2022 related to withheld property taxes, a $59.1 million decrease in cash payments to vendors for storm costs, the absence in 2023 of pension contributions of $15.0 million made in 2022, and the timing of cash payments made on our accounts payable. PSNH had cash flows provided by operating activities of $32.0 million in 2023, as compared to $361.5 million in 2022. The decrease in operating cash flows was due primarily to an increase in regulatory under-recoveries driven by the timing of collections for regulatory tracking mechanisms including energy supply, stranded costs, retail transmission and wholesale transmission, the timing of cash payments made on our accounts payable, a $118.2 million increase 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 of Regulatory (Liabilities)/Assets on the statements of cash flows. These unfavorable impacts were partially offset by a $118.2 million increase in operating cash flows due to income tax refunds received in 2023 compared to income tax payments in 2022, and the timing of cash collections on our accounts receivable. 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 . 58 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, 2023, 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, 2023, our regulated companies held collateral (letters of credit or cash) of $32.0 million from counterparties related to our standard service contracts. As of December 31, 2023, Eversource had $28.7 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. 59 Item 8. Financial Statements and Supplementary Data Eversource Management’s Report on Internal Controls Over Financial Reporting Reports of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) Consolidated Financial Statements CL&P Management’s Report on Internal Controls Over Financial Reporting Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) Financial Statements NSTAR Electric Management’s Report on Internal Controls Over Financial Reporting Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) Consolidated Financial Statements PSNH Management’s Report on Internal Controls Over Financial Reporting Report of Independent Registered Public Accounting Firm (PCAOB ID No. 34 ) Consolidated Financial Statements 60 Management’s Report on Internal Controls Over Financial Reporting Eversource Energy 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, 2023. February 14, 2024 61 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 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, 2023, 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, 2023, 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, 2023, of the Company and our report dated February 14, 2024, expressed an unqualified opinion on those financial statements. Basis for Opinion The Company’s management is responsible for maintaining effective internal control over financial reporting and for its assessment of the effectiveness of internal control over financial reporting, included in the accompanying 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. /s/ Deloitte & Touche LLP Hartford, Connecticut February 14, 2024 62 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 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, 2023 and 2022, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, 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, 2023, based on criteria established in Internal Control — Integrated Framework (2013) issued by the Committee of Sponsoring Organizations of the Treadway Commission and our report dated February 14, 2024, expressed an unqualified opinion on the Company’s internal control over financial reporting. Basis for Opinion 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 Matter 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 Critical Audit Matter Description The Company’s utility companies are subject to rate regulation by the Federal Energy Regulatory Commission and by their respective state public utility authorities in Connecticut, Massachusetts, or New Hampshire (the “Commissions”). The rate regulation by these Commissions is based on cost recovery. The regulated companies’ financial statements reflect the effects of the rate-making process. The rates charged to the customers of the Company’s regulated companies are designed to collect each company’s cost 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. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. The Company must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. The Company bases its 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. The Company uses 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 the Company’s financial statements. Management believes it is probable that each of the regulated companies will recover its respective investment in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to any of the regulated companies’ operations, or if management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made. 63 Accounting for the economics of rate-regulation impacts multiple financial statement line items and disclosures, such as regulated property, plant, and equipment, regulatory assets and liabilities, operating revenues, depreciation expense and amortization of regulatory assets. While management has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve full recovery of such costs or full recovery of all amounts invested in the utility business and a reasonable return on that investment. We identified the impact of rate-regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impact of future regulatory orders on the financial statements. Management judgments include assessing the probability of recovery in future rates of incurred costs and of a refund to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments requires specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities. How the Critical Audit Matter Was Addressed in the Audit 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 (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates, a refund, or a future reduction in rates. • 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 or of a future refund or reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We 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, refund, or future reductions in rates for regulatory assets and liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates. Investments in Unconsolidated Affiliates – Impact of Offshore Wind Impairment and Offshore Wind Divestiture - Refer to Note 6 to the Financial Statements Critical Audit Matter Description Eversource’s offshore wind business includes 50 percent ownership interests in each of North East Offshore and South Fork Class B Member, LLC, which collectively hold three offshore wind projects. North East Offshore holds the Revolution Wind project and the Sunrise Wind project. South Fork Class B Member, LLC holds the South Fork Wind project. Eversource’s offshore wind business also includes a noncontrolling tax equity investment in South Fork Wind through a 100 percent ownership in South Fork Wind Holdings, LLC Class A shares. The offshore wind projects are being developed and constructed through joint and equal partnerships with Ørsted. In the second quarter of 2023, the Company announced that it had completed the strategic review of its offshore wind investments and determined that it would continue to pursue the sale of its offshore wind investments. The Company also entered into a purchase and sale agreement with Ørsted for its 50% interest in an uncommitted lease area and committed to provide tax equity for the South Fork Wind project through a new tax equity ownership interest. In connection with the conclusion of the strategic review, Eversource evaluated its aggregate investment in the projects, uncommitted lease area, and other related capitalized costs and determined that the carrying value of the equity method offshore wind investment exceeded the fair value of the investment and that the decline was other-than-temporary. The estimate of fair value was based on the expected sale price of the Company’s 50 percent interest in the three contracted projects based on the most recent bid value, the sale price of the uncommitted lease area included in the purchase and sale agreement, expected investment tax credits and potential investment tax credit adder amounts, the value of the tax equity ownership interest, and the expectation of a successful repricing of the Sunrise Wind Offshore Renewable Energy Credit (“OREC”) contract. As a result, the Company recognized an other-than temporary impairment charge in the second quarter of 2023. In the fourth quarter of 2023, The New York State Public Service Commission denied Sunrise Wind’s petition to amend its OREC contract to increase the contract price to cover increased costs and inflation. Also during the fourth quarter, project construction forecasts were updated, and these new forecasts reflected additional expenditures for construction and scheduling related pressures, including the availability and increased cost of installation vessels and supply chain cost increases related to foundation fabrication. In determining the current fair value of the investments, these updated projections exceeded the previously estimated projections for construction expenditures, which resulted in a revised sales price that is now significantly lower than the previous bid value. Accordingly, the Company also recognized an other-than temporary impairment charge in the fourth quarter of 2023. We identified the evaluation of other-than-temporary impairment charge for the offshore wind investment as a critical audit matter. It involves 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 64 investment operations or the sale of the investment. This required a high degree of auditor judgment and an increased extent of effort when performing audit procedures to evaluate the reasonableness of management’s estimates and assumptions related to the price and the discount rate used in the discounted future cash flow method. How the Critical Audit Matter Was Addressed in the Audit Our audit procedures related to the discount rate used to determine fair market values and the estimates of discounted future cash flows expected from the sale of the investment. • We tested the effectiveness of management’s controls over impairment considerations including the aggregate investment in the projects, the sale price of the uncommitted lease area, and other related capitalized costs, as well as the discounted cash flow analysis for the offshore wind investments. We tested the effectiveness of management’s controls over the initial recognition of the impairment charge. • We evaluated the Company’s disclosures related to the impairment charges disclosed in the financial statements. • We evaluated the assumptions utilized within the discounted cash flow model used in the Company’s impairment analysis. • We made inquiries of management and evaluated the full impairment analysis from management that supported the other-than-temporary impairment charge in accordance with ASC 323-10-35-32A “Equity Method and Joint Ventures – Subsequent Measurement”. /s/ Deloitte & Touche LLP Hartford, Connecticut February 14, 2024 We have served as the Company’s auditor since 2002. 65 EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED BALANCE SHEETS As of December 31, (Thousands of Dollars) 2023 2022 ASSETS Current Assets: Cash $ 53,873 $ 47,597 Cash Equivalents — 327,006 Receivables, Net (net of allowance for uncollectible accounts of $ 554,455 and $ 486,297 as of December 31, 2023 and 2022, respectively) 1,431,531 1,517,138 Unbilled Revenues 225,325 238,968 Materials, Supplies, Natural Gas and REC Inventory 507,307 374,395 Regulatory Assets 1,674,196 1,335,491 Prepayments and Other Current Assets 355,762 382,603 Total Current Assets 4,247,994 4,223,198 Property, Plant and Equipment, Net 39,498,607 36,112,820 Deferred Debits and Other Assets: Regulatory Assets 4,714,970 4,242,794 Goodwill 4,532,100 4,522,632 Investments in Unconsolidated Affiliates 660,473 2,176,080 Prepaid Pension and PBOP 1,028,207 1,045,524 Marketable Securities 337,814 366,508 Other Long-Term Assets 592,080 541,344 Total Deferred Debits and Other Assets 11,865,644 12,894,882 Total Assets $ 55,612,245 $ 53,230,900 LIABILITIES AND CAPITALIZATION Current Liabilities: Notes Payable $ 1,930,422 $ 1,442,200 Long-Term Debt – Current Portion 824,847 1,320,129 Rate Reduction Bonds – Current Portion 43,210 43,210 Accounts Payable 1,869,187 2,113,905 Regulatory Liabilities 591,750 890,786 Other Current Liabilities 1,081,981 989,053 Total Current Liabilities 6,341,397 6,799,283 Deferred Credits and Other Liabilities: Accumulated Deferred Income Taxes 5,303,730 5,067,902 Regulatory Liabilities 4,022,923 3,930,305 Derivative Liabilities 67,999 143,929 Asset Retirement Obligations 505,844 502,713 Accrued Pension, SERP and PBOP 123,754 135,473 Other Long-Term Liabilities 961,239 888,081 Total Deferred Credits and Other Liabilities 10,985,489 10,668,403 Long-Term Debt 23,588,616 19,723,994 Rate Reduction Bonds 367,282 410,492 Noncontrolling Interest - Preferred Stock of Subsidiaries 155,569 155,570 Common Shareholders' Equity: Common Shares 1,799,920 1,799,920 Capital Surplus, Paid In 8,460,876 8,401,731 Retained Earnings 4,142,515 5,527,153 Accumulated Other Comprehensive Loss ( 33,737 ) ( 39,421 ) Treasury Stock ( 195,682 ) ( 216,225 ) Common Shareholders' Equity 14,173,892 15,473,158 Commitments and Contingencies (Note 13) Total Liabilities and Capitalization $ 55,612,245 $ 53,230,900 The accompanying notes are an integral part of these consolidated financial statements. 66 EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF (LOSS)/INCOME For the Years Ended December 31, (Thousands of Dollars, Except Share Information) 2023 2022 2021 Operating Revenues $ 11,910,705 $ 12,289,336 $ 9,863,085 Operating Expenses: Purchased Power, Purchased Natural Gas and Transmission 5,168,241 5,014,074 3,372,344 Operations and Maintenance 1,895,703 1,865,328 1,739,685 Depreciation 1,305,840 1,194,246 1,103,008 Amortization ( 490,117 ) 448,892 231,965 Energy Efficiency Programs 691,344 658,051 592,775 Taxes Other Than Income Taxes 940,359 910,591 829,987 Total Operating Expenses 9,511,370 10,091,182 7,869,764 Operating Income 2,399,335 2,198,154 1,993,321 Interest Expense 855,441 678,274 582,334 Impairments of Offshore Wind Investments 2,167,000 — — Other Income, Net 348,069 346,088 161,282 (Loss)/Income Before Income Tax Expense ( 275,037 ) 1,865,968 1,572,269 Income Tax Expense 159,684 453,574 344,223 Net (Loss)/Income ( 434,721 ) 1,412,394 1,228,046 Net Income Attributable to Noncontrolling Interests 7,519 7,519 7,519 Net (Loss)/Income Attributable to Common Shareholders $ ( 442,240 ) $ 1,404,875 $ 1,220,527 Basic (Loss)/Earnings Per Common Share $ ( 1.27 ) $ 4.05 $ 3.55 Diluted (Loss)/Earnings Per Common Share $ ( 1.26 ) $ 4.05 $ 3.54 Weighted Average Common Shares Outstanding: Basic 349,580,638 346,783,444 343,972,926 Diluted 349,840,481 347,246,768 344,631,056 The accompanying notes are an integral part of these consolidated financial statements. CONSOLIDATED STATEMENTS OF COMPREHENSIVE (LOSS)/INCOME For the Years Ended December 31, (Thousands of Dollars) 2023 2022 2021 Net (Loss)/Income $ ( 434,721 ) $ 1,412,394 $ 1,228,046 Other Comprehensive Income, Net of Tax: Qualified Cash Flow Hedging Instruments 20 20 972 Changes in Unrealized Gains/(Losses) on Marketable Securities 1,252 ( 1,636 ) ( 671 ) Changes in Funded Status of Pension, SERP and PBOP Benefit Plans 4,412 4,470 33,835 Other Comprehensive Income, Net of Tax 5,684 2,854 34,136 Comprehensive Income Attributable to Noncontrolling Interests ( 7,519 ) ( 7,519 ) ( 7,519 ) Comprehensive (Loss)/Income Attributable to Common Shareholders $ ( 436,556 ) $ 1,407,729 $ 1,254,663 The accompanying notes are an integral part of these consolidated financial statements. 67 EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF COMMON SHAREHOLDERS' EQUITY Common Shares Capital Surplus, Paid In Retained Earnings Accumulated Other Comprehensive Loss Treasury Stock Total Common Shareholders' Equity (Thousands of Dollars, Except Share Information) Shares Amount Balance as of January 1, 2021 342,954,023 $ 1,789,092 $ 8,015,663 $ 4,613,201 $ ( 76,411 ) $ ( 277,979 ) $ 14,063,566 Net Income 1,228,046 1,228,046 Dividends on Common Shares - $ 2.41 Per Share ( 828,337 ) ( 828,337 ) Dividends on Preferred Stock ( 7,519 ) ( 7,519 ) Long-Term Incentive Plan Activity 3,537 3,537 Issuance of Treasury Shares 986,656 49,913 18,451 68,364 Issuance of Treasury Shares for Acquisition of New England Service Company 462,517 29,401 8,650 38,051 Other Comprehensive Income 34,136 34,136 Balance as of December 31, 2021 344,403,196 1,789,092 8,098,514 5,005,391 ( 42,275 ) ( 250,878 ) 14,599,844 Net Income 1,412,394 1,412,394 Dividends on Common Shares - $ 2.55 Per Share ( 883,113 ) ( 883,113 ) Dividends on Preferred Stock ( 7,519 ) ( 7,519 ) Issuance of Common Shares - $ 5 par value 2,165,671 10,828 189,077 199,905 Long-Term Incentive Plan Activity 8,335 8,335 Issuance of Treasury Shares 949,724 53,822 17,350 71,172 Capital Stock Expense ( 2,847 ) ( 2,847 ) Issuance of Treasury Shares for Acquisition of The Torrington Water Company 925,264 54,830 17,303 72,133 Other Comprehensive Income 2,854 2,854 Balance as of December 31, 2022 348,443,855 1,799,920 8,401,731 5,527,153 ( 39,421 ) ( 216,225 ) 15,473,158 Net Loss ( 434,721 ) ( 434,721 ) Dividends on Common Shares - $ 2.70 Per Share ( 942,398 ) ( 942,398 ) Dividends on Preferred Stock ( 7,519 ) ( 7,519 ) Long-Term Incentive Plan Activity 1,375 1,375 Issuance of Treasury Shares 1,096,411 57,770 20,543 78,313 Other Comprehensive Income 5,684 5,684 Balance as of December 31, 2023 349,540,266 $ 1,799,920 $ 8,460,876 $ 4,142,515 $ ( 33,737 ) $ ( 195,682 ) $ 14,173,892 The accompanying notes are an integral part of these consolidated financial statements. 68 EVERSOURCE ENERGY AND SUBSIDIARIES CONSOLIDATED STATEMENTS OF CASH FLOWS For the Years Ended December 31, (Thousands of Dollars) 2023 2022 2021 Operating Activities: Net (Loss)/Income $ ( 434,721 ) $ 1,412,394 $ 1,228,046 Adjustments to Reconcile Net (Loss)/Income to Net Cash Flows Provided by Operating Activities: Depreciation 1,305,840 1,194,246 1,103,008 Deferred Income Taxes 85,405 346,779 347,056 Uncollectible Expense 72,468 61,876 60,886 Pension, SERP and PBOP Income, Net ( 90,706 ) ( 160,857 ) ( 14,693 ) Pension and PBOP Contributions ( 6,860 ) ( 83,148 ) ( 182,344 ) Regulatory Under Recoveries, Net ( 151,548 ) ( 205,294 ) ( 314,211 ) (Customer Credits)/Reserve at CL&P related to PURA Settlement Agreement and Storm Performance Penalty — ( 72,041 ) 81,274 Amortization ( 490,117 ) 448,892 231,965 Cost of Removal Expenditures ( 315,699 ) ( 303,755 ) ( 242,130 ) Payment in 2022 of Withheld Property Taxes — ( 78,446 ) — Impairments of Offshore Wind Investments 2,167,000 — — Other ( 53,026 ) ( 39,192 ) ( 64,640 ) Changes in Current Assets and Liabilities: Receivables and Unbilled Revenues, Net ( 124,393 ) ( 470,593 ) ( 135,505 ) Taxes Receivable/Accrued, Net 36,357 18,358 ( 110,621 ) Accounts Payable ( 287,637 ) 377,657 ( 29,201 ) Other Current Assets and Liabilities, Net ( 66,202 ) ( 45,583 ) 3,710 Net Cash Flows Provided by Operating Activities 1,646,161 2,401,293 1,962,600 Investing Activities: Investments in Property, Plant and Equipment ( 4,336,849 ) ( 3,441,852 ) ( 3,175,080 ) Proceeds from Sales of Marketable Securities 395,604 457,612 447,893 Purchases of Marketable Securities ( 336,779 ) ( 424,174 ) ( 414,980 ) Investments in Unconsolidated Affiliates ( 1,680,473 ) ( 742,496 ) ( 327,385 ) Proceeds from Unconsolidated Affiliates 1,090,662 — — Other Investing Activities ( 2,897 ) 20,420 22,178 Net Cash Flows Used in Investing Activities ( 4,870,732 ) ( 4,130,490 ) ( 3,447,374 ) Financing Activities: Issuance of Common Shares, Net of Issuance Costs — 197,058 — Cash Dividends on Common Shares ( 918,995 ) ( 860,033 ) ( 805,439 ) Cash Dividends on Preferred Stock ( 7,519 ) ( 7,519 ) ( 7,519 ) Increase/(Decrease) in Notes Payable 695,552 ( 78,170 ) 256,125 Repayment of Rate Reduction Bonds ( 43,210 ) ( 43,210 ) ( 43,210 ) Issuance of Long-Term Debt 5,198,345 4,045,000 3,230,000 Retirement of Long-Term Debt ( 2,008,470 ) ( 1,175,000 ) ( 1,142,500 ) Other Financing Activities ( 46,466 ) ( 48,185 ) ( 46,625 ) Net Cash Flows Provided by Financing Activities 2,869,237 2,029,941 1,440,832 Net (Decrease)/Increase in Cash, Cash Equivalents and Restricted Cash ( 355,334 ) 300,744 ( 43,942 ) Cash, Cash Equivalents and Restricted Cash - Beginning of Year 521,752 221,008 264,950 Cash, Cash Equivalents and Restricted Cash - End of Year $ 166,418 $ 521,752 $ 221,008 The accompanying notes are an integral part of these consolidated financial statements. 69 Management’s Report on Internal Controls Over Financial Reporting The Connecticut Light and Power Company 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, 2023. February 14, 2024 70 REPORT OF INDEPENDENT REGISTERED PUBLIC ACCOUNTING FIRM 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, 2023 and 2022, 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, 2023, 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, 2023 and 2022, and the results of its operations and its cash flows for each of the three years in the period ended December 31, 2023, in conformity with accounting principles generally accepted in the United States of America. Basis for Opinion 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 Critical Audit Matter Description The Company is subject to rate regulation by the Federal Energy Regulatory Commission and the state public utility authority in Connecticut (the “Commissions”). The rate regulation by these Commissions is based on cost recovery. The Company’s financial statements reflect the effects of the rate-making process. The rates charged to the customers are designed to collect the Company’s cost 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. In some cases, the Company records regulatory assets before approval for recovery has been received from the applicable regulatory commission. The Company must use judgment to conclude that costs deferred as regulatory assets are probable of future recovery. The Company bases its 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. The Company uses 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 the Company’s financial statements. Management believes it is probable that the Company will recover its investment in long-lived assets, including regulatory assets. If management were to determine that it could no longer apply the accounting guidance applicable to rate-regulated enterprises to the Company’s operations, or if management could not conclude it is probable that costs would be recovered from customers in future rates, the costs would be charged to net income in the period in which the determination is made. 71 Accounting for the economics of rate-regulation impacts multiple financial statement line items and disclosures, such as regulated property, plant, and equipment, regulatory assets and liabilities, operating revenues, depreciation expense and amortization of regulatory assets. While management has indicated it expects to recover costs from customers through regulated rates, there is a risk that the Commissions will not approve full recovery of such costs or full recovery of all amounts invested in the Company and a reasonable return on that investment. We identified the impact of rate-regulation as a critical audit matter due to the significant judgments made by management to support its assertions about impact of future regulatory orders on the financial statements. Management judgments include assessing the probability of recovery in future rates of incurred costs and of a refund to customers. Given that management’s accounting judgments are based on assumptions about the outcome of future decisions by the Commissions, auditing these judgments requires specialized knowledge of accounting for rate regulation and the rate setting process due to its inherent complexities. How the Critical Audit Matter Was Addressed in the Audit 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 (1) the recovery in future rates of costs incurred as property, plant, and equipment and deferred as regulatory assets, and (2) a refund or a future reduction in rates that should be reported as regulatory liabilities. We tested the effectiveness of management’s controls over the initial recognition of amounts as property, plant, and equipment; regulatory assets or liabilities; and the monitoring and evaluation of regulatory developments that may affect the likelihood of recovering costs in future rates, a refund, or a future reduction in rates. • 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 or of a future refund or reduction in rates based on precedents of the Commissions’ treatment of similar costs under similar circumstances. We 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, refund, or future reductions in rates for regulatory assets and liabilities to assess management’s assertion that amounts are probable of recovery, refund, or a future reduction in rates. /s/ Deloitte & Touche LLP Hartford, Connecticut February 14, 2024 We have served as the Company’s auditor since 2002. 72 THE CONNECTICUT LIGHT AND POWER COMPANY BALANCE SHEETS As of December 31, (Thousands of Dollars) 2023 2022 ASSETS Current Assets: Cash $ 10,213 $ 11,312 Receivables, Net (net of allowance for uncollectible accounts of $ 296,030 and $ 225,320 as of December 31, 2023 and 2022, respectively) 558,993 612,052 Accounts Receivable from Affiliated Companies 60,450 46,439 Unbilled Revenues 57,403 59,363 Materials, Supplies and REC Inventory 156,467 88,157 Taxes Receivable 41,253 65,785 Regulatory Assets 480,369 314,089 Prepayments and Other Current Assets 53,536 62,524 Total Current Assets 1,418,684 1,259,721 Property, Plant and Equipment, Net 12,340,192 11,467,024 Deferred Debits and Other Assets: Regulatory Assets 1,662,778 1,593,693 Prepaid Pension and PBOP 129,801 147,914 Other Long-Term Assets 298,169 290,444 Total Deferred Debits and Other Assets 2,090,748 2,032,051 Total Assets $ 15,849,624 $ 14,758,796 LIABILITIES AND CAPITALIZATION Current Liabilities: Notes Payable to Eversource Parent $ 249,670 $ — Accounts Payable 622,055 710,500 Accounts Payable to Affiliated Companies 134,726 136,277 Obligations to Third Party Suppliers 75,753 40,704 Regulatory Liabilities 102,239 336,048 Derivative Liabilities 81,944 81,588 Other Current Liabilities 127,703 123,171 Total Current Liabilities 1,394,090 1,428,288 Deferred Credits and Other Liabilities: Accumulated Deferred Income Taxes 1,860,122 1,640,034 Regulatory Liabilities 1,315,928 1,263,396 Derivative Liabilities 67,999 143,929 Other Long-Term Liabilities 190,186 166,081 Total Deferred Credits and Other Liabilities 3,434,235 3,213,440 Long-Term Debt 4,814,429 4,216,488 Preferred Stock Not Subject to Mandatory Redemption 116,200 116,200 Common Stockholder's Equity: Common Stock 60,352 60,352 Capital Surplus, Paid In 3,384,265 3,260,765 Retained Earnings 2,645,868 2,463,094 Accumulated Other Comprehensive Income 185 169 Common Stockholder's Equity 6,090,670 5,784,380 Commitments and Contingencies (Note 13) Total Liabilities and Capitalization $ 15,849,624 $ 14,758,796 The accompanying notes are an integral part of these financial statements. 73 THE CONNECTICUT LIGHT AND POWER COMPANY STATEMENTS OF INCOME For the Years Ended December 31, (Thousands of Dollars) 2023 2022 2021 Operating Revenues $ 4,578,804 $ 4,817,744 $ 3,637,412 Operating Expenses: Purchased Power and Transmission 2,612,949 2,110,253 1,392,969 Operations and Maintenance 733,287 707,162 644,175 Depreciation 376,904 355,511 338,915 Amortization of Regulatory (Liabilities)/Assets, Net ( 500,367 ) 335,636 99,009 Energy Efficiency Programs 133,453 134,222 129,564 Taxes Other Than Income Taxes 401,135 384,746 363,862 Total Operating Expenses 3,757,361 4,027,530 2,968,494 Operating Income 821,443 790,214 668,918 Interest Expense 193,361 169,348 166,107 Other Income, Net 61,560 83,252 30,187 Income Before Income Tax Expense 689,642 704,118 532,998 Income Tax Expense 170,909 171,198 131,273 Net Income $ 518,733 $ 532,920 $ 401,725 The accompanying notes are an integral part of these financial statements. STATEMENTS OF COMPREHENSIVE INCOME For the Years Ended December 31, (Thousands of Dollars) 2023 2022 2021 Net